JACKFAU-86-322-8/11
METHANOL PRICES DURING TRANSITION
FINAL REPORT
Submitted to:
U.S. ENVIRONMENTAL PROTECTION AGENCY
2565 Plymouth Road
Ann Arbor, Michigan 48105
August, 1987
JACK FAUCETT ASSOCIATES
73OO PEARL STREET SUITE 2OO
BETHESDA. MARYLAND 2O81 4
(301)961-8800
-------
JACKFAU-86-322-8/11
*"C*
METHANOL PRICES DURING TRANSITION
FINAL REPORT
Submitted to:
U.S. ENVIRONMENTAL PROTECTION AGENCY
2565 Plymouth Road
Ann Arbor, Michigan 48105
August, 1987
JACK FAUCETT ASSOCIATES
73OO PEARL STREET SUITE 2OO
BETHESDA. MARYLAND 2O81 4
(301)961-8800
-------
ACKNOWLEDGEMENTS
This report was prepared by Jack Faucett Associates (JFA) for the U.S. Environmental
Protection Agency (EPA). The U.S. Department of Energy, the California Energy
Commission and Jack Faucett Associates also contributed funding. The project was
directed by Michael F. Lawrence and the report was researched and written by
Linda Lent and Jon Skolnik of JFA. Don Hutson produced the document.
We wish to thank a wide range of individuals and companies throughout the country who
cooperated with the research effort. While too numerous to identify individually, the
list includes methanol producers, methanol researchers, policy makers desirous to
promote methanol as a transportation fuel (and a few who do not see a future for
methanol), and the shipping industry. Special appreciation is extended to Michael Gold
and Jeff Alson of the Environmental Protection Agency, Lilly Ghaffari of the California
Energy Commission, and Barry McNutt of the Department of Energy.
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TABLE OF CONTENTS
CHAPTER PAGE
ACKNOWLEDGEMENTS i
TABLE OF CONTENTS ii
LIST OF EXHIBITS iv
INTRODUCTION AND SUMMARY 1
RESEARCH OBJECTIVE 1
RESEARCH METHODOLOGY 2
RESEARCH RESULTