&EPA
United States
Environmental Protection
Agency
Office of Mobile Source Air Pollution Control
Emission Control Technology Division
2565 Plymouth Road
Ann Arbor, Michigan 48105
Air
EPA 460/3-84-012
April 1986
Costs To Convert Coal To
Methanol
-------
EPA 460/3-84-012
Costs To Convert Coal To Methanol
by
David S. Moulton and Norman R. Sefer
Southwest Research Institute
6220 Culebra Road
San Antonio, Texas 78284
Contract No. 68-03-3162
Work Assignment No. 9
EPA Project Officers: Robert J. Garbe and Craig A. Harvey
EPA Branch Technical Representative: Thomas M. Baines
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Mobile Source Air Pollution Control
Emission Control Technology Division
2565 Plymouth Road
Ann Arbor, Michigan 48105
April 1986
-------
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 - in
limited quantities - from the Library Services Office, Environmental Protection
Agency, 2565 Plymouth Road, Ann Arbor, Michigan 4.8105.
This report was furnished to the Environmental Protection Agency by Southwest
Research Institute, 6220 Culebra Road, San Antonio, Texas, in fulfillment of Work
Assignment 9 of Contract No. 68-03-3162. The contents of this report are reproduced
herein as received from Southwest Research Institute. The opinions, findings, and
conclusions expressed are those of the author and not necessarily those of the
Environmental Protection Agency. Mention of company or product names is not to be
considered as an endorsement by the Environmental Protection Agency.
n
-------
FOREWORD
This Work Assignment was initiated by the Emission Control Technology
Division, Environmental Protection Agency, 2565 Plymouth Road, Ann Arbor, Michigan
48105. The effort on which this report is based was accomplished by the Department
of Emissions Research and the Department of Energy Conversion and Combustion
Technology of Southwest Research Institute, 6220 Culebra Road, San Antonio, Texas
78284. This program, authorized by Work Assignment 9 under Contract 68-03-3162,
was initiated August 18, 1983 and was completed September 28, 1984. The program
was identified within Southwest Research Institute as Project 03-7338-000.
This Work Assignment was conducted by Mr. David S. Moulton, Research
Engineer and Mr. Norman R. Sefer, Senior Research Engineer. Mr. Chares Hare was
Project Manager and was involved in the initial technical and fiscal negotiations and
subsequent major program decisions. The EPA Project Officers were Messrs. Robert
1. Garbe and Craig A. Harvey of the Technical Support Staff, Environmental
Protection Agency.
in
-------
ABSTRACT
This report provides estimated costs of producing methanol transportation fuei
from coal. Estimates were made for mine-mouth plants in five different coal
producing regions, and uniform methods were used so the estimated sales prices could
be compared for market analysis. In addition to plant-gate prices, delivered prices
were estimated for three major market areas. With presently available
transportation, the lowest delivered prices were for methanol production based in the
southern lignite coal region. If new methanol-compatible pipelines were to be
constructed, the lowest delivered prices would be for production based in the western
subbituminous coal region. In the western subbituminous region, limited water
resources would make extensive planning and careful site selection necessary, but they
would not prevent the development of a coal-to-methanol industry. By-product
carbon dioxide sales for enhanced oil recovery could reduce the required plant-gate
methanol price in some areas near oil fields amenable to carbon dioxide injection
techniques.
IV
-------
TABLE OF CONTENTS
Page
FOREWORD iii
ABSTRACT iv
LIST OF ILLUSTRATIONS vi
LIST OF TABLES vii
I. SUMMARY 1
II. INTRODUCTION 4
III. PROCESS DESCRIPTION 7
Gasification 7
Gas Preparation 10
Methanol Synthesis 11
Coal Properties and Material Balances 12
IV. PLANT-GATE COSTS 21
Capital Expenditures 21
Operating Costs 29
Credit for By-Products 36
Economic Assumptions 38
Siting Limitations 42
Eastern Low-Sulfur Coal 45
Methanol Cost Distribution 46
V. TRANSPORTATION COSTS AND DELIVERED PRICES 49
Existing Product Pipelines 49
Water and Rail Transportation 50
New Pipeline Construction 51
Delivered Prices 53
Future Prices 59
VI. CONCLUSIONS 61
REFERENCES 63
APPENDICES
A. Program for Calculating Sales Price and Return on Investment
B. Example Computer Output for one Complete Price Calculation
C. Telephone Quotes for Costs of Water and Rail Transportation
D. Report on Pipeline Economic Factors
v
-------
LIST OF FIGURES
Page
1. Flow Chart of Coal-to-Methanol Process Scheme 8
2. Coal-to-Methanol Plant Organization Chart 34
3. Cost Distribution for Methanol Production in the Midwestern
High-Sulfur Region 47
4. Cost Distribution for Methanol Production in the Western Subbituminous
Coal Region 48
5. Cost Distribution for Methanol Production in the Western Subbituminous
Coal Region, Assuming No Credit for Carbon Dioxide Sales 48
6. Map Showing Projected Methanol Producing Regions and
Representative Consuming Locations With Their Associated Areas 54
VI
-------
LIST OF TABLES
Table
1. Characteristics of Some Commercial and Near Commercial
Coal Gasifiers 9
2. Characteristics of Some Methanol Synthesis Processes 13
3. Properties of Coals 14
4. Material Balances for Gasifier 15
5. Material Balances for Shift Reactor and COS Hydrolyzer,
Feed Streams 16
6. Material Balances for Shift Reactor and COS Hydrolyzer,
Product Streams 17
7. Material Balances for Acid Gas Removal and Guard Bed Gas
Conditioning Processes, Feed Streams 18
8. Material Balances for Acid Gas Removal and Guard Bed Gas
Conditioning Processes, Product Streams 19
9. Material Balances for Methanol Synthesis Reactor, All Coals 20
10. Factors in Cost Estimation Relationship 22
11. Capital Expenditures for Major Process Modules • • • 23
12. Capital Expenditures for Offsites 25
13. Initial Catalyst and Chemical Inventory Cost 26
14. Capital Expenditures for Royalties 27
15. Factors for Estimating Effects of State Use Tax 27
16. Capital Cost Summaries 28
17. Coal Cost Forecasts 30
18. Total Coal Consumption 31
19. Water Costs 31
20. Water Consumption 32
21. Annual Catalyst and Chemical Costs 32
22. Estimated Labor Rates 33
23. Annual Operating Labor Costs 35
24. Annual Maintenance Costs 35
25. Annual Insurance and Local Tax Costs 36
26. Estimated Prices for Crude Bright Sulfur • • • • 36
27. Total Carbon Dioxide Demand 37
28. Carbon Dioxide Prices and Expected Sales 38
29. Plant-Gate Methanol Prices 41
vii
-------
LIST OF TABLES (Cont'd)
Table Page
30. Effect of Variables on Price of Methanol in the Western
Subbituminous Region ............................................... 44
31. Effect of Carbon Dioxide Sales Credits on the Methanol Price
in the Southern Lignite Region ........................................ 44
32. Estimated Costs of Methanol Transportation Using Readily Available Means • 50
33. Estimated Costs of Methanol Transportation in Newly Constructed
Pipelines, Dollars per Thousand Barrel Miles ............................. 52
34. Estimated Costs of Methanol Transportation in Newly Constructed
Pipelines [[[ 52
35. Delivered Methanol Prices Using Readily Available Means of
Transportation [[[ 55
36. Delivered Methanol Prices Using Newly Constructed Pipeline
Transportation [[[ 56
37. Delivered Methanol Prices Using Newly Constructed Pipeline Transportation
Western Development Restricted by Water Availability .................. 57
38. Delivered Methanol Prices Using Best Estimate of Water Availability
Readily Available Transportation, and No CO2 Sales Credit,
$/Gallon [[[ 58
39. Delivered Methanol Prices Using Best Estimate of Water Availability,
Newly Constructed Pipeline Transportation, and No CO2 Sales Credit
-------
I. SUMMARY
Methanol has received considerable attention as a possible future transportation
fuel because it can be used in properly designed vehicles, and large amounts could be
produced from domestic coal reserves. Coal is mined in many different locations, and
the properties of the coal differ from place to place. Mining costs, water availability,
climate, and taxes also vary, and as a result, the cost of producing methanol from coal
should differ significantly from place to place. In addition, the availability and cost
of transportation could make a significant impact on delivered methanol prices. The
objective of this study was to use uniform methods to estimate the cost of producing
methanol at different coal fields so the estimated sales prices could be compared for
market analysis. A rapidly growing market for methanol as a transportation fuel was
assumed.
The production of methanol fronn coal requires three major steps: coal
gasification, gas conditioning, and methanol synthesis. Several individual processes
are involved in each step and an overall processing scheme was developed for this
study by putting together individual processes. Process selections included the Texaco
gasification process, the selective SELEXOL® process for acid-gas removal, and the
Imperial Chemical Industries (ICI) process for methanol synthesis. The following
criteria were used for process selection.
o Commercially available or very close
o Usable on a wide variety of feedstocks
o Economic
o Environmentally sound
o Reliable, low anticipated down time
Methanol prices were estimated for production based on five types of coal,
representing five different coal-producing regions. They were eastern high-sulfur
bituminous, midwestern high-sulfur bituminous, western subbituminous, southern
lignite, and northern lignite coals. Material balances were developed for the major
processes based on each coal's characteristics and the process requirements. Then
groups of processing equipment, termed 'process modules', were sized based on their
throughput. Capital and operating costs were estimated for mine-mouth plants in each
of the five producing regions, and credits were taken for by-products where feasible.
-------
Required plant-gate selling prices were calculated for each plant assuming four
different discounted-cash-flow rates of return on investment ranging from 10 to 25%.
The lowest plant-gate methanol prices were for production based in the western
subbituminous region and in the southern lignite region. In those regions, the price
was about $0.52 to $0.58 per gallon, depending on coal prices, for 15% rate of return
on investment. Prices in the northern lignite region were about $0.69 to $0.73 per
gallon. Prices for the plants using the high-sulfur coal in the eastern and midwestern
regions were $0.79 and $0.86 per gallon, respectively. By-product credits for sales of
carbon dioxide for use in enhanced oil recovery were found to have a significant effect
on the methanol price. For example, without by-product sales the methanol price for
production based in the southern lignite region would be $0.71 per gallon, rather than
$0.55 per gallon with by-product sales credits. Both prices were calculated assuming
a 15% rate of return on investment. The prices are based on 1984 dollars. Prices
based on 1990 dollars can be obtained by using a 1.328 multiplier on the 1984 dollar
prices.
Transportation costs were estimated for moving the methanol from the
producing regions to major market areas. Chicago, New York City, and Atlanta were
studied as typical market locations. Transportation costs were estimated using two
different assumptions: transportation by the least-cost method or combination of
methods available in 1984, and transportation by hypothetical, newly-constructed
pipelines. The right of eminent domain was assumed for the new pipeline
construction. Transportation costs were estimated for the presently available
methods based on telephone quotes, and were calculated for newly constructed
pipelines using capital and operating cost figures supplied by a pipeline engineering
company.
Plant-gate prices and transportation costs were used to determine delivered
prices. With presently available transportation, the lowest delivered prices were for
production based in the southern lignite region. With newly constructed pipelines, the
lowest delivered prices were for production based in the western subbituminous region.
Three locations would gain a major benefit from newly constructed pipelines: the
western subbituminous and northern lignite producing regions, and the Atlanta market
area.
-------
Water availability could be a major restriction on industrial development in arid
western regions. An analysis of water costs and availability in this study indicated
that with adequate planning and careful site selection, water availability would not
prevent the development of a coal-to-methanol industry in the western subbituminous
region. Also, a large increase in water cost would make only a slight difference in
methanol price. Neither water availability nor other siting limitations were
significant problems in any of the other producing regions.
Some of the issues which would affect the delivered methanol prices merit
further study. These include the effects of water availability and credits for CO2
sales which are presented as case studies toward the end of the report. These issues
are very site and time-specific. For a particular plant location, a thorough analysis of
water availability will be required, particularly in the west, as part of the construction
planning and permitting procedures. This will involve the acquistion of additional data
and extensive review of federal, state, and local planning activities. Similarly, prior
to construction of a plant, a thorough market analysis for CO2 sales including CO2
transportation, and technical and economic analyses for its use in individual oil fields
should be made. These issues were studied in this report from a general viewpoint and
the sensitivity factors are indicative of potential rather than specific results.
-------
II. INTRODUCTION
Methanol may become a major transportation fuel. It can be made from any of
several concentrated sources of carbon including conventional hydrocarbon fuels, coal,
peat and biomass. The technical problems associated with the use of rnethanol as a
transportation fuel are being widely investigated and it may become a practical fuel
for properly designed vehicles. The problems do not appear to be insoluble; no major
breakthroughs are required. Because rnethanol can be made from coal, it could
become an attractive domestic alternative to petroleum-derived vehicle fuels. The
energy content of our domestic coal reserve is about 100 times as great as our
petroleum reserves. The use of our coal reserves to provide methanol vehicle fuel
could significantly increase our energy security.
The huge deposits of coal in this country contain several different types of coal.
A number of factors which affect methanol production costs are known to vary widely
among these coal deposits. These include compositional factors such as sulfur,
moisture, and ash contents, and geological factors relating to ease and costs of mining.
The availability of water for industrial use is a major issue in arid regions, and markets
for by-products differ from place to place. Less important variables include the
effects of climate on building costs and differences in state and local taxes.
The delivered costs of methanol are further affected by transportation variables.
Some areas with factors favoring low production costs, such as the western low-sulfur
coal fields, have no access to inexpensive water transportation and only a very limited
local market because of the low population density. Other areas are served by
extensive networks of existing product pipelines, but they may not be available for
methanol shipment because of high demand for shipping other products, and questions
of materials compatability. Newly constructed pipelines built specifically to allow
methanol shipments need to be considered for the development of a large-scale
methanol fuel industry.
A number of previous studies have been made to determine coal-to-methanol
production costs. These have generally been made for specific sites using particular
processes and financial assumptions. Each study has had a somewhat different basis,
thus it has been difficult to compare the effects on delivered price that would result
from locating plants in different parts of the country utilizing locally obtained coal in
-------
each plant. The objective of this study is to use uniform methods to estimate the cost
of producing methanol at different coal fields. Making estimates on the same basis
provides sales prices which can be compared among the different regions for market
analysis.
Factored estimate methods based on publicly available studies were used to
obtain capital and operating costs. Particular attention was paid to items which were
variable by region. The capital and operating costs were used to calculate required
selling price for several rates of return on investment. Resources did not allow
detailed engineering design and optimization, or construction specifications. However,
the methods employed do allow reasonable estimates for delivered methanol costs, and
the variations can be assigned to differences among producing regions. Transportation
costs were estimated and the delivered prices were used to project development of
the coal-to-methanol industry in various coal producing regions, assuming the industry
would grow rapidly.
Five types of coal were considered in this study. These were eastern high-sulfur
bituminous, midwestern high-sulfur bituminous, western low-sulfur subbituminous,
northern lignite and southern lignite. A composition was chosen for each coal
generally representative of actual coal samples of the type and locality. The eastern
and midwestern coal compositions were intended to represent high-sulfur resources
with little chance for utilization in direct combustion, due to increasingly stringent
controls on sulfur emissions.
The coal compositions were used to develop material balances for major process
modules which were then sized by throughput. Cost estimates were made using
literature values for similar process modules, adjusted for inflation and throughput.
Off sites, which include land, utilities, administrative buildings, piping, roads, and other
improvements which are not a direct part of the production process, were estimated
based on process requirements and projected plant employment. Building costs were
estimated on a square foot basis utilizing the experience of Southwest Research
Institute architects. Operating costs were based on literature values, publicly
available statistics, and raw material price forecasts made by SwRI.
Costs of product transportation were estimated using similar procedures.
Transportation costs for existing transportation methods were derived from quotes
obtained by telephone from several carriers. Costs for newly constructed pipelines
-------
were calculated from capital and operating cost estimates for several rates of return
on investment. Raw data were supplied by a major pipeline engineering firm which
provided consultant services for this part of the project. Both the plant-gate
methanol prices and the new pipeline transportation costs were calculated to obtain
the required rates of return using the discounted cash flow method.
Siting limitations and by-product sales credits were studied from a general
viewpoint. Water availability in the western subbituminous region was the only major
siting limitation found. Credits for CO2 sales for use in enhanced oil recovery were
found to have a major effect on the required methanol sales price. Both factors were
very site and time-specific and would merit much further study for an individual plant.
In addition, the technology for using CC>2 in enhanced oil recovery was developing
rapidly and some changes in the potential market were expected. The potential
effects that water availability and CC>2 credits could have on the required methanol
sales price were presented as case studies.
Plant locations were projected based on lowest delivered cost. Three cities,
New York City, Chicago, and Atlanta, representing three major regions of the country,
were used for delivery locations. It was assumed that production would rise rapidly to
100 x 10^ gal/day and that this total would be apportioned among the three regions in
the same ratio as recent gasoline sales.
-------
III. PROCESS DESCRIPTION
The overall processing scheme is shown in Figure 1. The main unit operations,
and flow directions for the principal materials and utilities are included. Several
criteria were used to select the individual processes:
o Commercially available or very close
o Usable on a wide variety of feed stocks
o Economic
o Environmentally sound
o Reliable, low anticipated down time
Gasification
Table 1 lists characteristics of six gasifiers which appear to be applicable to
methanol production and which meet the requirements of this study. All are
commercial now or could become commercial within five years. The Lurgi and
BGC/Lurgi products are high in methane and are advantageous where methane is a
desired product. The Shell and Texaco processes are more attractive because of their
product distributions and high energy efficiencies.
There are some possible disadvantages of the Texaco process. In the reactor,
molten slag contacts the refractory which could lead to early refractory failure.
However, this problem was apparently solved during process development. Another
possible problem concerns preparation of the lignite feedstocks. The high moisture
content of lignites makes grinding difficult and the slurry feed to the gasifier could
have too much water. The alternative would be to dry the lignite, but most
competing processes require drying anyway so this is not a big disadvantage to the
Texaco process. Overall, lignite feeding seems to require special engineering and
design work, but problems that might occur were judged to be solvable. The
successful start-up of the Texaco gasifiers in the Cool Water Plant has provided
additional confidence in this selection.
The Texaco entrained flow process was selected for the coal gasification. It
includes the gasification, cooling, ash dewatering, and slag dewatering blocks in
Figure 1. Advantages over competing processes include the following:
o Drying is not required for bituminous or subbituminous coals
o The high pressure reactor reduces downstream compression costs
o Steam feed is not required
-------
H,S
MAIN PROCESS
BOILER FEEDWATER
STEAMSYSTEM
OTHER PROCESS AND UTILITY
FIGURE 1
FLOW CHART OF COAL TO METHANOL
PROCESS SCHEME
-------
TABLE 1.
CHARACTERISTICS OF SOME COMMERCIAL AND NEAR COMMERCIAL COAL GASIFIERS (1-7)*
vo
Lurgi
Commercial
Fixed Bed
Dry
2 x K
fines)
Top Lock
Hoppers
Casifier
Commercial Status
Type of Contact
Coal Preparation
Coal Feed Method
Solid Recycle No
Temperature, °F 1000-2000
Pressure, psig 350-450
Relative, O2 feed n/a
Relative steam feed high
Slag/refractory contact No slag
Energy Efficiency
Cold gas only 80
Cold gas + hydrocarbons 89
Including steam 89
Product Composition, Volume, %
Hydrogen 39 45
Carbon monoxide 17 16
Carbon dioxide 31
Methane 9 8.5
Other Hydrocarbons,
Ib per Ib of CO2 free gas 3.9
Information Source, Reference No. 7 5
BGC Lurgi
ear Commerical
Fixed Bed
Dry
2 x (4
(- 35% fines)
Top Lock
Hoppers
Optional
1300-3300
350-450
low
low
Flux
(lowers M.P.)
88
90
90
29
59
3.3
8.7
1.7
5
Koppers-Totzek
Commercial
Entrained Flow
Dry - 2% H2O
70%- 200 M
Screw
Conveyors
No
2700
0
high
n/a
L.P. steam
outside
refractory
67
67
85
36
52
0
0
7
Shell
Late 1980's
Entrained Flow
Dry < 5% H2O
Grind
Pressurized
Pneumatic
Yes
2500
392
high
None
H.P. steam
in wall
80
80
94
30
60
2
0
0
3
Texaco
Cool Water
Mid 1984
Entrained Flow
No Drying
Grind
H2O slurry
Slurry
Pump
No
2300
690
high
None
Slag contacts
the
refractory
77
77
95
39 35
38 48
17
0.5 0.5
0 0
7 5
Westinghousi
Keystone in
SFC Negotiatii
Fluidized Be
Dry
X xO
Pneumatic
Yes
1900
230
low
n/a
No Slag
81
81
90
n/a
n/a
n/a
n/a
n/a
6
* lumbers in parentheses designate references at the end of this report.
n/a Not available
-------
o Energy efficiency and product gas composition compare favorably
o There are no size requirements for the coal particles
o It accepts both caking and non-caking coals
Gas Preparation
Before the synthesis gas can be used in a methanol reactor two major changes
must be made in its composition. These are adjustment of the hydrogen to carbon
monoxide ratio, and the removal of sulfur compounds. The ratio is adjusted through
use of the water gas shift reaction:
CO + H2O J5r=fe H2 + CO2
Most methanol synthesis reactors require a small amount of CC>2 in the feed, but when
coal is used as the feedstock, a large amount of excess CC>2 is produced in the shift
reactor and it must be removed to obtain the required synthesis gas composition. Two
types of catalysts are available for the water-gas shift reaction; one requires some
sulfur in the feed, the other requires a sulfur-free feed. The sulfur-tolerant process
was selected because it appears to have less stringent operating requirements. This
selection requires placement of the shift reactor ahead of the sulfur removal
processes.
While most of the sulfur from the gasifier is in the form of hydrogen sulfide
(H2$), which can be readily removed from the gas stream, some is present as carbonyl
sulfide (COS) which is difficult to remove. In the shift reactor COS reacts with water
to form hydrogen sulfide:
COS + H2O =£5= H2$ + CO2
However, the final hydrogen to carbon monoxide ratio is controlled by by-passing part
of the gas stream around the shift reactor. To remove COS from the by-pass stream,
a reactor is used which contains a catalyst selective to the COS-water reaction and
does not promote the water gas shift reaction. With this arrangement, nearly all the
sulfur in the feed to the acid-gas removal section is in the form of
There are two types of acid-gas removal processes: selective and non-selective.
In non-selective processes, several acid gases, in this case H2$ and CO2, are removed
in a mixture, but in selective processes, relatively concentrated streams of each acid
gas are produced. A high H^S concentration in the stream from the acid gas removal
10
-------
section is advantageous for the later production of elemental sulfur. Also, the
growing importance of carbon dioxide in enhanced oil recovery processes makes it a
valuable by-product in some areas. The selective SELEXOL process was chosen for
this step.
Elemental sulfur is the desired final form of the sulfur impurities because it is
easily handled and is a valuable by-product. Of the available sulfur production
processes, the Claus process was selected because of reliability. In the Glaus process,
part of the H2S stream is oxidized to form sulfur dioxide (SO2). The two sulfur
compounds react first in a thermal reactor, then in a series of catalytic reactors to
form elemental sulfur:
2H2S + SO2—*• 35 + 2H20
The Claus reaction does not proceed to completion; there are still some sulfur gases
left over in the tail-gas. The SCOT process, which uses hydrogen to convert the left-
over SO2 back to H2S, was selected to treat the tail-gas. The H2S is then separated
from the rest of the tail-gas and sent back to the Claus feed.
The available acid gas removal processes do not get the H2S concentration low
enough to prevent damage to the methanol synthesis catalyst. A zinc-oxide absorption
bed, or guard-bed, is used to remove the last traces of sulfur before the synthesis gas
enters the methanol reactor.
Methanol Synthesis
Several very competitive processes are available for methanol synthesis. The
reaction is favored by high pressure; the higher the temperature, the more pressure is
required. At low temperatures the reaction rates are too slow. Historically, more
active catalysts have been sought to provide an acceptable reaction rate at lower
temperatures than used in the previous generation of reactors. This allowed the use
of lower pressures with savings in reactor capital cost and in compression energy
requirements. For this reason, high pressure processes such as Vulcan Cincinnati were
not considered. The Wentworth process is a recent variation of the high pressure
processes and several advantages are claimed, but whether these advantages offset the
higher compression cost was difficult to determine without using proprietary,
commercial scale data and experience. (8-9) Chem System's new liquid phase process
11
-------
was not close enough to commercial demonstration for these purposes. Mitsubishi Gas
Chemicals' process is similar to the Imperial Chemical Industries' (ICI) process, but the
catalyst may have a shorter lifetime.
Other major process licensors include Lurgi and Haldor Topsoe. Brief process
summaries for their methanol processes were recently published based on information
provided by the licensors. (10) Table 2 is a comparison based on these summaries.
Both Fluor and Synthetic Fuels Associates (SFA) have compared the ICI and Lurgi
process. Fluor(ll) found their costs comparable when considering both capital and
operating costs. Catalyst life is 3-5 years for each. SFA (12) points out that there
are differences in the kinds of utilities required and that they favor ICI's process
where utilities are based on coal or gas combustion, but they favor Lurgi's process
where utilities are based on steam generation from waste heat boilers. The large
number of operating ICI plants, utilities based on coal, and the fact that costs are
believed to be comparable were the bases for choosing the ICI process for methanol
synthesis.
The ICI process is based on a quench type, catalytic reactor. The reaction
between hydrogen and carbon monoxide to produce methanol is highly exothermic
causing the temperature to rise out of limits before a very high conversion of the
feedstock has been achieved. In ICI's reactor, the feed contacts a series of catalyst
beds, and between the beds additional cooled feed is mixed in to bring the temperature
back into the proper range. The catalyst is based on copper oxide, but the exact
composition and methods of formulation are proprietary. It may contain zinc oxide
and alumina or chromia, which are believed to prevent copper oxide crystal growth,
because crystal growth reduces the catalyst's useful lifetime. Other processes use
different catalysts and have different methods of controlling the temperature.
Coal Properties and Material Balances
Coal properties selected for this study are given in Table 3. The references
contain descriptions of coal with similar properties. Calculated material balances for
the gasifier and other major process modules are shown in Tables * through 9.
12
-------
TABLE 2. CHARACTERISTICS OF SOME METHANOL SYNTHESIS
PROCESSES
Haldor Topsoe
Reactor Type Fixed bed
Radial flow
ICI
Fixed bed
down flow
Heat Removal Heat exchange cold feed
between stages gas, between
cat. beds
Pressure, psig 700-1000
Temperature, °F
No. Plants Operating
Plants in Des. or Const.
Size of Plants, Bbl^/d
Feed and Fuel, 10* Btu(2)/Bbl(D
Natural Gas Feed 29.0
Heavy Oil Feed
Coal Feed
Electric Power, kWh/Bbl*1)
Natural Gas Feed 1.9
Heavy Oil Feed
Coal Feed
Cooling Water Requirements, 103 Gal/BblO)
Natural Gas Feed 4.32
Heavy Oil Feed
Water Consumption, Gal/Bbl^)
Natural Gas Feed 26.3
Heavy Oil Feed
Coal Feed
Catalysts <3c Chemicals, $/BblO)
Natural Gas Feed
Heavy Oil Feed
Coal Feed
750-1500
400-570
28
12
400-20,000
29.0
31.0
4.4
11.0
2.32
2.93
38.2
24.9
0.188
0.226
Lurgi
Tubular
water jacket
for steam
1000-1500
460-520
14
7
1200-20,000
28.2
36.3
38.7
-
-
103
83
126
0.126
0.063
0.075
- Not available
(1) Bbl = barrel or 42 gallons of methanol product
(2) Based on higher heating value
13
-------
TABLE 3. PROPERTIES OF COALS
Coal Type Eastern
High-Sulfur
Bituminous
Coal Moisture
Content, % 2.1
Proximate Analysis (dry basis)
Vol. matter, % 42.3
Fixed carbon, % 49.0
Ash, % 8.6
Ultimate Analysis, (MAP)
Carbon, % 79.3
Hydrogen, % 5.7
Sulfur, % 4.0
Nitrogen, % 1.2
Oxygen, % 9.8
Higher Heating Value,
BTU/lb (AF) 14,170
Ash Fusibility (Reducing)
Initial
Deformation,°F
Softening
Temp., °F 2,080
Fluid Temp., °F
Midwestern
High-Sulfur
Bituminous
12.4
39.5
46.2
14.2
79.03
5.61
5.49
1.32
8.54
12,757
1,975
2,140
Western
Sub-
bituminous
6.39
46.48
46.48
7.04
72.95
5.35
0.65
0.86
20.19
11,558
2,230
2,250
Southern Northern
Lignite Lignite
32.0
42.1
39.4
15.6
73.70
5.61
2.33
1.47
16.89
8,500
2,280
36.0
45.9
42.3
11.8
70.2
5.3
1.3
0.8
22.4
7,100
2,185
2,210
2,265
Information Source,
Reference No. 13, 14
15, 16
13, 17
18,19
18, 19
Not available
14
-------
TABLE it. MATERIAL BALANCES FOR GASIFIER
Coal Type
Eastern Midwestern Western
High-Sulfur High-Sulfur Sub-
Bituminous Bituminous bituminous
Southern
Lignite
Stream and Components, 1000 Ib mols/day except as noted:
Slurry Gasifier Feed:
Coal, raw,
ton/day 9097
Coal, moisture free
ton/day 8909
Water 1239
Oxygen Gasifier Feed:
O2 561.4
N2 1.78
Ar 9.68
10850
9551
1243
566.5
1.79
9.77
10052
9409
1225
498.4
1.58
8.59
15172
10314
1231
529.0
1.67
9.12
Northern
Lignite
16161
10340
1229
491.9
1.56
8.48
Raw Gas Product
CO
H2
CO2
H2O
H2S
COS
NH3
CH^
N2
Ar
774
561
294
1098
19.06
1.26
6.66
5.79
5.42
9.68
776
555
295
1096
26.32
1.740
6.68
5.80
6.17
9.77
766
570
291
1094
3.33
0.220
6.58
5.72
3.66
8.59
769
565
292
1118
11.87
0.784
6.62
5.75
7.50
9.12
768
567
292
1116
4.27
0.282
6.60
5.74
6.72
8.48
Total Raw Gas 2775
Ash, Slag
Tons/day
766
2779
1356
2749
662
2786
1609
2775
1220
15
-------
TABLE 5. MATERIAL BALANCES FOR SHIFT REACTOR AND
COS HYDROLYZER, FEED STREAMS
Coal Type
Eastern
High-Sulfur
Bituminous
Stream and Components, 1000 Ib
Midwestern
High-Sulfur
Bituminous
mols/day except
Western
Sub-
bituminous
as noted:
Shift Reactor Feed
CO
H2
C02
H2O
H2S
COS
Cfy
N2
Ar
Total Shift Feed
COS Hydrolyzer
CO
H2
C02
H2O
H2S
COS
CH^
N2
Ar
Total COS
Hyd. Feed
569
412
216
982
14.01
0.927
4.26
3.99
7.12
2210
Feed
205
149
77.9
147
5.05
0.333
1.53
1.44
2.57
590
573
410
218
990
19.43
1.28
4.28
4.56
7.21
2228
203
145
77.3
154
6.89
0.455
1.52
1.62
2.56
592
558
415
212
961
2.43
0.161
4.17
2.66
6.26
2162
208
154
78.9
148
0.901
0.060
1.55
0.99
2.33
595
Southern Northern
Lignite Lignite
563 562
414 415
214 214
974 967
8.69 3.12
0.573 0.206
4.21 4.20
5.49 4.91
6.68 6.20
2191 2175
206 207
151 152
78.3 78.5
156 155
3.18 1.148
0.210 0.076
1.54 1.54
2.01 1.81
2.44 2.28
600 600
16
-------
TABLE 6. MATERIAL BALANCES FOR SHIFT REACTOR AND
COS HYDROLYZER, PRODUCT STREAMS
Coal Type
Stream and
Eastern
High-Sulfur
Bituminous
Components, 1000 Ib
Midwestern
High-Sulfur
Bituminous
mols/day except
Western
Sub-
bituminous
as noted:
Shift Product
CO
H2
C02
H2O
H2S
COS
CH^
N2
Ar
Total Shift
Product
Hydrolyzer
CO
H2
C02
H2O
H2S
COS
CHif
N2
Ar
171
811
615
584
14.75
0.185
4.26
3.99
7.12
2210
Product
205
149
78.3
147
5.369
0.0125
1.53
1.44
2.57
172
811
620
588
20.46
0.257
4.28
4.56
7.21
2228
203
145
77.6
153
7.326
0.0183
1.52
1.62
2.56
167
806
603
570
2.55
0.0321
4.17
2.66
6.26
2162
208
155
79.0
148
0.958
0.0024
1.55
0.99
2.33
Southern Northern
Lignite Lignite
169 168
808 808
609 607
579 574
9.15 3.29
0.115 0.042
4.21 4.20
5.49 4.91
6.68 6.20
2191 2175
206 207
151 152
78.5 78.6
156 155
3.379 1.220
0.0084 0.0031
1.54 1.54
2.01 1.81
2.44 2.28
Total Hydrolyzer
Product 590 592 595 600 600
17
-------
TABLE 7. MATERIAL BALANCES FOR ACID GAS REMOVAL AND GUARD BED
GAS CONDITIONING PROCESSES, FEED STREAMS
Coal Type Eastern Midwestern Western
High-Sulfur High-Sulfur Sub- Southern Northern
Bituminous Bituminous bituminous Lignite Lignite
Stream and Components, 1000 Ib mols/day except as noted:
Feed (Combined Shift and Hydrolyzer product, dry)
CO
H2
C02
H2O
H2S
COS
Inerts
Total Feed
376
959
694
1.09
20.12
0.198
20.9
2071
375
957
698
1.09
27.8
0.275
21.7
2080
375
960
682
1.07
3.51
0.035
18.0
2040
375
959
688
1.08
12.5
0.123
22.4
2058
375
960
685
1.08
4.51
0.044
20.9
2045
18
-------
TABLE 8. MATERIAL BALANCES FOR ACID GAS REMOVAL AND GUARD BED
GAS CONDITIONING PROCESSES, PRODUCT STREAMS
Coal Type Eastern
High-Sulfur
Bituminous
Midwestern
High-Sulfur
Bituminous
Western
Sub-
bituminous
Stream and Components, 1000 Ib mols/day except as noted:
H2S Rich Product
CO 0.187 0.187 0.188
H2
CO2
H2O
H2S
COS
Inerts
Total H2S
Rich Product
CO2 Rich Product
CO
H2
C02
H2O
H2S
COS
Inerts
Total CO2
Rich Product
Methanol Synthesis
CO
H2
CO2
H20
H2S
COS
Inerts
50.30
0.011
20.12
0.148
-
70.76
0.563
0.289
573
0.011
0.050
-
574
Feed Gas
375
959
70.3
1.06
0
0
20.9
69.47
0.011
27.79
0.206
-
97.66
0.561
0.287
558
0.011
0.069
-
559
374
956
70.4
1.07
0
0
21.7
8.78
0.011
3.51
0.026
-
12.52
0.563
0.288
603
0.011
0.009
-
604
374
960
70.3
1.05
0
0
18.0
Southern
Lignite
0.187
31.3
0.010
12.53
0.092
-
44.13
0.563
0.289
586
0.011
0.031
-
587
374
959
70.3
1.05
0
0
22.4
Northern
Lignite
0.188
.
11.27
0.011
4.51
0.033
-
16.01
0.563
0.288
604
0.011
0.011
-
605
375
960
70.3
1.05
0
0
20.9
Total Methanol
Feed 1426 1424 1424 1427 1427
19
-------
TABLE 9. MATERIAL BALANCE FOR METHANOL SYNTHESIS REACTOR,
ALL COALS*
Components
CO
H2
CO2
H2O
Methanol
Light Ends
Higher Alcohols
Crty
N2
Ar
TOTAL 1424 62.76 503.8
Streams, 1000 Ib
Feed
374
960
70.3
1.05
-
-
-
5.72
3.66
8.59
mols/day
Raw
Purge Gas Methanol
3.30
32.18
8.58
0.017
0.931
-
-
5.58
3.62
8.56
0.073
0.137
1.97
71.36
429.6
0.24
0.24
0.141
0.040
0.034
* Stream compositions for the methanol synthesis reactors were the same for each
coal type. This material balance is for one of them.
20
-------
IV. PLANT-GATE COSTS
Capital Expenditures
The sizes of the streams calculated in the material balances provide a basis for
estimating the process module costs. Capital expenditures are estimated for
equipment of differing sizes by using the following general relationship, called the
power law (20):
Cost = A (Capacity)17
The term F is typically 0.6 where increases in capacity are achieved by increasing the
size of the processing units, and between 0.9 and 1.0 where increases in capacity are
achieved by increasing the number of processing units. Values for A and F were
obtained by a least squares regression of published costs for processing modules. In
some cases only one published cost was obtained for a processing module adequately
representative of the module planned in this study. In each of these cases, the size is
in the range where increased capacity is achieved by increasing the size of the
processing units and the value 0.6 was assigned for F. Table 10 gives the values for A
and F, the units to be used for the capacity, and the capacity range for which the
equation is considered valid. The results are in 1980 dollars. The cost of flue gas
desulfurization units for the boiler was based on a model by Rubin, Bloyd, and
Molberg (21). The estimated capital expenditures for the major process units are
given in Table 11. Most of the raw data used for the capital expenditure estimates
were given in 1980 dollars. Those which were not were adjusted for inclusion in the
tables. In the last part of this section, the summaries are given in 198^ dollars.
21
-------
TABLE 10. FACTORS IN COST ESTIMATION RELATIONSHIP
N>
Process Module
Coal Preparation
Oxygen Plant
Gasification
Gas Conditioning
Acid Gas Removal
H2S
C02
Sulfur Plant
Methanol Synthesis
Methanol Distillation
Steam and Power
Capacity Units
tons/day
Ib mols O2/hr
tons coal/day
Ib mols shift feed/hr
Ib mols H2S/hr
Ib mols CO2/hr
Ib mols H2S/hr
Ib mols MeOH/hr
Ib mols feed/hr
kilowatts
Capacity Range
1,000 -
2,000 -
5,000 -
70,000 -
100 -
5,000 -
100-
10,000 -
15,000 -
40,000 -
20,000
50,000
20,000
150,000
2,000
50,000
2,000
50,000
30,000
100,000
F
0.497
0.905
0.745
0.674
0.600
0.600
0.709
0.854
0.600
0.600
A,$106 -1980
161,170
15,400
194,200
14,680
1,218,000
77,283
197,900
22,097
32,728
68,800
References
(51,58,61)
(51,52,54,55,58-60)
(51,58,61)
(51,52,54)
(54,58)
(54,58)
(51,55,58,60,61)
(51,52,54,60)
(53,59)
(51,52,54)
Includes initial charge of methanol synthesis catalyst.
-------
TABLE 11. CAPITAL EXPENDITURES FOR MAJOR PROCESS MODULES
(1000$, 1980)
Process Module
Coal Preparation
Oxygen Plant
Gasification
Gas Conditioning
Acid Gas Removal
Sulfur Plant
Methanol Synthesis*
Methanol Distillation
Steam and Power
Flue Gas Desulfurization
Eastern
High-
Sulfur
17,114
152,385
182,275
34,948
108,510
25,211
103,600
13,665
48,850
16,340
Mid-
Western
High-
Sulfur
18,914
153,630
213,188
35,140
123,690
31,698
103,600
13,665
49,654
18,526
Western
Sub-
bituminous
17,814
136,820
199,190
34,435
61,771
7,310
103,600
13,665
49,667
0
Southern
Lignite
22,648
144,400
287,219
34,745
90,757
18,020
103,600
13,665
51,711
19,735
Northern
Lignite
23,118
135,205
303,804
34,574
66,252
8,732
103,600
13,665
52,528
17,475
TOTAL
702,898
761,705
624,272 786,500 758,953
Includes initial charge of methanol synthesis catalyst.
23
-------
The utilities constitute a major portion of the offsite costs. Estimates of
utilities consumption and production were made for each process module in the
following categories:
o Electric Power
o Water
- Cooling
- Raw
- Demineralized
Boiler feed
Condensate
o Steam
- 1500 psig
100 psig
50 psig
o Fuel Gas
The estimates were made by analogy with published utility summaries for similar
processes. (22,23,24,25,26). Estimates in each category were summarized and the
equivalent heat requirement or credit was calculated for the electric power, fuel gas,
boiler feed water loss, and each category of steam. The heat requirement was used to
calculate the non-process coal requirement for each plant. The capital expenditures
for utilities were based on the total electric power requirement.
Other offsite expenditures were estimated by various methods. Condensate
treatment, piping, methanol storage, and sulfur handling were estimated using the
same mathematical relationship used for estimating most of the process module costs.
The required acreage was estimated based on the total coal use, anticipated number of
employees, the approximate sizes of the process units, and the size of land parcels
available in the different coal producing regions. Land costs were estimated based on
phone conversations with local taxing authorities. Building sizes were estimated
based on function and anticipated occupancy. Building costs per square foot were
based on recent contracts and adjusted using experience factors for rural locations in
the different parts of the country supplied by the Southwest Research Institute
architects. The capital expenditures for offsites are summarized in Table 12.
-------
TABLE 12. CAPITAL EXPENDITURES FOR OFFSITES
($1,000 - 1980)
Function
Utilities
Condensate Treatment
Piperack and Yard piping
Methanol Storage
Sulfur Handling
Land Acquistion
Site work, roads,
parking, & landscape
Admin. Offices
Cafeteria
Shops Building
Warehouse
Garage
Chem. Laboratory
Chem. & Mat'l. Storage
Change Room
Fire Station
Eastern
High-
Sulfur
Bituminous
54718
1427
14572
9556
15345
659
3393
322
457
934
467
208
249
415
156
75
Midwestern
High
Sulfur
Bituminous
55626
1480
14572
9556
21197
606
3393
322
457
934
467
208
249
415
156
75
Western
Sub-
bituminous
55531
1266
14010
9188
2572
242
3131
297
422
862
431
192
230
383
144
69
Southern
Lignite
57809
1379
13730
9004
8452
747
3001
285
404
826
414
184
220
367
138
66
Northern
Lignite
58658
1292
14291
9372
3308
455
3262
309
440
898
449
200
240
399
150
72
Total Offsites
102953
109713
88970
97026
93795
25
-------
People experienced in permitting indicate that costs do not vary significantly
from region to region. Permitting costs were estimated at two million dollars (1980)
in any of the coal producing locations.
Costs of catalysts and chemicals were estimated based on information in the
Fluor and Oak Ridge reports (11,22,27,28), a report by Badger Plants Inc. (29), and
phone conversation with a methanol manufacturer. The results are shown in Table 13.
TABLE 13. INITIAL CATALYST AND CHEMICAL INVENTORY COST,
$1,000 (1980)
Eastern Midwestern Western
High-Sulfur High-Sulfur Sub- Southern Northern
Bituminous Bituminous bituminous Lignite Lignite
Gas Conditioning
Shift reaction
COS hydrolysis
1602
110
1615
111
1567
111
1588
111
1577
111
Acid Gas Removal
Selexol for CO2
Selexol for H2$
ZnO guard bed
1*01
4874
145
1364
6732
144
1474
850
144
1433
3035
145
1477
1093
145
Sulfur Plant
Claus catalyst
SCOT hydrogenation
SCOT solvent
105
82
54
145
113
75
18
14
9
65
51
34
24
18
12
Utilities
Water treatment
29
29
29
29
29
(Methanol synthesis catalysts included in process module estimates).
TOTAL
8402
10327
4216
6491 4341
26
-------
Royalty cost estimates were made with the aid of guidelines supplied by phone
from the process licensors. Actual royalties are often subject to extensive
negotiation, and the licensors requested that the individual process royalties not be
published. A summary is given in Table 14. All the royalties are capital charges
rather than operating charge royalties except for those charged by Texaco, which has
both a capital charge and a small operating royalty. Texaco provides some technical
services in return for the operating royalty and process data.
TABLE 1*. CAPITAL EXPENDITURES FOR ROYALTIES
($106, 1980)
Eastern
High-Sulfur
Bituminous
Midwestern
High-Sulfur
Bituminous
Western
Sub-
bituminous
Southern
Lignite
Northern
Lignite
Cost 6.50 6.53 6.26 6.39 6.30
The start-up costs and working capital estimates are based on other estimates.
The start-up costs for each plant were estimated at 8.0% of the total process
investment which includes the process modules, the initial charge of catalysts and
chemicals, and the royalties. The working capital was taken as total operating
expenditures for one month, plus one extra month's coal cost, plus two extra months
labor cost, plus one year's catalyst and chemical make-up costs.
Some adjustments were made to the capital costs before they were used in
calculating the sales price. Factors were applied to the depreciable assets to adjust
their cost to an effective cost which included the payment of state use taxes. Table
15 shows the states and the use tax factors.
TABLE 15. FACTORS FOR ESTIMATING EFFECT OF STATE USE TAXES
State Factor
Eastern High-Sulfur Bituminous Ohio 1.000
Midwestern High-Sulfur Bituminous Illinois 1.009375
Western Subbituminous Wyoming 1.040
Southern Lignite Texas 1.040
Northern Lignite North Dakota 1.040
27
-------
Installed process plants cost more in cold climates than in mild climates. Extra
insulation, heat tracing, and heavy duty construction add to costs in cold climates.
Engineers with experience in process plant economics estimate the cost differential to
be 15% between the Gulf Coast and the Canadian border. The locations used in the
studies which formed the basis for this estimate were in the north central part of the
country. Two of the selected coal producing regions were in areas with climates
significantly different; these were the northern lignite area and the southern lignite
area. The factor 1.05 was applied to the northern lignite case and 0.95 was applied to
the southern lignite case to account for climatic effects.
All of the costs were adjusted for inflation to 1984 dollars. The Nelson Cost
Indexes for refinery construction are published periodically in the Oil and Gas 3ournal,
and they were used to adjust the capital costs to 1983 dollars. Adjustment to 1984
dollars was made with a projected 10% inflation rate. Table 16 gives the adjusted
capital costs.
TABLE 16. CAPITAL COST SUMMARIES
($106 - 198*)
Process Modules
Offsites
Initial Chemicals
Royalties
Permitting
Start-up
Working Capital
TOTAL
Eastern
High-Sulfur
Bituminous
968.6
141.9
11.6
9.0
2.8
78.7
39.6
Midwestern
High-Sulfur
Bituminous
1059.5
152.6
14.4
9.0
2.8
86.6
47.2
Western
Sub-
bituminous
894.7
127.5
5.8
8.6
2.8
72.7
25.2
Southern
Lignite
1070.8
132.1
9.3
8.8
2.8
87.1
28.7
Northern
Lignite
1142.1
141.1
6.2
8.7
2.8
92.6
29.5
1252.1
1372.0
1137.3
1339.7
1422.9
28
-------
Operating Costs
Operating cost estimates were developed from several sources. Coal costs are
one of the largest expenses and forecasts of coal price involve a considerable amount
of uncertainty. Published forecasts in industry journals typically extend prices for
only one or two years in advance. The Energy Information Agency has compiled
statistics on steam coal prices since 1972, and they project prices out to 1995,
apparently based on a constant rate of price increase. (30) Coal price forecasts used
in design of coal gasification systems have typically been higher. (31,32) Several
coal producers and utility coal consumers contacted by phone expect coal price
increases to eventually exceed the inflation rate.
The published information and the phone conversations generally concerned
contract prices, that is, the prices paid when demand can be met from current
operations. If production must be expanded, typically by opening new mines, the
prices paid would have to be somewhat higher. This marginal price is typically about
20 percent above average contract prices.
High sulfur coal costs were expected to show no major long-term change.
Although the sulfur content of the high-sulfur coals studied here is above the high-
sulfur coal average, in making SwRI's coal price forecast, further downward
adjustments in price were not made because of two conflicting pressures. The current
oil glut is expected to be temporary, and overall coal prices are expected to increase
faster than inflation because of the long term energy shortage. However, demand for
coal with the high sulfur content considered here is expected to decline relative to the
total demand because of controls on gaseous sulfur emissions. With these
considerations, high-sulfur coal prices were forecast to remain steady, in constant
dollars, throughout the plant life.
The low-sulfur coal prices seem to be more subject to increases because fuel-
switching may increase in the future. However, this will be somewhat dependent on
governmental decisions and legal interpretations which make it difficult to forecast
29
-------
the extent of fuel switching. To see how coal price increases might affect the
product price, calculations were made based on four different, twenty year, constant
dollar forecasts:
1. Coal cost low, remaining near 1984 levels.
2. Coal cost rises slowly, increasing about 45%.
3. Coal cost rises rapidly, increasing about 90%.
4. Coal cost high and constant, well above 1984 levels.
The coal cost forecasts are summarized in Table 17.
TABLE 17. COAL COST FORECASTS, $/Ton
(Constant 198* $)
Years From 1990 Plant Startup 1-5 6-10 11-15 16-20
Eastern High-Sulfur Bituminous 31.70 31.70 31.70 31.70
Midwestern High-Sulfur
Bituminous 34.30 34.30 34.30 34.30
Western Subbituminous
Coal Cost Low 11.00 11.00 11.00 11.00
Coal Cost Rises Slowly 11.00 12.67 14.33 16.00
Coal Cost Rises Rapidly 11.00 14.00 17.00 20.00
Coal Cost High 15.00 15.00 15.00 15.00
Southern Lignite
Coal Cost Low 9.50 9.50 9.50 9.50
Coal Cost Rises Slowly 9.50 11.00 12.50 14.00
Coal Cost Rises Rapidly 9.50 12.50 15.50 18.50
Coal Cost High 13.50 13.50 13.50 13.50
Northern Lignite
Coal Cost Low 9.50 9.50 9.50 9.50
Coal Cost Rises Slowly 9.50 11.00 12.50 14.00
Coal Cost Rises Rapidly 9.50 12.50 15.50 18.50
Coal Cost High 13.50 13.50 13.50 13.50
The total coal consumption is given for each plant in Table 18. Coal
consumption is the total required for the process material balances, plus the utility
boiler requirements.
30
-------
TABLE 18. TOTAL COAL CONSUMPTION
Coal Type Coal, 1Q6 ton/year
Eastern High-Sulfur Bituminous 3.93
Midwestern High-Sulfur Bituminous 4.81
Western Subbituminous 4.26
Southern Lignite 6.91
Northern Lignite 7.20
The cost of water is a much lower fraction of the total operating costs than the
cost of coal. Water costs do not respond to supply in the same way that other
resources do because prices are regulated and because it is usually impractical to
transport it over long distances. Elements of the water cost include the facilities to
acquire the water and do preliminary treatment, and the operating costs. For surface
water, facilities costs would include pumps and the construction of reservoirs and
treatment plants to remove both suspended and dissolved impurities. For deep
groundwater, facilities costs would include well drilling, pumps, and treatment plants
to remove dissolved impurities. Pump operation for lifting water from a deep well
requires a large amount of energy and can be quite expensive compared to pump
operation for moving water on the surface.
Reliable information on water costs in areas where surface water is plentiful was
published by Ebasco Services, (33) which was based on information supplied by the
Illinois Water Resources Board. Fluor (25) estimated water costs in the northern
lignite fields and Pritchard (34) provided information applicable to deep groundwater
in an arid, western subbituminous coal region. Water cost forecasts are given in Table
19 and the water consumption for the principal in-plant uses is given in Table 20.
Other utilities were produced in plant and costs were included elsewhere.
TABLE 19. WATER COSTS
Coal Type 1984, $/1000 Gallons
Eastern High-Sulfur Bituminous 0.072
Midwestern High-Sulfur Bituminous 0.072
Western Subbituminous 1.155
Southern Lignite 0.150
Northern Lignite 0.115
31
-------
TABLE 20. WATER CONSUMPTION
(109 Gal/year)
Coal Type Process
Eastern High-Sulfur
Bituminous 0.98
Midwestern High-Sulfur
Bituminous 0.98
Western Subbituminous 0.97
Southern Lignite 0.97
Northern Lignite 0.97
Cooling
10.36
11.90
6.50
8.50
6.60
Other
3.12
3.12
3.12
3.12
3.12
Total
1M.
16.00
10.59
12.59
10.69
The high cooling-water requirement for the plants using high-sulfur coal is due to
consumption in the large acid gas removal sections required for those plants.
The annual costs of catalysts and chemicals were estimated based on information
in the Fluor and Oak Ridge reports (11,22,27,28), the report by Badger Plants (29) and
a phone conversation with a methanol manufacturer. The results are shown in
Table 21.
TABLE 21. ANNUAL CATALYST AND CHEMICAL COSTS,
$1,000 (1980)
Eastern
Process High-Sulfur
Module Bituminous
Gas conditioning
Shift reaction
COS hydrolysis
Acid Gas Removal
Selexol for CO2
Selexol for H2S
ZnO guard bed
Sulfur Plant
Claus catalyst
Hydrogenation
SCOT solvent
321
37
177
616
145
20
24
162
Midwestern
High-Sulfur
Bituminous
323
37
172
851
144
27
33
224
Western
Sub-
bituminous
314
37
186
107
144
3
4
28
Southern
Lignite
318
37
181
383
145
12
15
101
Northern
Lignite
315
37
187
116
145
5
5
36
Utilities
Water
treatment
Methanol
synthesis
TOTAL
431
4411
6344
431
4411
6653
431
4411
5665
431
4411
6034
431
4411
5688
32
-------
Operating labor costs were estimated from the numbers of employees projected
in several labor categories. The number of employees required for various sections of
the plant were estimated based on published sources (11,32) and experience with
similar units. The numbers are indicated on the organization chart shown in Figure 2.
Operating labor rates shown in Table 22 were estimated with the aid of information
supplied by the Bureau of Labor Statistics and industry sources.
TABLE 22. ESTIMATED LABOR RATES, 198* Dollars/Hour
Eastern
Labor High-Sulfur
Category Bituminous
Process Engineer
Sr. Plant Operators
Plant Operators
Drivers
Chemist
Sr. Lab Technician
Lab. Technician
Purchasing
Ins. & Personnel
Acctg. & Payroll
Sales
Secretaries
Nurse
20.13
18.26
14.55
13.39
15.56
17.89
13.95
15.39
14.54
10.56
13.04
10.00
13.13
Midwestern
High-Sulfur
Bituminous
20.13
18.26
14.55
13.39
15.86
18.19
13.95
15.39
13.81
10.03
12.38
9.50
12.47
Western
Sub-
bituminous
19.23
18.08
14.29
14.37
15.16
17.48
13.80
16.85
14.53
10.41
12.85
9.86
12.95
Southern
Lignite
21.12
16.52
13.08
11.81
16.64
18.65
12.03
14.65
13.85
10.06
12.42
9.53
12.51
Northern
Lignite
19.23
17.52
13.91
13.47
15.16
17.41
13.52
16.85
13.85
10.06
12.42
9.86
12.95
Supervision, benefits (labor burden), and overhead were estimated using the same
factors, applied to the operating labor cost, for each plant. Supervision was
estimated at 20% of the operating labor, burden at 35% of the operating labor plus
supervision, and the overhead at 35% of the operating labor plus supervision plus
burden. The total amounts of annual labor cost are shown in Table 23.
33
-------
Plant Manager
Operations
Superintendent
7 Unit
Supervisors
I
Plant
Superintendent
Safety
Engineer
18 Sr. Operators
52 Operators
2-8 Drivers
7 Process
Engineers
2 Plant
Inspectors
1 Chem &
5 Technicians
Feedstock
Department
Maintenance
Superintendent
8 Ma
Crew
int.
Chiefs
142 Maint.
Personnel
__ 6 Maint.
Engineers
7 Sr. Operators
34 Operators
Utility
Department
6 Sr. Operators
39 Operators
FIGURE 2. METHANOL-FROM-COAL PLANT ORGANIZATION CHART
-------
TABLE 23. ANNUAL OPERATING LABOR COST
($106, 198*)
Coal Type Cost
Eastern High-Sulfur Bituminous 12.55
Midwestern High-Sulfur Bituminous 13.10
Western Subbituminous 12.93
Southern Lignite 11.69
Northern Lignite 12.2*
Annual maintenance costs were estimated at 4.0% of the process module costs;
annual totals are shown in Table 24. Two-thirds of the maintenance cost is estimated
for materials and one-third is estimated for maintenance labor.
TABLE 2*. ANNUAL MAINTENANCE COSTS
($106, 198*)
Coal Type Cost
Eastern High-Sulfur Bituminous 38.74
Midwestern High-Sulfur Bituminous 42.38
Western Subbituminous 35.79
Southern Lignite 42.83
Northern Lignite 45.68
Insurance and local tax cost estimates were made. Annual insurance costs were
estimated at 1.0% of the cost of the process modules, plus the off sites, plus the initial
chemical inventory. Local taxes were estimated based on phone information provided
by representative local taxing authorities in each region. Local taxes generally make
only a very small contribution to the overall product price in industries of this type,
and would normally be included only in much more detailed cost studies. However,
they do vary among different regions of the country, and they were included here
because in this study an evaluation of the regional differences was an important
objective. They were grouped with the insurance for calculation purposes. Totals are
shown in Table 25.
35
-------
TABLE 25. ANNUAL INSURANCE AND LOCAL TAX COSTS
($106, 198*)
Coal Type Cost
Eastern High-Sulfur Bituminous 25.24*
Midwestern High-Sulfur Bituminous 14.81
Western Subbituminous 11.02
Southern Lignite 13.18
Northern Lignite 12.97
* First year only, costs decline slightly in succeeding years.
State taxes were estimated based on the main provisions of the state tax laws,
utilizing credits for local taxes where applicable. The states used for these estimates
were the same as given in Table 15 for the use taxes. Federal tax was estimated at
46% of the income less state taxes and depreciation.
Credit for By-Products
Two by-products make contributions to the plant economics, and both show
considerable variation by region. These are sulfur and carbon dioxide. Sulfur prices
were estimated from listings in recent issues of the Chemical Marketing Reporter and
are given in Table 26. Northern and western prices were lower because of their
distance from major markets in fertilizer manufacture, and their proximity to
inexpensive Canadian supplies. Prices in the southern lignite region were estimated
slightly lower because those producers would compete with Houston area oil refiners
who have ready access to water transportation.
TABLE 26. ESTIMATED PRICES FOR CRUDE BRIGHT SULFUR
(1984 $/Long Ton)
Eastern High-Sulfur Bituminous 110
Midwestern High-Sulfur Bituminous 110
Western Subbituminous 75
Southern Lignite 90
Northern Lignite 80
36
-------
Most studies of methanol plant economics have not taken any credit for carbon
dioxide. However, its use in enhanced oil recovery has increased in recent years and
its potential sale has become a significant factor. Literature pertaining to possible
markets and competing sources was examined for guidance in estimating CO2 sales.
Science Applications Inc. (35) studied demand in four basins for a 15 year CO2
injection life with results given in Table 27:
TABLE 27. TOTAL CARBON DIOXIDE DEMAND (35)
Carbon Dioxide Demand
Oil Producing Basin
Permian Basin and Texas Gulf Coast
Williston Basin (North Dakota, Montana)
Appalachian Basin (Ohio, West Virginia)
Los Angeles Basin
* Million standard cubic feet per day
** Tons per day
MMSCFD*
8228
194
68
309
TPD**
478,000
11,300
3,900
17,900
Industry sources have indicated that there are major markets near the western
subbituminous and the northern lignite coal regions. Although CO2 injection for
enhanced oil recovery has been demonstrated in Appalachian fields (36), the oil fields
in that region are small, shallow, and the potential market is very small. (37) Also, the
procedure would be economic only if CO2 could be obtained at a low price. The same
is true of the Illinois basin fields where the potential market appears to be even
lower. (35) No projects are underway or planned in Illinois, but CO2 use is increasing
in the other basins of interest. (38-40)
The principal competing source of CO2 was natural deposits obtained from wells.
Some was available as a by-product in natural gas, but other wells produced nearly
pure CO2- Natural CO2 was available for oil fields near the western subbituminous
coal region, the southern lignite region, and the eastern high-sulfur region. However,
CO2 pipelines several hundred miles long would be required in each case. One
pipeline has recently gone into service bringing CO2 from southern Colorado to the
Permian Basin.
37
-------
The pattern of CC>2 use in an individual project results in reduced sales over a
period of time. Typically, CC>2 use remains nearly constant for about 5 years until
CC>2 content in the product oil gets high enough to make recovery and recycle
profitable. New CO2 use then declines for several years until it is used only to
replace losses. To maintain constant sales, new projects would need to be found
during the plant life.
With this background, decisions were made about the prospects for CO2 sales.
They were necessarily somewhat arbitrary. Since the technology is relatively
young, new developments could significantly alter the sales pattern from that given
in Table 28. The decisions include the percent of production expected to be sold,
the period of sales, the maximum number of plants expected to sell CO2, and the
price. The sales patterns in Table 28 were used in calculating the plant-gate
annual credits for CO2 sales.
TABLE 28. CARBON DIOXIDE PRICES AND EXPECTED SALES
Coal Type
Eastern High-Sulfur
Bituminous
Midwestern High-Sulfur
Bituminous
C02
Produced,
TPD
12600
12300
Percent of
Production
Sold
10%
Sales
Period
Plant Life
Max.
No.
Plants
Price,
$/Ton
20
Western Subbituminous
13300
60
decline
30
Southern Lignite
Northern Lignite
12900
13300
100 Plant life
60
decline
10
25
35
Economic Assumptions
Several economic assumptions were used with the information given in the
preceding sections for calculating the plant-gate price of methanol. Four different
discounted-cash-flow rates of return were used to show the effect on sales price.
Different rates of return would be expected with different financing arrangements.
Plants built with equity financing typically expect 20-25% rate of return on
38
-------
investment, while those built with some sort of government participation are willing to
accept a lower rate of return. The government participation could take the form of a
subsidy, a loan guarantee, or a price support. Price supports seem likely in view of the
successful negotiation of price support agreements by Union Oil Shale and Cool Water
Coal Gasification. Actual rates of return differ from industry to industry and vary
with market conditions, but 18% is typical for manufacturing industries. Energy
companies are very competitive and generally receive lower rates of return, typically
about 12%, although investment funds are not generally available for new projects
unless economic studies indicate about 20 to 25% rate of return. For a plant built with
governmental participation, a selling price equivalent to about 12% rate of return
could probably be negotiated. For a plant built with equity financing, 20% would
seem a reasonable rate of return if the technology and markets are well established.
If an equity-financed plant were seen as a pioneering venture, investors would expect a
higher rate of return, 25% or greater. Other economic assumptions used in the
calculations included the following:
o Project life was 20 years
o Construction schedule -
Year Percent Spent
1 12
2 23
3 30
t 23
5 12
o Depreciation using the accelerated cost recovery system -
Year Percent Depreciated
1 15
2 22
3 21
t 21
5 21
o A 10% federal investment tax credit was taken, but no energy investment
credits were taken.
39
-------
o Income was assumed to be continuous for determining the present worth
factors used in the discounted-cash-flow method (41).
o Four discounted-cash-flow rates of return on investment were used: 10,
15, 20, and 25%. The method of calculation was based on income
distributed evenly throughout each year.
A computer program was written which uses an iterative procedure for
calculating the required sales price. It has provision for running a series of cases with
minor variations, without requiring re-input of the data which remain constant
between cases. Options allowed year by year changes in any operating costs or credits
which were expected to vary over the project life, cash outlays and recoveries, and the
incorporation of site specific items, such as the coal severance tax or license report
fees, not covered in the general operating cost categories. Temporary modifications
were made on a case-by-case basis to accommodate unusual items such as state tax
credits for local taxes, or a state net worth tax. The program was written to meet the
needs of this project, and as these needs were developed the program was expanded by
putting additional subroutines at the end, so program elements are not all arranged in
the same sequence as calculations occur. A complete listing of the program is given in
Appendix A.
The computer program was used to calculate plant-gate methanol prices for all
five coal types. The results, shown in Table 29, indicate that coal-derived methanol
can be produced for the lowest cost in the western subbituminous region, if sufficient
water is available. Costs in the southern lignite region are only slightly higher. Costs
in the northern lignite region are about midway between the lower cost regions and the
high cost eastern and midwestern regions using high-sulfur coal. The prices indicate
that the rate of return on investment has much more influence on the methanol price
than the coal cost in the ranges studied. Coal cost projections were given in Table 17.
The computer output for each calculated price includes a year-by-year listing of
the cash outlays, sales, earnings, taxes, cash flow, and present values. It also includes
the payout period and tables showing each operating expense, both in annual dollars
and as a percent of the total operating expenses. An example printout is included in
Appendix B.
40
-------
TABLE 29. PLANT-GATE METHANOL PRICES, 198* $/GALLON
Return on Investment, %
Eastern High-Sulfur
Midwestern High-Sulfur
Western Subbituminous
Coal Cost Low
Coal Cost Rises Slowly
Coal Cost Rises Rapidly
Coal Cost High
Southern Lignite
Coal Cost Low
Coal Cost Rises Slowly
Coal Cost Rises Rapidly
Coal Cost High
Northern Lignite
Coal Cost Low
Coal Cost Rises Slowly
Coal Cost Rises Rapidly
Coal Cost High
In 1984, by comparison, conventionally produced methanol prices were low.
Most methanol was made from natural gas and some U.S. plants were closed or
operating below capacity. In world markets, there was an oversupply of methanol,
yet some new plants had recently come on stream, or were nearing completion in
areas of the world with sources of inexpensive natural gas feedstocks. No major
new market areas were expected, except the automotive fuel market just beginning
to develop. The potential automotive fuel market was much larger than the
available, conventional supply both in the U.S.A. and worldwide. (42) However,
without rapid growth of the fuel market, the low methanol prices were expected to
continue with little change for several years. Spot prices for U.S. Gulf coast
delivery were frequently between $0.40 and $0.45 per gallon and contract prices
for rail-car or truck shipment were generally below $0.50 per gallon. The plant-
gate costs for coal-derived methanol would be significantly higher except for the
western subbituminous and the lignite regions at 10% return on investment.
10
0.608
0.651
0.363
0.372
0.379
0.388
0.353
0.364
0.376
0.390
0.470
0.482
0.495
0.509
15
0.790
0.862
0.520
0.527
0.533
0.546
0.544
0.553
0.563
0.582
0.688
0.699
0.709
0.729
20
1.037
1.144
0.732
0.738
0.743
0.759
0.800
0.808
0.816
0.840
0.983
0.991
0.999
1.025
25
1.345
1.496
1.000
1.004
1.008
1.027
1.121
1.127
1.133
1.162
1.356
1.362
1.368
1.399
41
-------
Siting Limitations
Despite the low price of methanol produced in the western subbituminous region,
plant siting would present some difficulties. In some localities, the coal is at
excessive depth, and there are significant hazards associated with underground mining.
Aquifer disruption and acid mine drainage can cause problems there, just as in other
coal fields. However, the western subbituminous coal deposits are very large, and
most of these problems can be avoided by careful selection of the mine location. The
principal constraint on siting is the water supply, and it has been the subject of
extensive controversy, but it also seems to be a solvable problem.
A review by the U.S. Office of Technology Assessment (43) discusses the
restraints on water use in the western subbituminous mining region. Surface water
allocations are based on average streamflows rather than on expected minimum
streamflows, the basis used in most of the eastern U.S. Furthermore, the western
streamflows show large season-to-season variations and large year-to-year variations.
(43,44) If water allocation could be obtained, large reservoirs would be required to
avoid water shortages. However, reservoir construction in highly scenic western
areas has usually been controversial and strong local opposition has prevented,
delayed, or forced alteration of many reservoir construction plans.
Ground water resources in the western subbituminous region have not been
extensively developed. There are some shallow groundwater aquifers, but they are
generally believed to be insufficient for industrial needs. (43,45) The Madison and
related formations appear to contain a significant groundwater resource at greater
depth. (46) The safe yield has been estimated at 75,500 acre feet (24.6 x 109 gallons)
per year, but drilling depths range from 4000 to 20,000 feet. (43) The water will be
expensive and the estimated safe yield would support only a little more than two of
the coal-to-methanol plants in this study. Actual plants will most likely use a
combination of water sources, supplementing whatever surface water can be obtained
with wells.
Water conservation can significantly reduce the water consumption relative to
the normal water requirements. Cooling consumes the largest fraction of water used
in a coal-to-methanol plant, and dry cooling towers are available, but seldom used
because of cost. It is significant that one of the very few dry cooling towers
constructed in the U.S. is on a small power plant located in the western subbituminous
42
-------
region. Larinoff (47) has written a critical review of dry cooling tower cost
estimates, and it appears that dry cooling towers cost about 4 times as much as wet
cooling towers to build. They also require more electric power, which for the coal-to-
methanol plants considered here means a larger boiler and electric generator and
higher coal consumption. Larinoff's data were used to estimate the cost of producing
methanol from western subbituminous coal using both dry cooling towers and other
water conservation measures to reduce the total water consumption to about 20% of
the normal requirement.
The Yellowstone River in southern Montana contains sufficient water for
extensive synfuels development; its' average stream flow is about 2000 x 10^ gallons
per year, large compared to the methanol plant requirement of 11 x 10^ gallons per
year. It goes close to the northern edge of a large subbituminous coal field, but many
acceptable mine locations would be located 40-70 miles away. Transportation could
raise the water cost to about $4.00 per 1,000 gallons and estimates were made based
on this figure with and without credit taken for CO2 sales. These can be compared to
the base case which has normal water usage, water cost at $1.15 per 1000 gallons, and
allows credit for CO2 sales. For these estimates, the coal price forecast termed "price
rises slowly1 was used.
The results, shown in Table 30, indicate that a large increase in water cost
causes only a slight increase in product price. For plants with normal water usage,
cases A and D, using high cost water increases the product price by less than 4 cents
per gallon. For plants with low water usage, the use of high cost water increases the
product price only about one cent per gallon, cases C and E. The cost attributed to
low water use ranges from 2 to 10 cents per gallon of product when water costs are
normal, cases A and B. Loss of CC>2 credits would increase costs about 9 cents per
gallon, cases B and C.
The effect that loss of credits for CO2 sales would have on the required selling
price was also calculated for production in the pertinent producing areas. The
calculations were made for 15% return on investment and for coal price projections
termed 'coal prices rises slowly'. The greatest effect was in the southern lignite
region for which some additional calculations were made using the other rates of
return. The results are shown in Table 31, and they again indicate the major effect
CO2 sales credits should have on methanol plant economics.
43
-------
TABLE 30. EFFECT OF VARIABLES ON PRICE OF METHANOL IN THE
WESTERN SUBBITUMINOUS REGION, 1984 $/GALLON
Return on Investment, %
Case Case Description 10 15 20 25
A Base case, normal water cost 2 credit
TABLE 31. EFFECT OF CARBON DIOXIDE SALES CREDITS
ON THE PLANT GATE METHANOL PRICE, 1984 $/GALLON
Case CO2 Credits No Co2 Credits
Eastern High Sulfur 0.790 0.806
Midwestern High Sulfur* 0.862 0.862
Western Subbituminous 0.527 0.615
Southern Lignite
Return on Investment, %
10 0.364 0.518
15 0.553 0.707
20 0.808 0.961
25 1.127 1.280
Nothern Lignite 0.699 0.801
* Credits for CO2 sales were not expected in the midwestern high-sulfur region, see
Tables 27 and 28.
Water supply is important for development in the western subbituminous region,
but it is not an impediment to development in any of the other regions. Reports by
the U.S. Water Resources Council (48) and by Scott, Pfeiffer and Gronhovd of North
Dakota State University (45) indicate adequate surface water supply for synfuel
development in most of the northern lignite mining region. Similarly, Smoller (49),
and Mathewson and Cason (50) report that both surface water supplies and shallow
44
-------
ground water supplies are adequate for extensive development in Eastern Texas and
Louisiana where the largest and highest quality portion of the southern lignite resource
is concentrated.
Eastern Low-Sulfur Coal
There are deposits of low-sulfur coal in the eastern part of the country which
could be used for methanol production. Many low-sulfur coal mines in the central
Appalachian mining region produce low-ash, high heating-value material. It tends to
be agglomerating in character, favorable for coke production. These properties make
the eastern low-sulfur coal very expensive, but also favorable for methanol production.
For coal gasification, coke is an undesirable product and agglomerating coals
cannot be used in some types of coal gasifiers. However, the entrained beds used for
the Texaco coal gasifiers can handle agglomerating coal. The low sulfur content
should allow reductions in the cost of acid gas removal equipment and eliminate the
need for flue-gas desulfurizers on the boiler. The low ash content would allow
operation with about 10% lower coal consumption for process feedstock than the
corresponding high-sulfur case. Similarly, the high heating value would allow about
25% lower consumption for utilities production, resulting in about 13% less coal
purchased than for the high-sulfur case.
Capital expenditures would be lower with low-sulfur coal. Based on
approximate material balances (not shown) about 10% savings were inferred for the
gasifier and coal preparation plant. Savings for acid gas removal would be about 35%
and for the sulfur plant about 75%. Flue gas desulfurization for the utility boiler
should not be required. There would be a very small savings, about 5%, for the oxygen
plant, but for other process modules costs would be about the same. Offsite savings
were estimated at 10%, mostly for reduced sulfur handling facilities. Capital
expenditures for the process modules and offsites together were estimated to cost \b%
less than for the eastern high-sulfur case. Capital expenditures for royalties,
chemicals and plant startup would be slightly less. The only area requiring a higher
capital expenditure was working capital which was higher because of the coal price.
For coal at $50 per ton, the working capital requirement was about 12% higher.
Coal was the dominating feature of the operating costs. Because of its high
value for both steam and coking purposes the price was estimated at $50 per ton.
45
-------
Water consumption and the cost of maintenance were each estimated to be about 10%
lower than for the high-sulfur case. It seemed unlikely that any income could be
obtained from carbon dioxide sales, and sulfur production was lower.
A plant-gate price for 15% return on investment was calculated for the eastern
low-sulfur case using the estimates discussed above. A plant location in Virginia was
assumed for state tax calculations. A coal price at $50 per ton is believed to be
reasonable, but to see the effect of coal price changes, an additional calculation was
made for coal at $70 per ton. The required methanol sales prices were $0.78 and
$0.87 per gallon respectively.
The price was not significantly different from the high sulfur case at $0.79 per
gallon. The high cost of coal tends to offset the benefits gained elsewhere in the
plant. If low-sulfur coal could be obtained for about $30 to $35 per ton, perhaps by a
plant-owned reserve which was easily mined, the methanol price would probably be
reduced to about $0.70 per gallon. However, eastern low-sulfur coal prices in that
range for 1990 and beyond should be regarded as fortuitous.
Methanol Cost Distribution
It is of interest to consider the contribution which different parts of the
methanol production process make to the plant-gate price. The coal-to-methanol
process can be divided into four major cost areas: coal purchase, coal gasification,
gas preparation, and methanol synthesis. The contribution to the plant-gate cost was
estimated for each area except for coal purchase by dividing the plant capital and
operating costs among the areas and calculating a product price for each. The
contribution of coal cost was estimated from the cases where calculations were made
for two different coal prices, with adjustments for differences in coal use and price
where needed.
Each of the plant cost areas included several process modules and related
operations. The coal gasification area included coal preparation, gasification, cooling,
ash and slag handling, and the oxygen plant. The gas preparation area included the
shift reaction, COS hydrolysis, acid gas removal, sulfur production, synthesis gas
purification in the guard bed, and flue-gas desulfurization at the boiler. Methanol
synthesis included gas recovery, methanol distillation and storage.
46
-------
Utilities and some operating costs were assigned in proportion to the process
module costs. Other operating costs which could be readily identified with plant areas
were assigned based on use as determined for the overall plant-gate price estimation.
For example, 67% of the chemical use was assigned to the methanol synthesis area.
All by-product credits were arbitrarily assigned to the gas preparation area.
Three cases were examined. The first case, shown in Figure 3, was for
midwestern high-sulfur coal feedstock. The second and third cases, Figures 4 and 5,
were for western low-sulfur coal feedstock with and without credit allowed for
carbon-dioxide sales. In all three cases, coal gasification was the major price
contributor, accounting for about half of the plant-gate price. For the western low-
sulfur coal, gas preparation was the least contributor to the price if carbon dioxide
sales credits were allowed, otherwise coal purchase was the least contributor.
Methanol synthesis was the least contributor in the midwestern high-sulfur coal case.
The fact that coal gasification is such a large contributor to the price indicates that
improvements in gasification economy would have a major effect on the plant-gate
methanol price.
COAL PURCHASE
COAL GASIFICATION
METHANOL SYNTHESIS
GAS PREPARATION
FIGURE 3. COST DISTRIBUTION FOR METHANOL PRODUCTION
IN THE MIDWESTERN HIGH-SULFUR COAL REGION
47
-------
COAL PURCHASE
METHANOL SYNTHESIS
COAL GASIFICATION
GAS PREPARATION
FIGURE 4. COST DISTRIBUTION FOR METHANOL PRODUCTION
IN THE WESTERN SUBBITUMINOUS COAL REGION
COAL PURCHASE
METHANOL SYNTHESIS
COAL GASIFICATION
GAS PREPARATION
FIGURE 5. COST DISTRIBUTION FOR METHANOL PRODUCTION IN THE
WESTERN SUBBITUMINOUS COAL REGION, ASSUMING NO CREDIT
FOR CARBON DIOXIDE SALES
48
-------
V. TRANSPORTATION COSTS AND DELIVERED PRICES
Transportation costs for bringing coal-derived methanol from mine-mouth plants
to the three representative delivery locations were estimated for readily available
means of transportation and for newly constructed pipelines. Three readily available
means of transportation were investigated:
o Existing product pipelines
o Barge service operating in the Great Lakes area, inland rivers and
tributaries, and surrounding coastal waters
o Unit train/railroad tanker
Existing Product Pipelines
There appears to be very little precedence in the industry in moving methanol
via existing product pipelines. Reasons for this condition, expressed by personnel at
the different pipeline companies contacted, are the effects that methanol would
produce on pipeline seals and valves due to its corrosive nature and the presence of
water in the pipelines. No one, however, ruled out the possibility of moving methanol
via pipeline in the future should demand and production increase. For the purpose of
this study, assuming that methanol were treated as other products moved via pipeline,
the present cost would average between $0.60 and $0.80 per thousand barrel miles.
While existing product pipelines are inexpensive means of transportation, they
have limited availability. The only line into the northern lignite region carries
liquefied petroleum gases, but the operating requirements for this type of line differ
significantly from lines carrying other liquid products, and it would be difficult to
adapt it for carrying methanol. There are no product lines in the western
subbituminous region, and very few between the southern lignite region and Chicago.
Most products from gulf coast refineries going to the Chicago area use water
transportation. Extensive, large product pipelines are in place from the gulf coast to
Atlanta and on to New York City, but these are very highly utilized. Since methanol
can replace gasoline only on about a 2 to 1 basis, pipeline transportation for only about
50% of the fuel methanol could be gained by assuming an equivalent quantity of
gasoline to be backed out of the market. With high pipeline utilization, questions
about methanol incompatibility, and lack of service to some of the less expensive
producing areas, the existing network of product pipelines at the time of this report
was assumed to be not readily available. The problems did not seem insurmountable,
and pipeline transportation was expected to become available in the future.
49
-------
Water and Rail Transportation
For water transportation of methanol, points of pick-up and delivery are limited.
For this study, the gulf coast area, the Chicago area, the eastern Ohio River, and New
York City could be used. There are no navigable water-ways near the northern lignite
or the western subbituminous regions. The southern lignite region is near, but not
adjacent to water transportation and rail transportation would be required for about
150 miles. Only the midwestern and eastern producing locations are adjacent to water
transportation. Telephone quotes obtained from several marine barge companies and
several railroads are summarized in Appendix C. The information was used as a basis
for estimating the transportation costs given in Table 32.
TABLE 32. ESTIMATED COSTS OF METHANOL TRANSPORTATION USING
READILY AVAILABLE MEANS, 1984 $/GALLON
Chicago New York City Atlanta
Eastern High-Sulfur Bituminous 0.113b 0.189a»b 0.142a
Midwestern High-Sulfur Bituminous 0.020b 0.085b 0.186a
Western subbituminous 0.396a 0.452 0.431a
Southern Lignite 0.125 0.125 0.208
Northern Lignite 0.353a 0.423 0.421a
a - rail transportation only
b - water transportation only
The routes used for making the estimates in Table 32 were those which appeared
to result in the lowest cost. Rail transportation is very expensive for short distances,
but the cost per mile goes down on very long routes. For example, rail costs from the
western subbituminous or northern lignite producing regions to the Mississippi River
are almost as high as rail costs direct to Atlanta. Only in the case of the southern
lignite could savings be realized by utilizing water transportation over part of a route
to Atlanta. New York City would receive all its supply by water transportation,
except for that produced in the eastern high-sulfur bituminous region, from where the
rail cost is about the same as the cost of barging it down the Ohio and Mississippi
Rivers and on around Florida. Production from the western subbituminous region
would go by rail to St. Louis, then utilize water transportation. It is possible to
transport by water from St. Louis to New York City via the Great Lakes, but the cost
is slightly more than twice the gulf coast route; however, in an actual case it may be
50
-------
the best route for destinations between eastern Michigan and western Pennsylvania.
Production from the northern lignite area would also travel by rail to the Mississippi
River, but the junction would vary with the season. Most of the time, water
transportation would begin in Minneapolis, but during the winter, rail transportation
could be required to as far south as St. Louis. Chicago could receive methanol by
water transportation from both the eastern and the midwestern high-sulfur regions.
For methanol produced in the western and the northern lignite regions, the rail cost
differential between the Mississippi River and Chicago is so small that it would be
impractical to make the transfer.
Transportation cost estimates show that three areas would have critical needs
for lower cost transportation. Costs are very high for western subbituminous and
northern lignite producing regions, and for the Atlanta consuming region.
New Pipeline Construction
New means of transportation could be very important to the development of a
coal-derived methanol industry. Newly constructed pipelines could provide
inexpensive transportation for regions where existing transportation methods were
lacking, or prohibitively expensive, and could affect the geographic distribution of a
future coal-to-methanol industry. To obtain an estimate of transportation costs using
a newly constructed pipeline, consultant services were purchased from the Williams
Brothers Engineering Company. They were asked to provide estimated capital costs,
operating and maintenance costs, and other economic data for two methanol-
compatible, pipeline systems. The northern pipeline system had two origin points, one
in the northern lignite region, and the other in the western subbituminous region.
Lines from each origin point met in South Dakota and continued as a single line to
terminals in Chicago and New York City. The southern pipeline system originated in
the southern lignite region and proceeded to terminals in Atlanta and New York City.
The Williams Brothers report is included in Appendix D.
The transportation costs were calculated using the computer program discussed
previously. A 20-year project lifetime was assumed, a cash outlay was taken the first
year for filling the line, and a cash recovery was taken the last year for recovering 90
percent of the line fill. Results are shown in Table 33, assuming 90% utilization, in
terms of barrel miles shipped.
51
-------
TABLE 33. ESTIMATED COSTS OF METHANOL TRANSPORTATION IN
NEWLY CONSTRUCTED PIPELINES, 1984 $/1000 BARREL MILES
Return on Investment, %
N.L.* - Junction
W.S.* - Junction
Junction - New York City
S.L.* - New York City
10
1.450
1.352
1.143
1.320
15
1.907
1.797
1.533
1.744
20 25
2.481 3.156
2.357 3.015
2.022 2.594
2.278 2.905
* Producing regions, N.L. = northern lignite, W.S. = western subbituminous, and
S.L. = southern lignite
The transportation costs calculated for 20% return on investment were used as
guidelines in estimating the transportation costs on a gallon basis given in Table 34.
They should be regarded as fairly low estimates because of the assumed 90%
utilization. While this is achieved in present products lines, it may be optimistic to
assume such a high utilization for pipelines dependent on a future industry. However,
even if the costs were to be 20 or 30% higher than in the above estimates, the savings
over the presently available means would be, in most cases, quite large.
TABLE 3*. ESTIMATED COSTS OF METHANOL TRANSPORTATION IN
NEWLY CONSTRUCTED PIPELINES, 198* $/GALLON
Producing Region Chicago
Eastern High-Sulfur Bituminous 0.020
Midwestern High-Sulfur Bituminous 0.015
Western Subbituminous 0.045
Southern Lignite 0.052
Northern Lignite 0.044
New York City Atlanta
0.022
0.048
0.081
0.082
0.079
0.031
0.023
0.080
0.040
0.075
It should be emphasized that the estimated costs in Table 34 are based on the
assumption that the pipeline would acquire the right of eminent domain. This allows
the pipeline owner to acquire pipeline right-of-way via condemnation proceedings if a
landowner refuses compensation for his property. Without the right of eminent
domain, the transportation costs would be higher than estimated and it is very possible
that difficulties in obtaining right-of-way could prevent pipeline construction entirely.
52
-------
Some other options are locally available which are attractive, but no attempt has
been made to estimate costs based on them. For example, a short pipeline connecting
a methanol producer in the southern lignite region to the nearest navigable waterway
should facilitate transportation to New York City at attractive rates. Similarly, a
pipeline from the Ohio River in western Pennsylvania may be able to follow existing
corridors to Cleveland and reduce transportation costs between the eastern high-sulfur
coal region and consumers near the Great Lakes. An existing crude oil pipeline was
built from North Dakota and adjacent parts of Canada to a refinery near Duluth when
expectations of crude oil production were greater than later realized. This line
probably has a low utilization, and it may become attractive to revamp it for methanol
carriage. Short additions to the line could bring it within easy reach of the northern
lignite region and some of the western subbituminous region.
Delivered Prices
The plant-gate costs, the transportation costs, the effects of plant designs
allowing reduced water consumption in the western subbituminous region, and the
effects of by-product credits were used to estimate delivered prices. The geographic
distribution of plant locations was modeled based on delivered price and an arbitrary
demand limit for each of the consuming locations. The total demand limit was set at
100 x 106 gallons per day proportioned among the three consuming locations relative
to the regional gasoline sales during 1982 and 1983. Figure 6 shows the producing
locations, the representative consuming locations and the states used for each of the
regional sales compilations. This procedure yielded the following regional demand
limits in millions of gallons per day:
Demand Limit, Million Gallons Per Day
Chicago 36.7
New York City 36.3
Atlanta 27.0
The lowest delivered prices provided the basis for plant location. The lowest
price to any location was found first, then the next lowest, until the demand limit had
been reached in each region. The plant-gate costs for 15% return on investment and
the coal cost forecast labeled 'coal cost rises slowly' were used in determining the
delivered prices.
-------
Producing Location
Consuming Location
; / W ! !
^'7;r—j / Western ! i
, **DA Tfi-~..j Subbituminous KwZir —-J
FIGURE 6. MAP SHOWING PROJECTED METHANOL PRODUCING REGIONS AND
REPRESENTATIVE CONSUMING LOCATIONS WITH THEIR ASSOCIATED AREAS
54
-------
The number of plants producing at the lowest price in each location was limited
by the expected sales of carbon dioxide shown in Table 28, and by water supply
limitations in siting plants in the western subbiluminous region. Delivered prices
differing by less than five cents per gallon were regarded as equivalent and the amount
of methanol was divided equally.
Results for the readily available means of transportation are shown in Table 35.
The geographic distribution of methanol plants shows production concentrated heavily
in the southern lignite region with 34 plants and 72% of the total production. There
were no plants in the northern lignite region because the plant-gate costs were higher
than other western production and transportation costs were too high to compete with
eastern and midwestern production.
TABLE 35. DELIVERED METHANOL PRICES USING BEST ESTIMATE OF WATER
AVAILABILITY, AND READILY AVAILABLE TRANSPORTATION, 198* $/GALLON
Producing Region
Southern Lignite
Southern Lignite
Midwestern Bituminous
Southern Lignite
Eastern Bituminous
Eastern Bituminous
Western Subbituminous
No.
of
Plants
10
18
6
6
4
1
2
Plant-Gate
Cost,*
$/Gal.
0.553
0.707
0.707
0.862
0.707
0.790
0.806**
0.527
Sales,
106 Gal./
Day
10.5
10.5
25.2
12.6
12.6
12.6
8.4
2.1
4.2
Chicago
Cost
$/Gal.
0.695
—
0.849
0.882
-
-
-
_
N.Y.C.
Cost
$/Gal.
0.678
-
0.832
-
-
-
-
—
_
Atlanta
Cost
$/Gal.
-
—
-
-
0.915
0.932
0.948
0.958
* Assumes 15% return on investment and coal costs that rise slowly.
** The higher cost on this line is due to loss of credits for CO2 sales.
For newly-constructed pipelines, two development models were considered for
the western subbituminous region based on water limitations. The first model
represented the best estimate of water availability, and two plants were allowed with
normal water use, four plants with low water use but normal water price, and an
55
-------
unrestricted number with both low water use and high water price. The results, shown
in Table 36, indicate production concentrated in the western subbituminous region.
Plants are also located in the southern and northern lignite region, but their numbers
were nearly limited to the number of plants with a CO2 market.
TABLE 36. DELIVERED METHANOL PRICES USING BEST ESTIMATE OF WATER
AVAILABILITY, AND NEWLY CONSTRUCTED PIPELINE TRANSPORTATION,
198* $/GALLON
Producing Region
Western Subbituminous
Southern Lignite
Western Subbituminous
Western Subbituminous
Western Subbituminous
Southern Lignite
Northern Lignite
No.
of
Plants
Plant-Gate Sales, Chicago N.Y.C. Atlanta
Cost,* 106 Gal./ Cost Cost Cost
10
23
4
5
$/Gal.
0.527
0.553
0.567
0.655**
0.662
0.707
0.699
Day
1.4
1.4
7.0
7.0
7.0
0.7
0.7
0.7
2.1
2.1
2.1
21.3
5.1
21.9
8.4
3.5
3.5
3.5
$/Gal. $/Gal. $/Gal.
0.572
0.605
0.612
0.700
0.707
0.608
0.635
0.648
0.736
0.743
0.607
0.593
0.743
0.647
0.735
0.742
0.747
0.774
0.778
* Assumes 15% return on investment and coal costs that rise slowly.
** The higher cost on this line is due to loss of credits for CO2 sales.
The second development model for the western subbituminous region assumed
more stringent restrictions on development. No plants were allowed with normal
water use, three plants were allowed with low water use but normal water prices, and
only seven additional plants were allowed with low water use and high water prices.
As shown in Table 37, these restrictions caused two concentrated areas of production;
besides the 10 plants in the western subbituminous region, 21 plants would be located
56
-------
in the southern lignite region. Only eight plants would be located in the northern
lignite region and four in the eastern bituminous region. With either of the
development models for the western subbituminous region, the existence of
inexpensive pipeline transportation would prevent midwestern production from
competing effectively and would severely limit eastern production.
TABLE 37. DELIVERED METHANOL PRICES USING NEWLY CONSTRUCTED
PIPELINE TRANSPORTATION, WESTERN DEVELOPMENT RESTRICTED
BY WATER AVAILABILITY, 1984 $/GALLON
Producing Region
Southern Lignite
Western Subbituminous
Western Subbituminous
Northern Lignite
Southern Lignite
Eastern Bituminous
Northern Lignite
No.
of
Plants
10
Plant-Gate Sales, Chicago N.Y.C. Atlanta
11
Cost,
$/Gal.
0.553
0.567
0.662
0.699
0.707
0.790
0.764
106 Gal./ Cost Cost Cost
Day $/Gal. $/Gal. $/Gal.
7.0
7.0
7.0
2.1
2.1
2.1
4.9
4.9
3.5
3.5
3.5
9.9
6.5
6.5
4.2
4.2
8.4
8.4
0.593
0.605
0.612
0.707
0.743
0.759
0.810
0.808
0.635
0.648
0.743
0.778
0.789
0.812
0.843
0.647
0.742
0.774
0.747
Credit for CO2 sales, as shown in Table 31, made a significant effect on the
plant-gate methanol price. The effect was greatest in the regions where most of the
plants were located as portrayed in the above tables. The loss of credit for CO2 sales
was examined to see how plant siting would be affected. The results are shown in
Tables 38 through 40.
57
-------
There were few changes in the pattern of plant siting and delivered costs for the
case using readily available transportation. There were 33 plants with 70% of the
total production in the southern lignite region, and no plants in the western
subbituminous region. A comparison of Tables 38 and 35 shows that three plants lost
in those regions were gained by the eastern and midwestern bituminous regions. The
lowest delivered prices were higher without the CO2 credits, but the highest prices
were about the same because of the expected market limitations for the CO2 where
credit was taken.
TABLE 38. DELIVERED METHANOL PRICES USING BEST ESTIMATE OF WATER
AVAILABILITY, READILY AVAILABLE TRANSPORTATION, AND NO CO2 SALES
CREDIT, 1984 $/GALLON
Producing Region
Southern Lignite
Midwestern Bituminous
Southern Lignite
Eastern Bituminous
For the case of newly constructed pipeline transportation and best estimate of
water availability there was a shift in plant siting from both lignite regions toward the
western subbituminous region. With credit for CO2 sales, Table 36, the combined
lignite regions had 19 plants and 40% of the total production. Without credit for CO2
sales, Table 39, there were only eight plants with 17% of the total production, all
located in the southern lignite region. The remaining 83% was in the western
subbituminous region.
When western development was restricted by water availability, the plant siting
was shifted back toward the southern lignite region. With western development
restricted, Table 40, the southern lignite region had 31 plants and 65% of the total
production. The loss of credits for CO2 sales resulted in the loss of all 13 plants shown
in the northern lignite region in Table 37. The southern lignite region gained 10 plants
and the eastern bituminous region gained three plants.
58
No.
of
Plants
26
8
7
6
Plant-Gate
Cost
$/Gal
0.707
0.862
0.707
0.806
Sales
106 Gal./
Day
36.3
18.9
16.8
14.7
12.6
Chicago N.Y.C.
Cost Cost
$/Gal $/Gal
0.832
0.832
0.882
-
— —
Atlanta
Cost
$/Gal
-
0.915
0.948
-------
TABLE 39. DELIVERED METHANOL PRICES USING BEST ESTIMATE OF WATER
AVAILABILITY, NEWLY CONSTRUCTED PIPELINE TRANSPORTATION, AND NO
CO2 SALES CREDIT, 1984 $/GALLON
Producing Region
Western Subbituminous
Western Subbituminous
Western Subbituminous
Southern Lignite
No.
of
Plants
34
Plant-Gate
Cost
$/Gal
0.615
0.655
0.662
0.707
Sales Chicago N.Y.C. Atlanta
106 Gal./ Cost Cost Cost
Day $/Gal $/Gal $/Gal
I A
I A
2.8
2.8
2.8
32.5
22.8
16.1
16.8
0.660
0.700
0.707
0.696
0.736
0.743
0.789
0.695
0.735
0.742
TABLE *0. DELIVERED METHANOL PRICES USING NEWLY CONSTRUCTED
PIPELINE TRANSPORTATION, WESTERN DEVELOPMENT RESTRICTED BY
WATER AVAILABILITY, AND NO C&2 SALES CREDIT, 198* $/GALLON
Producing Region
Western Subbituminous
Western Subbituminous
Southern Lignite
Eastern Bituminous
Future Prices
Early in 1984 it was necessary to estimate the inflation rate between 1983 and
1984 to express plant-gate costs in 1984 dollars. At that time the inflation rate was
expected to be about 10%. Toward the end of the project, that figure appeared to be
high, and the real inflation rate was probably closer to 4%. If the 4% figure is proven
correct, the correction factor 0.945 should be applied to prices reported here in 1984
dollars.
No.
of
Plants
3
7
31
7
Plant-Gate
Cost
$/Gal
0.655
0.662
0.707
0.806
Sales
106 Gal./
Day
2.1
2.1
2.1
4.9
4.9
4.9
20.0
29.7
14.6
14.7
Chicago
Cost
$/Gal
0.700
0.707
0.759
_
N.Y.C.
Cost
$/Gal
0.736
0.743
0.789
0.828
Atlanta
Cost
$/Gal
0.735
0.742
0.747
_
59
-------
Several factors, such as the high federal budget deficit, which were related to
high inflation rates were still present in 1984. The inflation rate was expected to
increase, but because of changes in monetary policy by the Federal Reserve Board, it
was not expected to return to the high rates experienced in the late 1970's. An
inflation rate at 5% was projected for 1985 and 6% for the years 1986-1990.
The inflation rate was expected to be quite uniform. No reasons were found to
expect differences in the inflation rate among the different coal producing regions. In
1984, crude oil prices appeared to be quite stable, which would imply a slightly lower
inflation rate for transportation than for production, but not enough to alter the
conclusions reached in this study. However, for the past few years, long term crude
oil price forecasts had gone awry, and events in the Middle East were still seen as
capable of causing big changes in both price and supply. Such changes would, of
course, affect the transportation costs much more than the methanol production costs.
Assuming stability in crude-oil prices, the factor 1.328 should be used to convert 1984
dollar prices as reported here to 1990 dollar prices.
60
-------
VI. CONCLUSIONS
1. Based on the assumptions made in this study, methanol can be produced
from coal in the southern lignite and western subbituminous regions at
lower cost than in the eastern and midwestern bituminous coal regions.
Costs in the northern lignite region would be about midway between the
others.
2. Without pipelines, the presently available transportation to major market
areas is more expensive for production in the western subbituminous and in
the northern lignite regions than for other producing regions. The
presently available transportation is also more expensive for delivery in the
Atlanta market area than for the Chicago or New York City market areas.
3. For the production and transportation costs projected in this study, and
using presently-available, non-pipeline transportation, the delivered prices
of methanol would favor industry development in the southern lignite
region.
4. With presently-available, non-pipeline transportation, utilization of
methanol fuel would be favored in the New York City and Chicago areas
over the Atlanta area. This result occurs because Atlanta, unlike most
major cities in the other regions, is not adjacent to water transportation,
however several other cities in the area such as Mobile, Miami, and
Charleston are adjacent to water, so this result does not apply over the
whole area.
5. This study indicates that new pipeline construction, requiring the right of
eminent domain, could provide a significant reduction in the delivered
methanol price. New pipelines would be particularly useful to serve the
western subbituminous and northern lignite producing regions, and the
Atlanta market area. If these pipelines were constructed, delivered prices
would favor industry development in the western subbituminous producing
region and utilization of the methanol fuel would not be favored in any
market area over other areas.
61
-------
6. The analyses of water resources presented here indicates that water
availability will not prevent development of a coal-to-methanol industry in
the western subbituminous region, but it will make siting more difficult. A
detailed water plan must be given high priority in western siting
considerations, and it may still be necessary to pay high prices for water,
or to transport it a considerable distance. However, if water were much
more expensive the cost of methanol would only be slightly higher. The
use of dry cooling towers and other similar measures to conserve water
would also make the methanol slighty more expensive. However, neither
high-cost water nor water conservation were expected to cause a methanol
price high enough to change the western regions' favorable economic
position relative to other producing regions.
7. No major siting limitations were found for any producing region except the
water supply in the western subbituminous region.
8. Carbon dioxide has potential as an important by-product in areas where it
could be used for enhanced oil recovery. Credits for its sale could have a
major effect on the required methanol selling price in the southern lignite,
the western subbituminous, and the northern lignite regions. The loss of all
credits for CO2 was found to have little or no impact on plant siting if the
industry relies on presently available transportation without pipelines. If
new pipelines were extensively available, the loss of CO2 credits would
result in delivered methanol prices which should favor industry
development in the western bituminous region. If western development
were restricted, the southern lignite region would be favored. For
individual plants, the possibility of CC>2 sales merits serious consideration
and careful study.
62
-------
REFERENCES
1. BDM Corp. "Coal Gasification Systems Engineering and Analysis," Volume 2,
Final Report, 1980, Report No. NASA-CR-16165*.
2. Simbeck, D.R., Dickenson, R.L., Oliver, E.O, (Synthetic Fuels Associates) "Coal
Gasification Systems: A Guide to Status, Applications, and Economics," Electric
Power Research Institute, Palo Alto, CA, 1983, (Report No. AP-3109).
3. Hartmann, 3.3., Matchak, T.A., Sipe, H.E., Wu M. (Fluor Engineers Inc.) "Shell
Based Gasification-Combined Cycle Power Plant Evaluations," Electric Power
Research Institute, Palo Alto, CA, 1983, (Report No. AP-3129).
*. BDM Corp. "Coal Gasification Systems Engineering and Analysis. Appendix A:
Coal Gasification Catalogue," Final Report, 1980, Report No. NASA-CR-161655.
5. BDM Corp. "Coal Gasification Systems Engineering and Analysis. Appendix G:
Commercial Design and Technology Evaluation," Final Report, 1980, Report No.
NASA-CR-161661.
6. Schwartz, C.W., Rath, L.K., Freier, M.D., (Westinghouse Electric Corp.) "The
Westinghouse Gasification Process," Chemical Engineering Progress, April 1982,
p.55.
7. Sun Tech Inc. "Assessment of Ether and Alcohol Fuels from Coal," Volume 2,
1983, U.S. Department of Energy Report No. DOE/CS/54045-2.
8. Wentworth, T.O. and Othmer, D.F., "Producing Methanol for Fuels," Chemical
Engineering Progress, p 29, (August 1982).
9. Wham, R.M. and Forrester, R.C. Ill, "Available Technology for Indirect
Conversion of Coal to Methanol and Gasoline: A Technology and Economics
Assessment," presented at the Third Miami International Conference on
Alternative Energy Sources, Dec. 15-18, 1980.
10. "Petrochemical Handbook," Hydrocarbon Processing 62 (11), 111-113, (Nov.
1983).
11. Wham, R.M. et al, "Liquefaction Technology Assessment, Phase 1: Indirect
Liquefaction of Coal to Methanol and Gasoline Using Available Technology," Oak
Ridge National Laboratory, Report No. ORNL-566*, Feb. 1981, p 1*3.
12. Simbeck, D.R. and Dickenson, R.L., "Methanol from Coal: Making the Best
Choice," Proceedings Fifth International Alcohol Fuel Technology Symposium,
Vol. 1, Auckland, New Zealand, 1982, pp 1-261 through 1-268.
13. Nielsen, G.F. (Ed.) U.S. Coal Mine Production by Seam - 1976, Mining
Informational Services, Keystone Coal Industry Manual, McGraw-Hill, NY, 1977.
1*. Retcofsky, H.L. and Hough, M.R., "Nature of the Free Radicals in Coals,
Pyrolyzed Coals, and Liquefaction Products," American Chemical Society,
Division of Fuel Chemistry Preprints, 2*, (1), 83 (1979).
63
-------
15. Nielsen, G.F. (Ed.) 1981 Keystone Coal Industry Manual, Mining Informational
Services, Keystone Coal Industry Manual, McGraw-Hill, NY, 1982.
16. HNG Synfuels Co. and Texaco Inc. "Convert Synfuels Project Feasibility Study
Coal to Methanol," DOE Report No. DE-FG-1-80RA-50337, 31 December 1980,
p. 5.
17. 3ohanson,E., (Hydrocarbon Research Inc.) "Solvent Refining of Wyodak, Illinois
No. 6 (Monterrey Mine) and Black Mesa Coals," Volume 2. EPRI Report No. 389,
Electric Power Research Institute, Palo Alto, CA, 1976, pp 12, 198.
18. Boley, C.C., Fegley, M.M., "Design and Operation of Two Refractory-Lined
Internally Heated, Entrained-Bed Carbonizers," DOE Report No.
GFERC/RI77/1, Grand Forks Energy Research Center, Grand Forks, ND, 1977,
p9.
19. Bouchillon, C.W., et al, "Evaluation of the Micropulverization, Drying and
Beneficiation of Lignite," Conference Proceedings, 6th International Coal
Utilization Exhibition and Conference, Houston, TX, Nov. 1983, Vol. VI, Lignite
Development and Utilization, p. 295.
20. Rudd, D.F., and Watson, C.C., Strategy of Process Engineering, Wiley, New
York, 1968, pp 115-124.
21. Rubin, E.S., Bloyd, C.N., and Molburg, 3.C., "Models of Air Pollution Control
Costs for Coal-to-Electricity Systems," Fifth International Coal Utilization
Exhibition and Conference, Houston, TX 7-9 Dec., 1982, Proceedings Volume 3,
pp 189-208.
22. Buckingham, P.A., Cobb, D.D., Leavitt, A.A., Snyder, W.G., (Fluor Engineers and
Constructors, Inc.) "Coal to Methanol, An Engineering Evaluation of Texaco
Gasification and ICI Methanol-Synthesis Route," EPRI Report No. AP-1962,
Electric Power Research Institute, Palo Alto, CA, 1981, p 6-13 through A-15.
23. Fluor Engineers and Constructors Inc., "Crow Tribe of Indians Synfuels
Feasibility Study," Vol. II, Book III, Department of Energy Report No.
DOE/RA/50351-1300, pp 6-910 through 6-920.
24. New York State Energy Research and Development Authority, "Low/Medium BTU
Coal Gasification Assessment Program for Specific Sites of Two New York
Utilities," Albany, 1980. Department of Energy Report No. DOE/FE/20223-2.
25. Fluor Engineers and Constructors "Dunn-Nokota Methanol Project, Dunn County,
North Dakota, Volume II, Preliminary Plant Design and Cost Estimate," Irvine,
CA, 1982, Department of Energy Report No. DOE/RA/50362-1395-Vol. 2-Pt. 2.
26. Hyder, D.A. (Burns and ROE), Ku, W.S., Piascik, T.M., (Public Service Electric &
Gas Co), District Gasification in New 3ersey," Fourth International Coal
Utilization Exhibition and Conference, Houston, TX, 17-19, Nov. 1981,
Proceedings Volume 4, 329-352.
27. Fluor Engineers L Constructors "Coal Liquefaction Technology Assessment
Phase 1," Department of Energy Report No. ORNL/SUB-80-/24707, pp 315-331.
64
-------
28. Ulrich, W.C., Edwards, M.S. and Salmon, R., "Evaluation of an In-Situ Coal
Gasification Facility for Producing M-Gasoline via Methanol," Department of
Energy Report No. ORNL/5439, pp 85-98.
29. Badger Plants Inc., "Conceptual Design of a Coal-to-Methanol-to-Gasoline
Commercial Plant, Volume 1, Technical," Second Interim Final Report, Aug. 31,
1977 - Mar. 1, 1979. Department of Energy Report No. FE-2416-43 (Vol. 1), pp
173-179.
30. Energy Information Agency, DOE, "1981 Annual Report to Congress," EIA,
Volume 3, May 1982, pp 27-28. See also recent issues of Monthly Energy Review,
DOE/EIA-0035, Energy Information Agency, Washington, DC.
31. BDM Corp., "Coal Gasification Systems Engineering and Analysis. Appendix E:
Cost Estimation and Economic Evaluation Methodology," Final Report, 1980,
Report No. NASA-CR-161659.
32. Burns and Roe Industrial Services, "Low/Medium BTU Coal Gasification -
Assessment Program For Potential Users in New Jersey," Burns and Roe,
Parancus, N3 1981. Department of Energy Report No. DOE/FE/20216-2.
33. Ebasco Services, Inc., "Feasibility Study Gasoline From Coal in the State of
Illinois, Volume II Cost-Site-Environmental-Planning," Department of Energy
Report No. DOE/RA/50326-1145, Vol. 2.
34. Pritchard, Corporation, "Underground Coal Gasification (UCG) Gas to Methanol
and MTG-Gasoline: An Economic and Sensitivity Study," Pritchard Corporation,
Kansas City, 1982. Department of Energy Report No. UCLR-15510.
35. Anada, H., King, D., Seskus, A., Fraser, M. (Science Applications Inc.) and Sears,
3., (West Virginia University), "Feasibility and Economics of By-Product CC>2
Supply for Enhanced Oil Recovery," Volume 1, Technical Report, U.S.
Department of Energy Report No. DOE/MC/08333-3 (Vol. 1), 1982.
36. Watts, R.3., Gehr, 3.B., Wasson, 3.A., Evans, D.M., and Locke, C.D., "A Single
CO2 Injection Well Minitest in a Low Permeability Carbonate Reservoir,"
3ournal of Petroleum Technology, 34(8), 1781 (Aug. 1982).
37. Kuuskraa, V.A., Hammershaimb, E.G., Morra, F., and Wicks, D. (Lewin and
Assciates Inc.), "Technical and Economic Potential of Enhanced Oil Recovery in
Appalachia," Presented at the Eastern Regional Meeting of the Society of
Petroleum Engineers, 4-6 Nov. 1981, Columbus OH. Paper No. SPE 10373,
Society of Petroleum Engineers of AIME, Dallas, 1981.
38. Leonard, 3., "EOR Set to Make Significant Contribution," Oil and Gas 3ournal
82(14), 83 (April 2, 1984).
39. Matheny, S.L. 3r., "EOR Methods Help Ultimate Recovery," Oil and Gas 3ournal
78(13), 79 (Mar. 31, 1980).
40. McRee, B.C., "CO2: How It Works, Where It Works," Petroleum Engineer,
49(11), 52 (Nov. 1977).
65
-------
41. Congelline, R.H., "Correcting Economic Analyses," Chemical Engineering 77
(23), 109 (Nov. 16, 1970).
42. Anderson, E.V., "Large Volume Fuel Market Still Eludes Methane!," Chemical and
Engineering News, July 16, 1984, pp 9-16.
43. U.S. Office of Technology Assessment "Increased Automobile Fuel Efficiency
and Synthetic Fuels: Alternatives for Reducing Oil Imports. Background
Paper 5. Water Availability for Synthetic Fuels: An Assessment of Current
Studies," NTIS No. PB83-152645, 1981.
44. Hickcox, D.H. "The Impact of Energy Development in the Tongue River Basin,
Southeastern Montana," Water Resources Bulletin, _18(6), 941 (Dec. 1982).
45. Scott, D.F. Pfeiffer, G.H., and Gronhovd, D.E., "Water as a Parameter for
Development of Energy Resources in the Upper Great Plains - Effects on Land
and Water Resources of Alternative Patterns of Coal-Based Energy
Development," North Dakota Agricultural Experiment Station Research Report
No. 70, North Dakota State University, Fargo, ND 1978.
46. Ricker, D.A., Ulman, W.3., Hampton, E.R., (Eds), "Synthetic Fuels
Development - Earth Science Considerations," U.S. Department of the
Interior/Geological Survey, Washington, D.C., 1979.
47. Larinoff, M.W. "Performance and Capital Costs of Wet/Dry Cooling Towers in
Power Plant Service," in Waste Heat Management and Utilization Vol. 2 Ed:
Samuel S. Lee and Subrata Sengupta, Hemisphere, Washington, Proc. Conf. 9-11
May 1977, Miami Beach, FL, 1977, pp 687-714.
48. U.S. Water Resources Council "Synthetic Fuel Development for the Upper
Missouri River Basin, Section 13(a) Water Assessment Report," U.S. Water
Resources Council, Washington, 1981.
49. Smoller, R.K., "Gasification of Gulf Coast Lignites," Sixth International Coal
Utilization Exhibition and Conference, Houston, TX, 15-17 November 1983,
Proceedings Volume 5, pp 117-124.
50. Mathewson, C.C., and Cason, C.L., "Evaluation of the Impact of Texas Lignite
Development on Texas Water Resources," Technical Report No. 108, Texas
Water Resources Institute, Texas A&M University, 1980.
66
-------
APPENDIX A
Program for Calculating Sales Price and Return on Investment
-------
APPENDIX A
PROGRAM FOR CALCULATING SALES PRICE AND RETURN ON INVESTMENT
LANGUAGE; BASIC/1. 00 DC
10
20
25
30
35
40
0041
0042
45
50
55
60
65
7(1
*7r-"
no
101
1.02
1.1.0
115
1.25
130
135
140
1.45
1.50
155
160
165
170
175
180
185
190
199
200
205
210
214
21.5
216
220
225
230
DIM A*[701,Cf(60),Co<60),DfT(50),Dp<60),Ccf(60)
DIM Ebt(60>,Ex(60),FiT<60>,Dcp<60>,DcT(2Q,100>
DIM Pv(60), Pvf(60>, Ro.t(60), Rrpv (60 ) , Fp ( 60 )
DIM Sit(60),Sp(60)?Tpw(60),Ti(60),Up(60),Bpis(60),Bp2s(60)
DIM Rcsti(60),Rcst2(AO),RcsT3(60),RMtc(60),Rn2c(60>,RM3r(60)
DIM RMia(60> ,Rh2a<60) , RM,3a(60> ,Ut<60) , l..a(60> ,Ma(60),Ilt(60>
DIM Otc(60),Bpip(60>,Bpta(60),Bp2p(60), Bp2a(60>,Rpi(60)
DIM Rp2(60),Rp3(60),Utp(60),L.ap(60),Map(60),Htp(60),Otp(60)
DIM Bppl(60),Bpp2(60),0pp(13>,Sitp(60),Fitp(60)
PRINT "THIS PROGRAM CALCULATES EITHER RETURN ON INVESTMENT OR
PRINT "REQUIRED SALES PRICE THE FIRST PART OF THE
PRINT "REQUESTS INPUTS AFTER THEY ARE ENTERED YOU
"PINT "A CHANCE TO REVIEW AND CORRECT THEM
PROGRAM "
WILL HAVE
PRINT
r.:n<"-im
GO SUP
nrjSi.j^
COS! IP
TF K'l;
360
380
710
BOS
935
< 5 " r
4 5 0 0
TF E* = "C" THEN
C,GSUF( 1090
1 = 1.
GOSUB 1115
GO SUB 1.205
IF I>i THEN .1.55
! NAME INPUT
! PROJECT COST AND TIME INPUTS
TAX JNF'O INPUTS
ROI INFO INPUTS
Oi'F-RAIING EXPENSE INPUTS
EDIT Al. I. INPUTS
r x EB . vALLIi-! FuC " i'.iR •!>
(FIRST SALES PRICK EST.)
(EARN, TAX, CASH FLOW) + (SUM RETURN)
(NFU SALES ESTIMATE)
GOSUB 1530
GOTO 130
IF APS (Up ( I) --UoCI '--I i >< Spa*Up(I) THEN 346
IF I>3 THEN :i.:iu
1 = 1 + 1
GOSUB 1530 i (NEW SALES ESTIMATE)
GOTO 130
Ds3=ABS(Up(I~3)-Up(I-2> )
Ds2 = ABS(Up(I-2)-Up(I-l> )
Dsl = ABS(Up Ds2 OR Ds3 > Dsi THEN 1.40
PRINT " SUCCESSIVE CALCULATIONS DO NOT IMPROVE "
PRINT " THE SOLUTION. THESE PRICES WERE TRIED: "
FOR L = i TO I
FIXED 6
PRINT " SALES PRICE TRIAL ";!...;" WAS "; Up(L) ; "PER" jG*
FIXED 0
NEXT I...
PRINT " DO YOU WISH TO PRINT THE OUTPUT (Y) "
PRINT " OR QUIT WITH NO OUTPUT (N)? CHOICE Y EVENTUALLY ALLOWS A RERUN.
A-2
-------
235
240
245
THEN BOOO
255
260
265
270
275
280
285
290
295
300
305
310
315
320
325
330
335
340
345
346
347
350
360
365
370
375
380
385
390
395
400
405
41.0
415
420
425
430
435
440
445
450
455
460
465
470
47S
480
4H5
490
49S
500
505
507
510
515
520
525
535
538
540
545
550
! EARNINGS, TAX •»• CASH FLOU
(INITIAL EST. RATE OF RETURN
CALC. PRESENT VALUE FACTORS
PRESENT VALUES AND SUMS
THEN 330
Roid)
i
! CALC.
INPUT F$
IF F$ = "N
GOTO 346
GOSUB 1205
GOSUB 1475
1 = 0
Roid) = Roip
GOSUB 1090
GOSUB 1445
RrpM(I) = Tpw(Pl)
IF I<2 THEN 300
Dv = ABS(Rrpvd)-Rrpvd-i))
IF Dw > ABS(Rrpvd) + Rrpvd-D)
1 = 1 + 1
IF Rrpwd-1) > 0 THEN 320
Roip = R o i(I-i)-i
GOTO 265
Ro.ip = Roid-1) + 1
GOTO 265
Roip = (Rrpvd)/Dv>
GOSUB 1090
GOSUB 1445
GOSUB HIS
IF K* <> "
GOSUB 4400
GOSUB 2040
PRINT
PRINT
INPUT A*
RETURN
PRINT " ENTER THE TOTAL PROJECT COSTS "
INPUT PC
PRINT " ENTER TOTAL YEARS FOR PROJECT LIFE,
PRINT " INCLUDING CONSTRUCTION YEARS "
INPUT PI
PRINT " ENTER TOTAL YEARS FOR CONSTRUCTION "
INPUT Cy
Ydl = Cy + i
GOSUB 595 .! DEPRECIATION INPUTS
RETURN
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
FOR Y
PRINT
FINAL ROI INTERPOLATION
CALC. PRESENT VALUE FACTORS
PRESENT VALUES AND SUMS
! FOR ONLY THE PRESENT VALUE OF CASH OUTLAYS
THEN 350
! FOR OPERATING EXPENSE Y. BY CATEGORY
! PRINT OUTPUTS (END OF MAIN PROGRAM).
" ENTER NAME OF PROJECT AND/OR CASE NUMBER "
11 70 CHARACTERS MAX "
CONSTRUCTION SCHEDULE ENTRIES "
ENTER PERCENT SPENT IN EACH CONSTRUCTION YEAR-
i TO Cy
PERCENT SPENT IN YEAR
INPUT Cp(Y)
Co(Y) = (Pc*Cp(Y) >/100
NEXT Y
PRINT " FOR HOU MANY OTHER YEARS WILL THERE "
PRINT " BE. CASH OUTLAYS OR RECOVERIES ? (MAXIMUM = 20) "
INPUT Yco
FOR Z = i TO Yco
PRINT " ENTER A YEAR NO., IT'S NET CASH OUTLAYS, "
PRINT " AND IF NOT DEPRECIABLE, THE LETTER N."
PRINT " (FOR EXAMPLE 17,12900,N). USE A - SIGN FOR CASH
PRINT " RECOVERIES, (FOR EXAMPLE 35,-52500, ) "
INPUT Y,C,Dep*
Co(Y) = C
IF C<0 OR Dep*="N" THEN 560
Ya = Y + Tdy
FOR Yy = Y TO Ya
Aa = Yy - Y + Yd!
Dct(Z.Yv) = C*(Dp(Aa>/100)
A-3
-------
555
SAO
565
570
575
580
585
590
595
600
605
610
615
620
625
630
635
640
645
650
655
660
665
670
675
680
685
690
695
700
705
710
715
725
730
735
740
745
755
760
765
770
775
781
784
785
790
795
800
805
810
815
820
825
830
835
840
845
850
855
860
865
870
875
880
NEXT Yy
NEXT Z
FOR Y = Yd I TO PI
FOR DC = 1 TO Yc:o
Dft(Y) = Dft(Y) -f Dct(Dc,Y)
NEXT DC
NEXT Y
RETURN
PRINT " ENTER COST OF DEPRECIABLE ASSETS "
INPUT Da
PRINT " ENTER NUMBER OF YEARS FOR TAX DEPRECIATION "
PRINT " AFTER END OF CONSTRUCTION "
INPUT Tdy
PRINT " IS TAX DEPRECIATION STRAIGHT LINE ? Y OR N "
INPUT D*
Yde = Cy -f Tdy
IF D* = "N" THEN 665
FOR Y = Yd! TO Yde
Dft(Y) = Da/Tdy
Dp(Y) = 100/Tdy
NEXT Y
GOTO 700
PRINT " ENTER PERCENT DEPRECIATED EACH YEAR "
PRINT " STARTING WITH THE YEAR AFTER CONSTRUCTION ENDS '
FOR Y = Ydl TO Yde
PRINT " PERCENT DEPRECIATED IN YEAR ">Y>" = "
INPUT Dp(Y)
Dft(Y) = = 0 THEN 755
Ftr = (VAL(C*>)/100
Str = 0
PRINT " ENTER PERCENT STATE CORPORATE OR FRANCHISE "
PRINT " TAX RATE (DEFAULT IS OX). IN THIS PROGRAM "
PRINT " FEDERAL TAX IS NOT A STATE TAX DEDUCTION "
INPUT Strp
Str = Strp/ 1.00
PRINT
PRINT " ENTER THE PERCENT INVESTMENT TAX CREDIT "
PRINT " APPLICABLE (FEDERAL) - NOT APPLIED TO CASH OUTLAYS FOLLOWING
PRINT " THE INITIAL CONSTRUCTION"
INPUT Itcp
RETURN
PRINT " IS RETURN ON INVESTMENT TO BE CALCULATED 100 THEN Spap =100
Soa = Snao/100
A-4
-------
885 PRINT " ENTER ANNUAL SALES VOLUME,UNITS. FOR EXAMPLE— 185,TON"
890 INPUT Sv, G*
89S IF E* = "S" THEN 980
900 PRINT " IF SALES PRICE WILL BE CONSTANT OVER PROJECT LIFE, "
905 PRINT " ENTER SALES PRICE PER ";G$;" IF YOU WISH TO SUPPLY"
910 PRINT " FORECAST PRICES, ENTER F "
915 INPUT J*
920 IF J* = "F" THEN 955
925 JM = VAL
940 Sp(Y) = JM
945 NEXT Y
950 GOTO 980
955 FOR Y = Ydl. TO PI.
960 PRINT " ENTER FORECAST PRICE FOR YEAR ";Y
965 INPUT Fp
1035 Expt = Expt + Ex(Y)
1040 NEXT Y
1045 GOTO 1085
1050 FOR Y = Ydl TO PI
1055 PRINT " ENTER FORECAST NET OPERATING EXPENSE FOR YEAR ";Y
1060 INPUT Ex(Y)
1065 Expt = Expt •*• Ex(Y)
1070 NEXT Y
1075 GOTO 1085
1080 GOSUB 2500
1085 RETURN
1090 Rf = l/(i + (Roip/100))
1095 FOR Y = i TO PI
1100 Pvf(Y) = <(RfAY)-(RfA(Y-1)))/LOG(Rf)
1105 NEXT Y
1110 RETURN
1115 Bf'-=Q
1120 Tvco = 0
1125 IF E$ = "C" THEN 1150
1130 FOR Y = Ydl TO PI
1135 Sf = Sf •«• Pvf(Y)
1140 NEXT Y
1145 Sfa = SfX(Pl-Cy)
1150 FOR Y = i TO PI
1155 Tuco = Tyco + Pvf(Y)*Co
1160 NEXT Y
1165 IF E* = "C" THEN 1.200
11.70 Sfr = Str + -
-------
1205
1206
1.21.0
1.215
1220
1.225
1230
1240
1245
1250
1255
1.260
1265
1.270
1275
1200
1285
1290
1295
1305
1310
1.315
1320
1325
1330
1335
1340
1345
1350
1355.
1360
1365
1370
1375
1380
1305
1395
1400
1.402
1405
1410
1.41.5
1435
1440
1441
1442
1443
1445
1450
1455
1460
1465
1470
1.475
1480
1485
1490
1495
1500
1505
1510
1515
1520
1525
! FEDERAL INCOME TAX
Ccfc = 0
FOR Y = Ydl TO PI
EbT(Y) = Sp*Str ! STATE INC./FRANCHISE TAX
Ti = 2500() THEN 1.290
IF Itc <= Fitl THEN 1275
Fit(Y) = 0
Itc = Itc - Fit!
GOTO 1355
Fit(Y) = FiTl-lTc
ITC = 0
GOTO 1355
IF Itc < 25000 THEN 1330
FT! = FiTl - 25000
ITC = ITC - 25000
Trie = 0.85*FTi
IF Tric<=Itc THEN 1345
FiT(Y) = FT! - ITC
ITC = 0
GOTO 1355
Fit(Y) = Fitl - Itc
Itc = 0
GOTO 1355
Itc = Itc - Trie
Fit(Y) = Ftl - Trie
Fitl = Ftr*Ti(Y-f.l)
IF Y - Yd! > 15 THEN Itc = 0
NEXT Y
CcfCO)
Tp v(0 )
FOR Y
Cf(Y) =
Ccf(Y)
! FEDERAL INCOME TAX
iit(Y) - Fit(Y)
CASH FLOW
CUMULATIVE
CASH FLOW
THEN 1405
PRESENT VALUES OF CASH FLOWS
CUMULATIVE PRES. VALUES OF CASH FLOWS
-Ccf - i
' Ccf(Y-l) •»• Cf(Y)
IF Ccfc. > 0 OR Cc:f(Y) < 0
GOSUB 1441
IF E* = "C" THEN 1435
Pv(Y) = Cf(Y)*Pvf(Y)
Tpu(Y) = Tpu(Y-i) + Pv(Y>
NEXT Y
RETURN
Pop = Y - 1 + < <-l)*/-
Ccfc = 1
RETURN
Tpv(O) = 0
FOR Y = i TO PI
Pv(Y) = Cf(Y)*Pvf
Tpv(Y) = Tpw(Y-l) + Py(Y)
NEXT Y
RETURN
Tci = 0
Tco = 0
Fh = INT((P1 - Cy)/2 ) + Cy ! YR. NO. TO END FIRST HALF CASH INTAKES
FOR Y ~ Ydl TO Fh
Tci = Tci + Cf(Y)
NEXT Y
FOR Y = i TO PI
Tco = Tco + Co
-------
1530 Tcf = 0
1535 FOR Y = Ydl TO PI
1540 Tcf = Tcf + Cf(Y)
1545 NEXT Y
1550 Sa = Sa*(i-« l + (Ro:ip/4> >*(Tpv(PD/Tcf )) ) ! NEW ANNUAL. SALES ESTIMATE
1555 FOR Y = Ydl TO PI
1560 Sp(Y) = Sa ! FOR OUTPUT LISTING OF ANNUAL SALES
1565 NEXT Y
1570 Up(I) = Sa/Sv ! NEW UNIT PRICE ESTIMATE
1575 RETURN
1580 IF «Y-i>/5-INT«Y-l>/5» = 0 THEN PRINT ! SPACE TOP AND AFTER 5
1585 RETURN
1590 PRINT
1.595 PRINT
1600 PRINT " INPUTS WILL BE SHOWN IN SECTIONS FOR CHECKING.
1605 PRINT
1610 PRINT " A. PROGRAM NAME: "
1615 PRINT
1620 PRINT A*
1625 GOSUB 2005
1630 IF 7* 0 "N" THEN 1640
1635 GOSUB 360
1640 PRINT " B. PROJECT DATA "
1645 PRINT " TOTAL PROJECT COST = "-, PC
1650 PRINT " PROJECT LIFE INCLUDING CONSTRUCTION = "; PI
1655 PRINT " CONSTRUCTION PERIOD IS TO BE "; Cy j " YEARS"
1660 GOSUB 2005
1665 IF 7* <> "N" THEN 1675
1670 GOSUB 380
1675 PRINT " C. DEPRECIATION: "
1680 PRINT " DEPRECIABLE ASSETS^ "> Da
1685 PRINT
1690 FOR Y = Yd! TO Yde
1695 PRINT " 7. DEPRECIATION FOR YEAR "> Y >" = "jDp(Y)
1700 NEXT Y
1705 GOSUB 2005
1710 IF 7$ <> "N" THEN 1720
1715 GOSUB 595
1720 PRINT " D. CONSTRUCTION AND OTHER OUTLAYS:
1725 FOR Y = 1 TO Cy
1730 PRINT " PERCENT SPENT IN YEAR " > Y ; "FOR CONSTRUCTION = ";Cp(Y>
1735 NEXT Y
1738 PRINT
1740 FOR Y = Ydl TO PI
1745 IF Co = 0 THEN 1755
1750 PRINT " CASH OUTLAYS FOR YEAR ";Y >"= ">Co(Y)
1755 NEXT Y
1.760 GOSUB 2005
1765 IF 7$ <> "N" THEN 1775
1770 GOSUB 430
1775 PRINT
1780 PRINT " E. TAX INFORMATION: "
1785 PRINT " FEDERAL TAX RATE. IS "; 100*Ftr ; "PERCENT, AND THE STATE "
1790 PRINT " INCOME OR FRANCHISE TAX RATE IS ">Strp>" PERCENT"
1795 PRINT
1800 PRINT " THE INVESTMENT TAX CREDIT IS "iltcpj" PERCENT "
1805 PRINT " OF THE DEPRECIABLE ASSETS NOT INCLUDING CASH OUTLAYS"
1810 GOSUB 2005
1815 IF 7* <> "N" THEN 1825
1820 GOSUB 710
1825 PRINT "F. RETURN ON INVESTMENT (ROD: "
1.830 PRINT " ROI IS TO BE
1835 IF E* = "C" THEN PRINT " CALCULATED FROM SALES YOU SUPPLY" ELSE. 1845
A-7
-------
1840 GOTO 1.950
1845 PRINT " SUPPLIED BY YOU FOR CALCULATION OF REQUIRED SELLING PRICE."
1R50 TF E$ = "C" THEN 1870
1RS5 PRINT " ROI IS "iRoipi" PERCENT AND THE SELLING PRICE"
I860 PRINT " ACCURACY IS ";Sp*p> " PERCENT OF THE SELLING PRICE."
1865 PRINT
1870 PRINT " ANNUAL SALES VOLUME IS ";Su> G*
1875 IF E* = "S" THEN 1.920
1880 PRINT " ANNUAL CASH INTAKES FROM SALES WILL BE BASED ON "
1885 PRINT " THESE PRICES:"
1890 PRINT
189S PRINT "YEAR ", "FORECAST PRICE"
1.900 FOR Y = Yd! TO PI
1.905 GOSUB 1580
1.910 PRINT Y, Fp(Y)
191.5 NEXT Y
1920 GOSUB 3005
1925 IF Z* 0 "N" THEN 1935
1.930 GOSUB SOS
1935 PRINT " G. NET OPERATING EXPENSES: "
1.936 IF K* = "C" THEN 1967
1.940 PRINT
1945 PRINT " YEAR ", "OPER. EXPENSES"
1950 FOR Y = Yd! TO PI
1955 GOSUB 1580
1.960 PRINT Y, Ex(Y)
1.965 NEXT Y
1966 GOTO 1970
1967 GOSUB 3500
1.970 GOSUB 3005
1975 IF Z* 0 "N" THEN 1995
1.980 GOSUB 985
1985 PRINT " INPUT REVIEW COMPLETED - BUT THERE IS ALWAYS ANOTHER CHANCE. "
1.990 PRINT " WOULD YOU LIKE TO REVIEW THE INPUTS AGAIN 7 Y OR N "
1995 INPUT Z*
2000 IF Z$ - "Y" THEN 1590 ELSE 2035
3005 PRINT
201.0 Z* = ""
2015 PRINT " IS THIS SECTION CORRECT ? ENTER N TO RESUBMIT THE SECTION, "
2020 PRINT " OR CARRIAGE RETURN TO CHECK THE NEXT SECTION. ALSO, USE THE"
3025 PRINT " CARRIAGE RETURN FOR VALUES WHICH ARE ALREADY CORRECT."
2030 INPUT Z$
2035 RETURN
2040 PRINT " DO YOU WANT A PAUSE (P) BETWEEN PAGES FOR CUSTOM PRINTOUT,"
2041 PRINT " OR DO YOU WANT CONTINUOUS "P" AND A1*O"C" THEN 2040
3044 PRINT A$
2045 PRINT
2046 Pr = 1
2050 PRINT " PAGE 1 -••- CASH OUTLAYS AND DEPRECIATION "
2055 PRINT
2060 PRINT " YR. "; "CASH OUTLAYS","SALES","EARNINGS", "TAX"
2065 PRINT " ">" "," ", "BEFORE TAX","DEPRECIATION"
2070 PRINT
2075 FIXED 0
2080 FOR Y= 1 TO PI
2085 GOSUB 1580
2090 PRINT USING 2445; Y > Co(Y),Sp(Y>,Eht(Y),DfT(Y)
2095 NEXT Y
2100 GOSUB 2455
2105 PRINT A*
2110 PRINT
2115 PRINT "PAGE 2 — TAXES AND CASH FLOW "
2130 PRINT
A-8
-------
2125 PRINT "YR. "; "STATE","TAXABLE"/'FEDERAL","CASH"
2130 PRINT " ";" TAX","INCOME (FED.)","TAX","FLOW"
2135 PRINT
2140 FOR Y = 1 TO PI
2145 GOSUB 1580
2150 PRINT USING 2445; Y ;Sit(Y) ,Ti(Y),F11(Y),Cf(Y)
2155 NEXT Y
2160 GOSUB 2455
2165 PRINT A*
2170 PRINT
2175 FIXED 3
2180 PRINT "PAGE 3 —- CUMULATIVE CASH FLOWS AND PRESENT VALUES "
2185 PRINT " FOR "; Roip ; " PERCENT RETURN ON INVESTMENT"
21,Pvf(Y),Pv
2230 NEXT Y
2235 GOSUB 2455
2240 PRINT A*
2245 PRINT
2250 PRINT "APPENDIX A — PRICE, RETURN AND OTHER INFORMATION"
2255 PRINT
2260 IF ,T* = "F" THEN 2300
2265 IF E* = "C" THEN 2300
2270 FIXED 6
2275 PRINT " THE PRICE IS "; Up(I) /'PER "; G*
2280 FIXED 0
2285 .PRINT " VALUE OF AVERAGE ANNUAL BALES: ";Sa
2290 FIXED 4
2295 PRINT " REQUIRED ACCURACY: ",Spap;"X"
2300 PRINT
2305 FIXED 1
2310 PRINT " THE RETURN ON INVESTMENT IS "; Roip ; "PERCENT"
2315 FIXED 2
2320 PRINT
2325 PRINT " THE PAYOUT PERIOD IS "; Pop ; "YEARS."
2330 PRINT
2335 FIXED 0
2340 PRINT
2345 PRINT " THE TOTAL PRESENT VALUES OF ALL CASH OUTLAYS-. ";Twc.o
2350 IF E* := "S" THEN 2365
2355 PRINT " TOTAL CASH OUTLAYS: ";Tco
2356 PRINT
2360 IF E* - "C" THEN 2405
2365 PRINT " THIS SOLUTION REQUIRED ";I /'ITERATIONS"
2370 PRINT " THE FOLLOWING SALES WERE TRIED: "
2375 FIXED 4
2380 PRINT
2385 PRINT "ITERATION" , "PR ICE. / ";G$
2390 FOR W = 1 TO I
2395 PRINT W , Up(W)
2400 NEXT W
2401 IF K$ 0 "C" THEN 2405
2402 GOSUB 4600
2405 GOSUB 2455
2410 PRINT
2411 IF K* <> "C" THEN 2415
2412 GOSUB 3500
2413 Pr = 0
2414 GOSUB 4900
2415 PRINT " IF YOU WISH TO RE-EDIT THE INPUTS, AND RERUN THE PROGRAM, "
2420 PRINT " ENTER RR "
2425 INPUT Rr*
A-9
-------
2430
2435
2440
2445
2446
2447
2448
2450
2455
2456
2460
2465
2470
2475
2480
2485
2490
2491
2492
2493
2494
2495
2500
2505
2510
2515
2520
2525
2530
2535
2540
2541
2542
2543
2544
2545
2546
2547
2548
2550
2551
2555
2560
2565
2570
2575
2580
2590
2595
2596
2600
2605
2610
2615
2625
2630
2635
2636
2640
2645
2646
2650
26S5
2660
2665
2670
2675
STANDARD
If Rr$ = "RR» THEN 5000 ELSE 7980
RETURN
IMAGE DD,ilD,i6D,200,201)
IMAGE I)D,10D.DD,, 17D,15D.DD,1 OX,DD . 3D
IMAGE DD,13D. 21) ,2X, 12D . 3D , 14D . DD, 2X , 1 ID .3D
I MAGE DD, 3X, K , !3X , K , 20I), 12X, 2D . 3D
IMAGE DD,13D,6X,Z.6D,17D,2X,20D
PRINT
IF Al* = "C" AND Pr = 1 THEN 2492
PRINT
PRINT " THE PROGRAM HAS PAUSED. THE TERMINAL MAY BE PUT IN LOCAL MODE1
PRINT " TO PRINT OUT OR MANIPULATE THE DISPLAY. WHEN READY FOR THE "
NEXT PAGE, ENSURE THE TERMINAL IS IN REMOTE MODE AND TYPE"
CONT. IF YOU WISH TO QUIT, TYPE STOP. CAUTION!!!!
STOP CAUSES LOSS OF ALL DATA!!! "
PRINT
PRINT
PRINT
PAUSE
GOTO 2495
FOR P5 = 1
PRINT
NEXT P5
RETURN
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
PRINT
TO 10
INPUTS CAN BE MADE IN THESE OPERATING COST CATEGORIES:"
3 RAW MATERIALS (UNIT COST, ANNUAL CONSUMPTION EACH)"
UTILITIES"
TOTAL OPERATING LABOR"
TOTAL MAINTENANCE "
INSURANCE PLUS LOCAL TAXES"
ONE OTHER COST ITEM, YOU NAME IT"
2 BY-PRODUCT CREDITS (UNIT PRICE, ANNUAL SALES EACH)"
"in
CAUTION
IN THE NEXT SECTION, A ZERO INPUT IS NOT RECOGNIZED - THE"
COMPUTER WILL ASSIGN THE PREVIOUS YEAR'S VALUE TO THE"
CURRENT YEAR. IF ZERO IS DESIRED, IT CAN BE APPROXIMATED"
BY A VERY SMALL NUMBER "
GOSUB 7945
IF Sk$ = "S" THEN 2635
Bi = i
PRINT " ENTER THE NAME OF THE FIRST RAW MATERIAL:"
INPUT Rwi$
FOR Y = Yd! TO PI
PRINT " ENTER UNIT COST FOR YEAR ";Y;" IF SAME AS PREVIOUS "
PRINT " YEAR, MAKE NO ENTRY "
INPUT RMlc(Y)
IF Rnlc(Y) = 0 THEN Rwlc"
PRINT " YEAR, MAKE NO ENTRY."
INPUT RMla(Y)
IF RMia(Y) = 0 THEN RMla(Y) = RMia(Y-l)
NEXT Y
PRINT
PRINT " THE NEXT CATEGORY IS THE SECOND RAW MATERIAL,"
GOSUB 7945
IF Sk* = "S" THEN 2727
B2=l
PRINT "ENTER THE NAME OE THE SECOND RAW MATERIAL:"
INPUT Rd2*
FOR Y = Yd! TO PI
PRINT " ENTER UNIT COST FOR YEAR ";Y;"
PRINT " YEAR, MAKE NO ENTRY."
INPUT R«2c(Y)
IF SAME AS PREVIOUS
IF SAME AS PREVIOUS
A-10
-------
2685 IF RM2c(Y) = 0 THEN R«2c = RM2c = 0 THEN Rfi2a = RM2a
2775 IF R«3r(Y) = 0 THEN Rp\3c
2890 NEXT Y
2895 GOTO 2931
2900 FOR Y = Ydi TO PI •
2905 PRINT " ENTER ANNUAL UTILITY COST FOR YEAR ">Y;" IF SAME. AS "
291.0 PRINT " PREVIOUS YEAR , MAKE NO ENTRY."
2915 INPUT Ut
-------
2980 FOR Y = Ydl TO PI
2985 PRINT " ENTER ANNUAL. LABOR COST FOR YEAR ";Y;" IF SAME AS "
2990 PRINT " PREVIOUS YEAR , MAKE NO ENTRY."
2995 INPUT La(Y>
3005 IF La(Y) = 0 THEN l..a(Y) = La(Y-i)
3010 NEXT Y
3011 PRINT
3012 PRINT " THE NEXT CATEGORY IS THE TOTAL MAINTENANCE,"
3013 GOSUB 7945
3014 IF Sk* = "S" THEN 3092
3015 PRINT " IF MAINTENANCE COST WILL BE CONSTANT OVER THE"
3020 PRINT " PROJECT LIFE, ENTER THE AMOUNT. IF YOU WISH "
3025 PRINT " TO SUPPLY FORECAST COSTS, ENTER F."
3030 INPUT Ma*
3031 B6=l
3035 IF Ma* = "F" THEN 3060
3040 FOR Y = Ydl TO PI.
3045 Ma(Y) = VAL(MaS)
3050 NEXT Y
3055 GOTO 3092
3060 FOR Y = Ydl TO PI
3065 PRINT " ENTER ANNUAL. MAINTENANCE COST FOR YEAR ";Y>" IF SAME AS '
3070 PRINT " PREVIOUS YEAR , MAKE NO ENTRY."
3075 INPUT Ma
3085 IF Ma(Y) = 0 THEN Ma(Y> = Ma(Y-i)
3090 NEXT Y
3092 PRINT
3093 PRINT " THE NEXT CATEGORY IS INSURANCE PLUS LOCAL TAXES,"
3095 GOSUB 7945
3098 IF Sk* = "S" THEN 3176
3099 B7=l
3100 PRINT " IF INSURANCE AND LOCAL TAXES WILL BE CONSTANT OVER THE"
3105 PRINT " PROJECT LIFE, ENTER THE AMOUNT. IF YOU WISH "
3110 PRINT " TO SUPPLY FORECAST COSTS, ENTER F."
3115 INPUT lit*
3120 IF lit* = "F" THEN 3145
3125 FOR Y = Ydl TO PI
3130 ITt(Y) = VALdlt*)
3135 NEXT Y
3140 GOTO 3176
3145 FOR Y = Ydl TO PI
31.50 PRINT " ENTER INSURANCE AND LOCAL TAX COST FOR YEAR ">Y
31.55 PRINT " IF SAME AS THE PREVIOUS YEAR , MAKE NO ENTRY."
3160 INPUT IJ. t(Y)
3170 IF I1t(Y) = 0 THEN Ilt(Y) = H.t(Y~l)
3175 NEXT Y
3176 PRINT
3177 PRINT " THE NEXT CATEGORY IS GENERAL; A NAME WILL BE REQUESTED."
3180 GOSUB 7945
3182 IF Sk* = "S" THEN 3272
3183 B8=l
3185 PRINT " ENTER THE NAME OF ANOTHER COST CATEGORY;"
3190 INPUT Ot*
3195 PRINT " IF ";0t$;" COST WILL BE"
3200 PRINT " CONSTANT OVER THE PROJECT LIFE, ENTER THE AMOUNT."
3205 PRINT " IF YOU WISH TO SUPPLY FORECAST COSTS, ENTER F."
3210 INPUT Otr*
3215 IF Otc* = "F" THEN 3240
3220 FOR Y = Ydl TO PI
3225 Otc(Y) = VAL(Otc$)
3230 NEXT Y
3235 GOTO 3272
3240 FOR Y = Yd! TO PI
3245 PRINT " ENTER ">0t*;" COST FOR YEAR ">Y
3250 PRINT " IF SAME AS THE PREVIOUS YEAR ,, MAKE NO ENTRY."
3255 INPUT Otc(Y)
3265 IF Otc(Y) = 0 THEN Otc(Y) = Otc(Y-l)
3270 NEXT Y
A-12
-------
3272 PRINT
33.73 PRINT " THE NEXT CATEGORY IS THE FIRST BY-PRODUCT CREDIT."
3275 GOB LIB 7945
3277 IF Sk$="S"THEN 3350
3370 B9=l
320(1 PRINT "ENTER THE NAME 01" THE FIRST BY-PRODUCT:"
3285 INPUT Bplt>
3290 FOR Y = Ydi TO PI
3295 PRINT " ENTER UNIT PRICE FOR YEAR "-.Y;". IF SAME AS PREVIOUS "
3300 PRINT " YEAR, MAKE NO ENTRY."
3305 INPUT Bplp(Y)
3310 IF Bplp = Bplp(Y-i)
331.5 NEXT Y
3316 GOSUB 4(300
3320 FOR Y = Ydl TO PI
332S PRINT " ENTER ANNUAL SALES •VOLUME: FOR YEAR ";Y;" . IF SAME AS"
3330 PRINT " PREVIOUS YEAR, MAKE NO ENTRY."
3335 INPUT Bpla(Y)
3340 IF Bpia = 0 THEN Bpia(Y) = Bpia(Y-l)
3345 NEXT Y
3350 PRINT
3355 PRINT " THE LAST CATEGORY IS THE SECOND BY-PRODUCT CREDIT."
3360 GOSUB 7945
3362 IF SI<*-"S"THETN 3435
3363 B 1.0 = 1
3365 PRINT "ENTER THE NAME OF THE SECOND BY-PRODUCT:"
3370 INPUT Bp2*
3375 FOR Y = Ydi TO PI
3300 PRINT " ENTER UNIT PRICE-: FOR YEAR ";Y;". IF SAME AS PREVIOUS "
3385 PRINT " YEAR, MAKE MO ENTRY."
3390 INPUT Bp2p(Y)
3395 IF Bp2p(Y) = 0 THEN Bp2p = Bp2.p " . IF SAME. AS"
3415 PRINT " PREVIOUS YEAR, MAKE NO ENTRY."
3420 INPUT Bn2a
-------
36053 PRINT "APPENDIX B -OPERATING COST DETAIL, ";RM2*;" PAGE 2"
3609 PRINT
3610 IF Pr = 1 THEN 3614
3611 GOSUB 7945
361.3 IF Sk* = "S" THEN 3690
3614 PRINT "YR " ;RM2*,RM2$,R«2*,"PERCENT OF"
361.5 PRINT " "."UNIT COST" , "ANNUAL CONS.","COST","EXPENSES *"
36,30 PRINT
3635 FOR Y- 1. TO PI.
3630 GOSUB 1580
3635 PRINT USING 2446; Y >Rii2c ( Y ) , R«2a < Y ) ,Rcst2< Y) ,Rp2< Y)
3645 NEXT Y
3650 GOSUB 2455
3655 GOTO 3670
3660 PRINT " NO ENTRIES FOR SECOND RAW MATERIAL, PAGE 2 SKIPPED."
3665 GOTO 3690
3670 PRINT A*
3685 PRINT
3690 IF B3 = 0 THEN 3745
369,? PRINT
3693 PRINT "APPENDIX B—OPERATING COST DETAIL, ";RM3*>" PAGE 3"
3694 PRINT
3695 IF Pr = 1 THEN 3699
3696 GOSUB 7945
3697 IF Sk* = "S" THEN 3775
3699 PRINT "YR . "> Rn3* ,, R«3'6, RM3*, "PERCENT OF"
3700 PRINT " "i"UNIT COST","ANNUAL CONS.","COST","EXPENSES *"
3705 PRINT
3710 FOR Y= 1 TO PI
3715 GOSUB 1580
371B PRINT USING 2446; Y >Rw3c: ( Y > ,Rfi3a (Y) ,Rcst3< Y) ,Rp3< Y)
3730 NEXT Y
3735 GOSUB 2455
3740 GOTO 3755
3745 PRINT " NO ENTRIES FOR THE THIRD RAW MATERIAL, PAGE 3 SKIPPED."
3750 GOTO 3775
3755 PRINT A*
3770 PRINT
3775 IF B4 = 0 AND P5 = 0 THEN 3045
3777 PRINT
377R PRINT "APPENDIX B—OPERATING COST DETAIL, UTILITIES AND LABOR, PAGE 4"
3779 PRINT
3780 IF Pr = 1 THEN 3784
3781 GOSUB 7945
378? IF Sk* = "S" THEN 3875
3784 PRINT "YR 'V'UTU. ITIES","UTILITIES X","LABOR","LABOR %"
1785 PRINT " "."COST","OF EXPENSES *", "COST ","OF EXPENSES *"
3790 PRINT
3800 FOR Y= 1 TO PI
3805 GOSUB 1580
3810 IF Ut$ = "P" THEN 3825
3815 PRINT USING 2447j Y ; 1.11 < Y ) ,l!tp ( Y) ,l...a < Y ) , Lap < Y)
3820 GOTO 3830
3B,?5 PRINT USING 2448: Y;" < IN-PI... ANT) ", " 0 0 00 " , La (Y ) , Lap (Y )
3830 NEXT Y
3835 GOSUB ,?455
3840 GOTO 3855
3845 PRINT " NO ENTRIES FOR UTILITIES OR LABOR, PAGE 4 SKIPPED"
3850 GOTO 3875
3BS5 PRINT A*
3870 PRINT
3875 IF B6 = 0 AND B7 = 0 THEN 3930
3877 PRINT
3878 PRINT "APPENDIX B—OPERATING COST DETAIL, MAINT., INS. & LCI. TAX PAGE 5"
3879 PRINT
A-14
-------
3880 IF Pr = 1 THEN 3884
3881 GOSUB 7945
388;? IF Sl<* = "S" THEN 3960
3884 PRINT "YR "; "MAINTENANCE ", "MAINTENANCE X" ," INSURANCE" , "INS t> LCI... TAX X"
3885 PRINT " "i"COST","OF EXPENSES * ","\ LOCAL. TAX","OF EXPENSES *"
3890 PRINT
3895 FOR Y= 1 TO PI
3905 GOSUB 1.580
3910 PRINT USING 2447; Y;Ma(Y),Map(Y),111(Y),Iltp(Y)
3915 NEXT Y
3930 GOSUB 2455
3925 GOTO 3940
3930 PRINT " NO ENTRIES FOR EITHER MAINTENANCE OR FOR INSURANCE "
3931 PRINT " PLUS LOCAL TAXES, PAGE 5 SKIPPED"
3935 GOTO 3960
3940 PRINT A*
3955 PRINT
3960 IF B8 = 0 THEN 4010
3961 PRINT
396? PRINT "APPENDIX B—OPERATING COST DETAIL, OTHER COSTS, PAGE. 6"
3963 PRINT
3965 IF Pr = 1. THEN 3969
3966 GOSUB 7945
3967 IF 8k* = "S" THEN 4040
3969 PRINT "YR. "; Ot*,0t*
3970 PRINT " "'; "COST","X OF EXPENSES *"
3975 PRINT
3980 FOR Y= 1 TO PI
3985 GOSUB 1.580
3990 PRINT USING 2447 ; Y , 01c(V),01p(Y)
3995 NEXT Y
4000 GOSUB 2455
4005 GOTO 4020
4010 PRINT " NO ENTRIES FOR 'OTHER' COSTS, PAGE 6 SKIPPED"
4015 GOTO 4040
4020 PRINT A*
4035 PRINT
4040 IF B9 = 0 THEN 4085
4042 PRINT
4043 PRINT "APPENDIX B—OPERATING COST DETAIL, ";Bpi*;" PAGE 7"
4044 PRINT
4045 IF Pr = 1 THEN 4049
4046 GOSUB 7945
4047 IF Sk* = "S" THEN 41.15
4049 PRINT "YR "; Bp It, Bp 1.*, Bp It, "PERCENT OF"
4050 PRINT " "."UNIT PRICE","ANNUAL SALES" ,"CREDIT","EXPENSES *"
4055 PRINT
4060 FOR Y= 1 TO PI
4065 GOSUB 1580
4070 PRINT USING 2446; Y ;Bpip ,Bpia(Y),Bpis,Bppl(Y)
4075 NEXT Y
4080 GOSUB 2455
4082 GOTO 4095
4085 PRINT " NO ENTRIES FOR THE FIRST BY-PRODUCT, PAGE 7 SKIPPED"
4090 GOTO 411.0
4095 PRINT A*
4110 PRINT
4115 IF B10 = 0 THEN 4165
41.1.7 PRINT
4118 PRINT "APPENDIX B—OPERATING COST DETAIL, ">Bp2*;" PAGE 8 "
411.9 PRINT
41.20 IF Pr " 1 THEM 4124
4121 GOSUB 7945
41.22 IF Sk* = "S" THEN 41.8?
4124 PRINT "YR. "> Bp?>* - Bp2* , Bp2t, "PERCENT OF"
4125 PRINT " 'V'UNIT PRICE","ANNUAL SALES","CREDIT","EXPENSES #"
4130 PRINT
41.35 FOR Y= 1 TO PI
A-15
-------
4140 GOSUB 1580
41.45 PRINT USING 2446; Y >Bp2p ( Y ) , Bp2a ( Y ) ,Bp2s< Y ) ,Bpp2( Y )
4150 NEXT Y
4160 GOTO 41.70
4165 PRINT " NO ENTRIES FOR SECOND BY-PRODUCT, PAGE '8 SKIPPED"
4170 PRINT
4175 PRINT "* EXPENSES INCLUDE OPERATING EXPENSES (NO CREDITS), PLUS1
41.80 PRINT " STATE AND FEDERAL TAXES"
4101 GOSUB 2455
4182 PRINT
4185 RETURN
4305 FOR Y = Ydl TO PI.
4306 Rcstl(Y) = RMic(Y)*RMla*R
4325 Tut ™ Tut + Ut(Y)
4330 Tla = Tla + L.a(Y)
4335 Twa •- Tna + Ma(Y)
4340 Tilt =•• Tilt + II. t(Y)
4345 Totr = Tote + Otc(Y)
4350 Tbpl -- Tbpl •»• Kpis(Y)
4355 Thp2 = Thp2 •*• Bp;:.'s(Y)
4360 Fx(Y)-=Rcsti( Y) +Rcst2( Y )+Rcst3( Y) -HJt < Y)+L.a< Y)+Ma < Y > + Ilt < Y)+Otc (Y )
4361. Ex(Y) •= Ex(Y) - Bpis.= <100*Tr«l)/Txp
4480 Opp<2> = <100*TrM2>/Txp
4485 Opp(3> = (100*TrM3)/Txp
4490 Opp(4) = (100*Tut)/Txp
4495 Opp(5) = (100*Tla)/Txp
4500 Opp(6) = (iOO*Tna)/Txp
4505 Opp(7) = <100*Ti1.t)/Txp
4510 Opp(8) = (100*Totc)/Txp
451.5 Opp(9) = <100*Tsit)/Txp
4520 Opp(lO) = (100*Tfit)/Txp
4525 Opp(il) ™ (100*rbpi)/Txp
4530 Opp(12) = <100*Tbp2)/Txp
4535 RETURN
4600 PRINT
A-16
-------
PROJECT LIFE FRACTIONAL EXPENSE SUMMARY"
PERCENT OF TOTAL EXPENSES *"
4605 PRINT
461.0 PRINT "
461.1. PRINT
461.2 PRINT
4615 PRINT "EXPENSE CATEGORY
4619 Cr$ = " (CREDIT) "
4620 FIXED 3
4621. IMAGE 30X,DD.3D
4622 IMAGE 10X,DD.3D
4623 IMAGE 10X,K , 1. OX ,DD . 3D
4625 PRINT
4630 PRINT Rfil*;" . ",
4631. PRINT USING 4621 > Opp
4645 PRINT "UTILITIES",
4646 PRINT USING 4621; Opp(4)
4650 PRINT "OPERATING LABOR",
4651 PRINT USING 4621> Opp<5>
4652 PRINT
4655 PRINT "MAINTENANCE",
4656 PRINT USING 4621; Opp(6>
4660 PRINT "INSURANCE PLUS LOCAL TAXES",
4661. PRINT USING 4622; Opp(7)
4670 PRINT Ot*; " .",
4671 PRINT USING 4621, Opp<8)
4675 PRINT "STATE TAX",
4676 PRINT USING 4621; Qpp<9)
4680 PRINT "FEDERAL TAX",
4681 PRINT USING 4621; QppdO)
4605 PRINT
4690 PRINT Bpi*}".",
4691 PRINT USING 4623;Cr$,Opp<11)
4695 PRINT Bp2*>".",
4696 PRINT USING 4623 ;(>*, Opp ( 1.2 >
4700 PRINT
4705 PRINT
4710 PRINT " * EXPENSES INCLUDE OPERATING EXPENSES (NO CREDITS),PLUS"
4715 PRINT " STATE AND FEDERAL TAXES."
4720 RETURN
4800 PRINT
4805 PRINT
4810 PRINT " COST/PRICE SECTION COMPLETED. NEXT, ENTER THE ANNUAL"
4815 PRINT " VOLUME IN CONSISTENT UNITS."
4820 PRINT
4825 PRINT
4830 RETURN
4900 PRINT A*
4905 PRINT
4910 PRINT "APPENDIX C—TAXES AS A PERCENT OF TOTAL EXPENSES *"
4915 PRINT
4920 PRINT "YR. ";"STATE TAX","STATE TAX","FEDERAL TAX","FEDERAL. TAX"
4925 PRINT " "; "AMOUNT", "% OF- EXPENSES *", "AMOUNT" , "7. OF EXPENSES *"
4930 PRINT
4935 FOR Y « t TO PI
4940 GOSUP 1580
4945 PRINT USING 2447; Y ;S:i. t ( Y> ,Si tp (Y) ,Fi t ( Y ) ,Fi tp ( Y )
4950 NEXT Y
4955 PRINT
4960 PRINT "* EXPENSES INCLUDE OPERATING EXPENSES (NO CREDITS), PLUS"
4965 PRINT " STATE .AND FEDERAL TAXES"
4970 RETURN
5000 PRINT " DO YOU WISH TO READ THE RE-RUN EDIT SUGGESTIONS ? (Y OR N>"
5001 INPUT Re*
5010 IF Re* = "N" THEN 1.00
5015 PRINT " THE FIRST STEP IN A RERUN IS TO EDIT ALL INPUTS. INPUT VARIABLES'
A-17
-------
50,?(1 PRINT " WILL REMAIN THE SAME UNLESS CHANGED. WHEN CARRIAGE RETURN IS"
5025 PRINT
5030 PRINT
5035 PRINT
5040 PRINT
5045 PRINT
KEYED IN RESPONSE TO A , THE VARIABLE REMAINS UNCHANGED FROM"
THE PREVIOUS RUN."
IF OPERATING EXPENSES WERE ENTERED BY CATEGORY, SECTIONS MAY"
BE SKIPPED WITHOUT ALTERING THE INPUT VARIABLES. ALSO, KEYING"
5050 PRINT " CARRIAGE RETURN IN THIS SECTION DOES NOT GIVE THE PREVIOUS YEAR'S"
5055
•5060
5065
5070
5075
5080
5085
5090
5095
6000
7945
7946
7950
7965
7970
7980
7981
7983
7984
8000
8010
PRINT " VALUE AS IT DID IN THE FIRST RUN, INSTEAD IT CAUSES THE VALUE"
PRINT " USED IN THE PREVIOUS RUN TO BE RETAINED. HOWEVER, THE YEAR TO"
YEAR REPEAT FEATURE CAN BE UTILIZED BY KEYING IN A (0). FOR"
EXAMPLE, IN A RERUN YOU MAY WISH TO CHANGE LABOR COSTS TO"
13.682E6 FOR YEARS 1.4 THROUGH 31. IT MAY BE ENTERED FOR YEAR"
NUMBER 14 THEN REPEATED FOR YEARS IS - 31 BY KEYING 0 CARRIAGE"
RETURN. DURING INPUT CHECKING, CALCULATED VARIABLES WILL BE"
SHOWN AS LEFT OVER FROM THE PREVIOUS RUN, BUT THEY WILL BE "
CHANGED DURING CALCULATION."
PRINT "
PRINT "
PRINT "
PRINT "
PRINT "
PRINT "
PRINT "
GOTO 100
Sk* = ""
PRINT " IF YOU WISH TO SKIP THE NEXT CATEGORY, ENTER S "
INPUT Sk'f
PRINT
RETURN
PRINT " DO YOU REALLY WANT TO QUIT AND LOSE ALL YOUR INPUT DATA ?"
PRINT " (Y OR N)"
INPUT Rq*
IF Rq$ = "Y" THEN 8000 ELSE 5000
STOP
END
A-18
-------
Some program modifications were required to handle the state tax for the eastern high-sulfur
case. The state chosen for this case, Ohio, has a net worth tax and it was convenient to
temporarily modify the program to handle it. For broader applications it could be desirable to
write this feature into the program as a regular option. The following printout shows the lines
which were modified; changes are circled.
DIM Ebt(60> jExCbO) - F ':> t (60 ) ,I>cp(60> ,Dct(20 ,1.00)
_
2 0 D I M P M ( 6 0 ) , P v f ( 6 0 > , R o :i. ( 6 0 ) , R r p v ( 6 0 ) , F p ( 6 0 )|>(3c(26)
Sit(Y)= Si-NY) THEN Sit(Y) = Nwt
1.21 R S:it(Y) == Si. t(Y) •« Qc))) I
I
1220 T:i(Y) -~ Eht(Y> •••• Dft(Y) - Sit(Y) ! FEDERAL TAXABLE INCOME
32SO PBTMT " IF SAHF AS THE PREVIOUS YEAR , MAKE NO ENTRY "
INPUT DC (Y)|
3995 NEXT V
3996 PRINT
3997 PRINT " *** STATE TAX CREDITS FOR LOCAL TAXES WERE USED TO CALCULATE"
3998 PRINT " THE STATE TAX AND ARE NOT INCLUDED HERE."
4000 GOSUB 2455
471.5 PRINT " STATE AND FEDERAL TAXES. "
4716 PRINT
471.7 PRINT " *** STATE TAX CREDITS FOR LOCAL TAXES WERE USED TO CALCULATE"
471R PRINT " THE STATE TAX AND ARE NOT INCLUDED HERE."
4720 RETURN
A-19
-------
APPENDIX B
Example Computer Output for One Complete Price Calculation
-------
Example Computer Output
WESTERN LOU-SULFUR CASE 7
PAGE 1 —• CASH OUTLAYS AND DEPRECIATION
YR . CASH OUTLAYS
SALES
EARNINGS
BEFORE TAX
TAX
DEPRECIATION
i
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
SO
21
22
23
24
25
131555160
252147390
328887900
252147390
131555160
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
553683020
0
0
0
0
0
499568987
499573940
499578893
499583846
499588799
487953752
476318705
464713658
453078611
441452564
441457517
441462470
441467423
441472376
441477329
441482282
441487235
441492188
441497141
441502094
0
0
0
0
0
146387850
214702.180
204942990
204942990
204942990
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
B-2
-------
UFSTERN LOU-SULFUR CASE 7
PAGE 2 --•• TAXES AND CASH FLOW
YR. STATE
TAX
TAXABLE
INCOME (FED.)
FEDERAL
TAX
CASH
FLOW
i
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
353181137
284871760
294635903
294640856
294645809
487953752
476318705
464713658
453078611
441452564
441457517
441462470
441467423
441472376
441477329
441482282
441487235
441492188
441497141
441502094
0
0
0
0
0
64871423
131041009
135532515
135534794
135537072
224458726
219106604
213768282
208416161
203068179
203070458
203072736
203075014
203077293
203079571
203031850
203084128
203086406
203088685
203090963
-131555160
-252147390
-328887900
-252147390
-131555160
434697564
368532930
364046377
364049052
364051727
263495026
257212100
250945375
244662450
238384384
238387059
238389734
238392408
238395083
238397757
238400432
238403107
238405781
238408456
238411131
B-3
-------
WESTERN LOU-SULFUR CASE 7
PAGE 3— CUMULATIVE CASH FLOWS AND PRESENT VALUES
FOR 20.000 PERCENT RETURN ON INVESTMENT
YR.
i
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
1G
19
20
21
22
23
24
25
CUMULATIVE
CASH FLOW
-131555160
-383702550
-712590450
-964737840
-1096293000
-661595436
-293062506
70983871
435032923
799084650
1062579676
1319791776
1570737151
1815399601
2053783985
2292171044
2530560778
2768953186
3007348269
3245746026
3484146458
3722549565
3960955346
4199363802
4437774933
PRESENT
VALUE FACTOR
0.914136
0 761780
0.634817
0.529014
0.440845
0.367371
0.306142
0.255119
0.212599
0.177166
0.147638
0.123032
0.102526
0.085439
0.071199
0.059332
0 . 049444
0.041203
0.034336
0.028613
0.023844
0.019870
0.016559
0.013799
0.011499
PRESENT
VALUES
-120259285
-192080802
-208783480
•133389446
-57995411
159695142
112823496
92874977
77396383
64497460
38901889
31645242
25728530
20903637
16972706
14144080
11786866
9822498
8185507
6821333
5684508
4737143
3947663
3289756
2741494
CUMULATIVE
PRES. VALUES
-120259285
-312340087
-521123567
-654513013
-712508424
-552813282
-439989786
-347114808
-269718425
•205220966
-166319077
-134673835
-108945305
-88041668
-71068962
-56924882
-45138016
-35315518
-27130011
-20308678
-14624171
-9887028
-5939365
-2649608
91886
B-ft
-------
WESTERN LOW-SULFUR-—CASE 7
APPENDIX A — PRICE. RETURN AND OTHER INFORMATION
THE PRICE IS .722352 PER GALLON
AVERAGE ANNUAL SALES: 553683020
REQUIRED ACCURACY: .0100 7.
THE RETURN ON INVESTMENT IS 20.0 PERCENT
THE PAYOUT PERIOD IS 7.81 YEARS.
THE TOTAL PRESENT VALUES OF ALL CASH OUTLAYS
THIS SOLUTION REQUIRED 18 ITERATIONS
THE FOLLOWING SALES WERE TRIED:
712508424
ITERATION
1.0000
2.0000
0000
0000
0000
0000
0000
8.0000
9. 0000
10 .0000
11.0000
12.0000
13.0000
14.0000
15.0000
16.0000
17.0000
IB.0000
PRICE /
.8675
.8176
.7848
.7631
.7490
.7397
.7336
.7297
.7271
.7254
.7243
.7236
.7231
.7228
.7226
.7225
.7224
.7224
GALLON
PROJECT LIFE FRACTIONAL EXPENSE SUMMARY
EXPENSE CATEGORY
COAL.
WATER.
CHEMICALS.
UTILITIES
OPERATING LABOR
MAINTENANCE
INSURANCE PLUS LOCAL TAXES
CORP. LICENSE.
STATE TAX
FEDERAL. TAX
SULFUR.
CARBON DIOXIDE.
-PERCENT OF TOTAL EXPENSES *
19.492
3.970
2.381
. 000
3.943
10.497
3.234
. 016
.000
56.467
(CREDIT)
(CREDIT)
.428
15.080
* EXPENSES INCLUDE OPERATING EXPENSES (NO CREDITS),PLUS
STATE AND FEDERAL TAXES.
B-5
-------
WESTERN LOW-SULFUR CASE 7
APPENDIX B--OPERATING COST DETAIL, PAGE i
YR. COAL
UNIT COST
COAL
ANNUAL CONS,
COAL
COST
PERCENT OF
EXPENSES *
i
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
20
21
22
23
24
25
.00
.00
.OD
.00
. 00
15. 00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15. 00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0
0
0
0
0
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
4259900
.00
. 00
.00
.00
.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
63898500.00
.000
.000
.000
.000
.000
30.776
23.338
22.962
22.962
22.963
17.402
17.660
17.924
18.198
18.480
18.480
18.480
18.480
18.480
18.480
18.480
18.481
18.481
18.481
18.481
B-6
-------
WESTERN LOU-SULFUR CASE 7
APPENDIX B—OPERATING COST DETAIL, PAGE 2
YR. UATER
UNIT COST
WATER
ANNUAL CONS.
UATER
COST
PERCENT OF
EXPENSES *
i
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
20
21
22
23
24
25
.00
.00
.00
.00
.00
i. 16
1.16
1.16
1.16
1.16
i . 16
1 .16
1.16
1.16
1.16
1. 16
1.16
1.16
1.16
1.16
i . 16
i .16
1.16
1 .16
1.16
0
0
0
0
0
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
11266600
,
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
13012923.
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
.000
. 000
.000
. 000
.000
6.267
4.753
4.676
4.676
4.676
3.544
3.596
3.650
3.706
3.763
3.763
3.763
3.763
3.763
3.764
3.764
3.764
.764
764
3
3.
3.764
B-7
-------
WESTERN LOU-SULFUR CASE 7
APPENDIX B—OPERATING COST DETAIL, PAGE 3
YR . CHEMICALS
UNIT COST
CHEMICALS
ANNUAL CONS.
CHEMICALS
COST
PERCENT OF
EXPENSES *
i
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
7805000
.00
.00
.00
.00
.00
.00
.00
.00
.00
. 00
. 00
. 00
. 00
. 00
. 00
. 00
.00
. 00
. 00
. 00
. 00
.00
.00
. 00
. 00
0
0
0
0
0
1
i
1
1
i
1
i
1
i
i
1
1
1
i
1
1
1
i
1
i
.00
.00
.00
. 00
.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
7805000.00
.000
. 000
.000
.000
.000
3.759
2.851
2.805
2.805
2.805
2.126
2.157
2.189
2.223
2.257
2.257
2.257
2.257
2.257
2.257
2.257
2.257
2.257
2.257
2 257
B-8
-------
WESTERN LOW-SULFUR CASE 7
APPENDIX B--OPERATING COST DETAIL, PAGE 4
YR. UTILITIES
COST
UTILITIES %
OF EXPENSES *
LABOR
COST
LABOR 7.
OF EXPENSES *
i
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
20
21
22
23
24
25
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
(IN
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
PLANT)
0.000
0. 000
0 .000
0.000
0.000
0 . 000
0 . 000
0. 000
0.000
0.000
0 . 000
0.000
0.000
0.000
0.000
0.000
0. 000
0.000
0 .000
0. 000
0 .000
0. 000
0 . 000
0 .000
0.000
0
0
0
0
0
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
12927000
.000
.000
.000
.000
.000
6.226
4.721
4.645
4.645
4.645
3.521
3.573
3.626
3.682
3.739
3.739
3.739
3.739
3.739
3.739
3.739
3.739
3.739
3.739
3.739
B-9
-------
WESTERN LOW-SULFUR CASE 7
APPENDIX B—OPERATING COST DETAIL, PAGE 5
YR. MAINTENANCE
COST
MAINTENANCE %
OF EXPENSES *
INSURANCE
& LOCAL TAX
INS & LCL TAX X
OF EXPENSES *
1
2
3
4
5
6
7
8
9
10
it
12
13
14
15
16
17
18
19
20
21
22
23
24
25
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
34410000
.00
. 00
.00
. 00
.00
.00
.00
. 00
.00
. 00
.00
.00
.00
. 00
.00
.00
.00
.00
.00
. 00
.00
. 00
.00
. 00
.00
.000
.000
.000
. 000
.000
16.573
12.568
12.365
12.365
12.366
9.371
9.510
9.652
9.800
9.951
9.952
9.952
9.952
9.952
9.952
.00
.00
.00
.00
.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000 .00
10603000.00
10603000.00
10603000.00
9.952
9.952
9.952
9.952
9.952
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
10603000.00
.000
. 000
.000
.000
.000
5.107
3.873
3.810
3.810
3.810
2.888
2.930
2.974
3.020
3.066
3
3.
3.
3.
3.
066
066
066
067
067
3.067
3.067
3.067
3.067
3.067
B-10
-------
UESTERN LOU-SULFUR CASE 7
APPENDIX B—OPERATING COST DETAIL, PAGE 6
YR . CORP. LICENSE
COST
CORP. LICENSE
'/. OF EXPENSES *
i
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
. 00
.00
.00
.00
.00
99060.00
94107.00
89154.00
84201.00
79248.00
74295.00
69342.00
64389.00
59436.00
54483.00
49530.00
44577.00
39624.00
34671.00
29718.00
24765.00
19812.00
14859.00
9906.00
4953.00
000
000
000
000
000
048
034
032
030
028
020
019
018
017
016
014
013
Oil
010
009
007
006
004
003
001
B-ll
-------
WESTERN LOU-SULFUR—CASE 7
APPENDIX B--OPERATING COST DETAIL, PAGE 7
YR. SULFUR
UNIT PRICE
SULFUR
ANNUAL SALES
SULFUR
CREDIT
PERCENT OF
EXPENSES *
1
2
3
4
5
6
7
8
9
10
11.
12
13
14
15
16
17
18
19
20
75.
75.
75.
75.
75.
75.
75.
75.
75.
75.
75.
75.
75.
75.
75.
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
21
22
23
24
75.00
75.00
75.00
75.00
75.00
0
0
0
0
0
.00
. 00
.00
.00
.00
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
18686
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
1401450
.00
.00
.00
.00
.00
.00
. 00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.000
. 000
.000
. 000
.000
.675
.512
.504
.504
.504
382
.387
.393
.399
.405
.405
.405
.405
.405
.405
.405
.405
.405
.405
405
B-12
-------
WESTERN LOU-SULFUR CASE 7
APPENDIX B—OPERATING COST DETAIL, PAGE 8
YR. CARBON DIOXIDE CARBON DIOXIDE
UNIT PRICE ANNUAL SALES
CARBON DIOXIDE
CREDIT
PERCENT OF
EXPENSES *
1
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
20
21
22
23
24
25
30
30.
30
30
30
30.
30
30
30
30
30
30.
30
30.
30
30.
30
30 ,
30
30
.00
. 00
00
.00
00
. 00
00
. 00
00
.00
00
.00
. 00
.00
.00
.00
00
.00
00
.00
00
.00
.00
.00
.00
0
0
0
0
0
2908000
2908000
2908000
2908000
2908000
2520000
2132000
1745000
1357000
969300
969300
969300
969300
969300
969300
969300
969300
969300
969300
969300
.00
. 00
.00
.00
.00
87240000.00
87240000.00
87240000.00
87240000.00
87240000.00
75600000.00
63960000.00
5235aOOO.00
40710000.00
29079000.00
29079000.00
29079000.00
29079000.00
29079000.00
29079000.00
29079000
29079000
29079000
29079000
00
00
00
00
29079000.00
.000
.000
.000
. 000
.000
42.018
31.864
31.350
31.350
31.351
20.589
17.677
14.685
11.594
8.410
8.410
8.410
8.410
8.410
8.410
8.410
8.410
8.410
8.410
8.410
* EXPENSES INCLUDE OPERATING EXPENSES (NO CREDITS), PLUS
STATE AND FEDERAL TAXES
B-13
-------
WESTERN LOU-SULFUR CASE 7
APPENDIX C—TAXES AS A PERCENT OF TOTAL EXPENSES *
YR. STATE TAX
AMOUNT
STATE TAX
'/. OF EXPENSES *
FEDERAL TAX
AMOUNT
FEDERAL TAX
7. OF EXPENSES *
1
2
3
4
5
6
7
8
9
10
ii
12
13
14
15
16
17
18
19
20
21
22
23
24
25
.00
.00
.00
. 00
.00
. 00
.00
. 00
.0.0
.00
.00
. 00
.00
. 00
.00
.00
.00
.00
00
. 00
.00
.00
00
.00
.00
.000 .00
.000 .00
. 000 .00
.000 .00
.000 .00
.000 64871422.82
000 131041009.40
.000 135532515.18
000 135534793.56
.000 135537071.94
.000 224458725.72
.000 219106604.10
.000 213768282.48
.000 208416160.86
.000 203068179.24
.000 203070457.62
000 203072736.00
,000 203075014.38
000 203077292.76
,000 203079571.14
000 203081849.52
000 203084127.90
000 203086406.28
000 203088684.66
000 203090963.04
.000
. 000
.000
.000
.000
31.244
47.862
48.704
48.705
48.707
61.129
60.555
59.965
59.355
58.728
58.729
58.730
58.731
58.732
58.733
58.734
58.736
58.737
58.738
58.739
* EXPENSES INCLUDE OPERATING EXPENSES (NO CREDITS), PLUS
STATE AND FEDERAL TAXES
B-14
-------
APPENDIX C
Telephone Quotes for Costs of Water and Rail Transportation
-------
APPENDIX C
Telephone Quotes for Costs of Water and Rail Transportation
Water
1. For shipment size at 80,000 barrels, the cost is $2.00 per barrel from the
Houston, TX port up the Mississippi and Illinois Rivers to Lamont, IL (20 miles
south of Chicago). Due to low bridge restriction, local tug boats to tow barges
into Chicago proper must be subcontracted at an additional cost of $6,500.00 per
shipment.
2. For 70,000 barrels minimum 90,000 barrels maximum shipment, the cost is $16.00
per ton or $2.21 per barrel from the Houston, TX port to Jo lie t, IL (30 miles SW
of Chicago on the Illinois River). Subcontracting of local tug boats into Chicago
proper is also necessary.
3. For 10,000 barrel barge shipments, the cost is $15.00 per ton or $2.07 per barrel
from the Houston, TX port up the Mississippi and Illinois Rivers into Chicago
proper. No bridge restrictions.
*. For 50,000 barrels minimum the cost is $2.15 per barrel from Galveston, TX
around the east coast to New York City, New York.
5. For 50,000 barrel minimum per shipment the cost is $2.46 per barrel from
Chicago to Buffalo, New York via the Great Lakes. Can also move up the St.
Lawrence River around the Northeast coast into New York City at a cost of
$8.10 per barrel.
Costs for loading and unloading of the methanol were not addressed in any of the
above estimates.
Rail
The feasibility of moving methanol by unit train - a series of specially designed
and built railroad cars interconnected to form a single unit for loading and
unloading - was investigated. It appears that some of the railroad companies
that were contacted can provide this service at a lower cost than the standard
C-2
-------
individual tanker car. However, in order to formulate a price quote, amount,
duration and frequency of shipments must be known. Therefore, the price quotes
that were obtained are based on the standard individual tanker cars ranging from
52,800 to 19,000 Ib capacity. The capacity size of the cars vary depending on
availability, weight restrictions, etc. The larger the capacity size, the lower
than the cost. Rail prices are usually stated in dollars per hundred pounds.
The following are price quotes for rail transportation of methanol from locations near
the five regions locations to Chicago, Atlanta, and New York City.
1. From Wheeling, W. VA to Chicago, IL, 180,000 Ib capacity car at $2.04 per 100
wt or $5.65 per barrel.
From Wheeling W. VA to Atlanta, GA: 190,000 Ib capacity car at $2.16 per 100
wt or $5.98 per barrel.
From Wheeling W. VA to New York City, NY 180,000 Ib capacity car at $2.36 per
100 wt or $6.90 per barrel.
2. From Palastine, TX to Chicago, IL; 180,000 Ib capacity car at $1.67 per 100 wt
or $4.62 per barrel.
From Palastine, TX to Atlanta, GA; 180,000 Ib capacity car at $3.44 per 100 wt
or $9.52 per barrel.
From Palestine, TX to New York City, NY; 130,000 Ib capacity car at $2.44 per
100 wt or $6.75 per barrel.
3. From St. Louis, MO to Chicago, IL; 130,000 Ib capacity car at $1.80 per 100 wt
or $4.98 per barrel.
From St. Louis, MO to Atlanta, GA; 130,000 Ib capacity car at $2.83 per 100 wt
or $7.83 per barrel.
From St. Louis, MO to New York City, NY 64,000 Ib capacity car at $5.04 per
100 wt or $13.96 per barrel.
C-3
-------
4. From BeuJah, ND to Chicago, IL; 52,800 lb capacity car at $5.33 per 100 wt or
$14,81 Per barrel.
From Beulah, ND to Atlanta, GA; 52,800 lb capacity car at $6.36 per 100 wt or
$17.67 per barrel.
From Beulah, ND to New York City, NY; 52,800 capacity car at $7.40 per 100 wt
or $20.56 per barrel.
From Gillette, WY to Chicago, IL; 52,800 lb capacity car at $5.99 per 100 wt or
$16.64 per barrel.
From Gillette, WY to Atlanta, GA; 52,800 lb capacity car at $6.52 per 100 wt or
$18.12 per barrel.
From Gillette, WY to New York City, NY; 52,800 capacity car at $8.42 per 100
wt or $23.40 per barrel.
5. From Palestine, TX to Houston and Galveston, TX for further movement via
waterway; 52,800 lb capacity car at $1.46 per 100 wt or $4.06 per barrel.
C-4
-------
APPENDIX D
Report on Pipeline Economic Factors
-------
Williams Brothers
Engineering Company
Resource Sciences Park
MOO Souih Yale Avenue
rulu, Oklahoma 74136
Phone: (918) 496-5020
Tele« 497493 WBEC TUl
facvmile (918) 49«-50J4
September 6, 1984
Southwest Research Institute
Post Office Drawer 28510
6220 Culebra Road
San Antonio, Texas 78284
Attention: Mr. David S. Moulton
Subject: Methanol Pipeline Transportation
Dear Mr. Moulton:
In response to the Statement of Work issued by Southwest
Research Institute dated July 24, 1984, Williams Brothers
Engineering Company has prepared preliminary design and cost
data for potential pipeline systems transporting methanol from
the North-Central and South-Central regions of the United
States to New York City. Data was developed for two methanol
pipeline systems: one to transport 400,000 barrels per day
from sources in Wyoming and North Dakota to markets in Chicago,
Illinois and New York City; the second to transport 300,000
barrels per day from a source in Texas to markets in Atlanta,
Georgia and New York City. This data will be used by Southwest
Research to calculate pipeline transportation costs for
comparison to other potential modes of methanol transportation.
It must be emphasized that much of the data presented herein is
definitely conceptual in nature. Attempts at optimizing the
pipeline design, a normal part of the pipeline transportation
cost analysis process, have been minimal due to the time
constraints placed on the assignment. The data presented does
constitute a reasonable set of pipeline system design and cost
characteristics which should be suitable for your purposes at
this time.
Routes and Capacities
For the northern pipeline system, origin points in Campbell
County, Wyoming and Mercer County, North Dakota were specified
by the Statement of Work. Brule County, South Dakota was
selected as a convenient junction location for the origin
pipeline segments, being approximately 320 miles from Campbell
D-2
-------
Williams Brothers
Southwest Research Institute
Mr. David S. Moulton
September 6, 1984
Page 2
County and 280 miles from Mercer County. From the junction
point, the selected route proceeds across northern Iowa and
Illinois to Chicago, then continuing across northern Indiana
and Ohio, central Pennsylvania, and northern New Jersey into
New York City. The estimated distance from the junction point
in South Dakota to New York City is 1,300 miles. The selected
route is basically straight line from point to point, with
slight adjustment to minimize major river crossings.
Elevations are estimated at 4,500 feet above sea level in
Campbell County, 2,000 feet in Mercer County, 1,500 feet in
Brule County, 600 feet at Chicago, and 0 feet at New York City.
Design capacities for the pipeline segments are 200,000 barrels
(8.4 million gallons) per day for both the Wyoming to South
Dakota and North Dakota to South Dakota segments and 400,000
barrels (16.8 million gallons) per day for the South Dakota to
New York segment.
The origin point of the southern pipeline system is in Milam
County, Texas, from where the selected route proceeds across
southern Louisiana and Mississippi and central Alabama to
Atlanta, then continuing across western South Carolina and
North Carolina, central Virginia and Maryland, southeastern
Pennsylvania, and north central New Jersey into New York City.
The estimated length of the pipeline is 1,520 miles. The
selected route is basically straight line from its origin to
Baton Rouge, Louisiana, at which point it joins an existing
pipeline corridor occupied by Colonial Pipeline. The route
follows the Colonial corridor into Pennsylvania and continues
on a straight line into New York. Elevations are estimated at
500 feet above sea level in Milam County, 1,000 feet at
Atlanta, and 0 feet at New York City. Design capacity for the
pipeline is 300,000 barrels (12.6 million gallons) per day.
Pipeline Design
Applicable parts of the Department of Transportation regulation
for transportation of hazardous liguids by pipeline (Part 195,
Title 49, Code of Federal Regulations) and incorporated
references, plus principles of fluid flow in pipe were used in
preparing the design, construction, operations and maintenance
data presented herein. Pipeline sizing and pumping
requirements are based on transporting methanol with a specific
gravity of 0.795 and a kinematic viscosity of 0.74 centistokes.
D-:
-------
Williams Brothers
Southwest Research Institute
Mr. David S. Moulton
September 6, 1984
Page 3
Initial pipe and pump station selection was based on the
following factors:
• Internal design pressure of 1,440 psig and design factor
of 0.72
• Pipe material to be API 5L Grade X-60 priced at $800 per
ton
• Pipe wall thickness to be standard API wall thickness
• Pipe sized to produce a friction head loss of between 25
and 50 feet per mile
• 75 percent pumping unit efficiency
• Pump station costs of $1,200 per installed horsepower
Using these factors, various combinations of pipe size and
pumping capacity for each flowrate were evaluated on an initial
investment cost basis, with the lowest cost combination being
selected for development of more detailed construction and
operating data. The selected pipeline systems are described in
Table 1.
Capital Requirements
Capital requirements for constructing each of the four pipeline
segments described in Table 1 have been estimated and are
displayed in Table 2. All costs are based on estimated current
material prices and labor rates and no escalation to year of
construction has been included. Total costs, in millions of
1984 dollars, for the four pipeline segments are:
Wyoming to South Dakota $106.3
North Dakota to South Dakota 95.7
South Dakota to New York 742.1
Texas to New York 721.2
D-4
-------
Williams Brothers
Inynrering Company
Southwest Research Institute
Mr. David S. Moulton
September 6, 1984
Page 4
Economic Factors
The Statement of Work issued by Southwest Research requested
information on typical or reasonable values for certain items
considered in evaluating pipeline economics. The following
discussion addresses these points:
* Project Life
Although the useful life of a pipeline facility can
sometimes extend to 50 years or longer, a project life of
20 to 25 years is typically assumed when evaluating the
potential revenues from a proposed pipeline investment.
This is due to the risks involved in forecasting the
business aspects of pipeline operation such as growth or
decline of product supply or demand, competition, etc.
* Number of Years Required for Construction
The duration of physical construction activity on a
pipeline system is determined by the number of
construction spreads used, their rate of progress, and the
success of pre-construction planning. It is estimated
that approximately 1.5 years would be required to complete
construction on the methanol pipelines studied. The
duration of pre-construction activity is much more
difficult to predict and probably will be considerably
longer than that for construction. Pre-construction
activities would include engineering, environmental study,
survey, acquisition of agreements and permits from
landowners and responsible governmental and regulatory
agencies, materials procurement, and contracting. It is
recommended that a minimum of 3 years be allowed for
completion of pre-construction activity.
* Approximate Percent of Construction Funds Spent Each Year
of Construction
Assuming a project duration of 5 years from commencement
of pre-construction to completion of construction and
demobilization, reasonable estimates of percentage of
capital requirements spent per year would be:
D-5
-------
Williams Brothers
Southwest Research Institute
Mr. David S. Moulton
September 6, 1984
Page 5
Year %
1 1
2 2
3 22
4 50
5 25
* Percent of the Capital Outlay Which is Depreciable
One hundred percent of the monies considered as initial
investment are depreciable.
* Amount and Timing of Other Capital Outlays during the
Project Life
Once the pipeline is ready for service it must be filled
with methanol before normal operation begins. The cost of
line fill is the product of the volume required and its
unit value to the owner. For the two pipeline systems
studied, line fill volumes would be 5.14 million barrels
for the northern system and 3.52 million barrels for the
southern system. No other capital outlays should be
required, outside of normal operating and maintenance
costs, unless operating conditions change at some time in
the future. Examples of such change would be a
significant increase in volume to be transported, the
addition of new methanol source or delivery points, or
investment in new technology advances which might decrease
operating costs. At this point, estimating the amount of
capital expenditures for these purposes will require
additional input from Southwest Research.
Operating Expenses
An estimate of the annual operating and maintenance expenses
for each of the four pipeline segments described in Table 1 are
summarized in Table 3. All costs are presented in 1984
dollars. These costs would not be expected to change
substantially during the project life if adjustments for
inflation are taken into account.
Some of the criteria used in estimating operating and
maintenance expenses were:
D-6
-------
Williams Brothers
Southwest Research Institute
Mr. David S. Moulton
September 6, 1984
Page 6
• Intermediate pump stations are unmanned. Initial pump
stations and delivery terminals are manned continuously.
• Power costs are based on an average charge of 6 cents per
kwh of power consumed by mainline pumping units. Power
cost is the largest single item of expense in operating
the pipeline systems and is a significant factor to be
considered when optimizing pipeline design.
• Insurance and ad valorem taxes are calculated at 1.5
percent of initial investment.
Taxes and Depreciation
In response to the Southwest Research request for guidance on
certain tax and depreciation matters, we offer the following
comments:
* State income tax levies are usually considered
insignificant at this stage of a cost of transportation
study and are ignored. Also, there is little uniformity
from state to state on methods of calculating state tax.
However, if provision is to be made for state income
taxes, 2 percent of pretax income would be a reasonable
annual average to use.
* Southwest Research Institute assumptions of a ten percent
investment tax credit, five year accelerated cost recovery
system for depreciation and no energy investment tax
credits appear to be appropriate.
* Regarding areas unique to pipelines which may affect
project economics, Southwest Research Institute should be
aware of the necessity of the pipeline owner to obtain the
right of eminent domain. This allows the owner to acquire
pipeline right-of-way via condemnation proceedings if a
landowner refuses reasonable compensation for his
property. Without this privilege, acquisition of
right-of-way is likely to be much more costly than we have
estimated, if not virtually impossible.
D-7
-------
Wffiams Brothers
Southwest Research Institute
Mr. David S. Moulton
September 6, 1984
Page 7
We appreciate the opportunity you have given us for
participating in this project and sincerely hope that the
information presented herein fully satisfies your requirements
If we can be of further service, please do not hesitate to
call.
Very truly yours,
WILLIAMS BROTHERS ENGINEERING COMPANY
Michael M. Friese
Project Manager
MMF:slm/5803-001
Attachments
D-8
-------
•^Williams Brothers
f nginetnng Company
5803
TABLE 1
METHANOL PIPELINE SYSTEM FACILITIES
Line Length, Miles
Flow Rate, MBPD
Pipe Diameter and Wall
Thickness, Inches
No. of Pump Stations
Installed Brake
Horsepower per Station
No. Delivery Terminals
Wyoming
to
North Dakota South Dakota
to
South Dakota South Dakota
320
200
18 x 0.312
3
7,000
280
200
18 x 0.312
3
7,000
0
to
New York
1,300
400
26 x 0.438
9
13,000
Texas
to
New York
1,520
300
22 x 0.375
14
10,000
D-9
5803-002
-------
5803
• ' rvY/VT|lll<||l|3 umiiicii
\AA/ tnginecring Company
TABLE 2
CAPITAL REQUIREMENTS FOR CONSTRUCTING
Wyoming North Dakota
to to
South Dakota South Dakota
ROW and Land 4.8 4.2
Line Pipe 39.9 34.9
Coating 2.1 1.8
Scraper Traps, Valves, 3.7 3.6
and Other Materials
Pipeline Construction 29.6 26.3
Pump Stations and 12.8 12.8
Terminals
Engineering, 8.3 7.5
Construction
Management and
Inspection
Subtotal 101.2 91.1
Contingency @ 5% 5.1 4.6
Total 106.3 95.7
Notes: (1) Costs are in millions of 1984 dollars.
(2) Costs for project financing, initial line
studies and permitting are not included.
D-10
PIPELINES
South Dakota Texas
to to
New York New York
27.3 35.8
323.5 271.5
12.3 12.1
18.3 21.4
179.5 187.8
87.7 101.7
58.2 56.6
706.8 686.9
35.3 34.3
742.1 721.2
fill, and environmental
5803-002
-------
NoA/ tngioeering Company
TABLE 3
ANNUAL OPERATING AND MAINTENANCE
Wyoming North Dakota
to to
South Dakota South Dakota
Operations Payroll 0.36 0.34
Supervisory Payroll 0.20 0.19
Communications 0.04 0.04
Automotive 0.03 0.03
Power 6.65 7.09
Pipeline Maintenance 0.10 0.08
Station Maintenance 0.11 0.11
Contract Services 0.03 0.02
Insurance and 1.59 1.44
Ad Valorem Tax
Miscellaneous .05 .05
TOTAL 9.16 9.39
Note: Costs are in millions of 1984 dollars.
D-ll
COSTS
South Dakota
to
New York
1.45
0.61
0.17
0.09
40.78
0.39
0.59
0.10
11.13
2.77
58.08
Texas
to
New York
1.95
0.90
0.20
0.13
48.38
0.46
0.70
0.12
10.82
3.18
66.84
5803-002
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA 460/3-84-012
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Costs to Convert Coal to Methanol
5. REPORT DATE
April 1986
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
David S. Moulton and Norman R. Sefer
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Southwest Research Institute
6220 Culebra Road
San Antonio, Texas 78284
10. PROGRAM ELEMENT NO.
Work Assignment 9
11. CONTRACT/GRANT NO.
68-03-3162
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
2565 Plymouth Road
Ann Arbor, MI 48105
13. TYPE OF REPORT AND PERIOD COVERED
Final (8/15/83 - 9/30/84)
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report provides estimated costs of producing methanol transportation fuel
from coal. Estimates were made for mine-mouth plants in five different coal
producing regions, and uniform methods were used so the estimated sales prices could
be compared for market analysis. In addition to plant-gate prices, delivered prices
were estimated for three major market areas. With presently available transportation
the lowest delivered prices were for methanol production based in the southern
lignite coal region. If new methanol-compatible pipelines were to be constructed,
the lowest delivered prices would be for production based in the western
subbituminous coal region. In the western subbituminous region, limited water
resources would make extensive planning and careful site selection necessary, but
they would not prevent the development of a coal-to-methanol industry. By-product
carbon dioxide sales for enhanced oil recovery could reduce the required plant-gate
methanol price in some areas near oil fields amenable to carbon dioxide injection
techniques. Contains a literature review with 50 references.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS C. COSATI Ffold/GrOUp
Coal
Bituminous Coal
Subbituminous Coal
Lignite
Cost Estimates
Conversion
Manufacturing
Coal gasification
Carbinols
Desulfurization
Prices
Transportat ion
Coal rank
Methanol
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
217NO. OF PAGES
122
20. SECURITY CLASS (Thtspagt)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
------- |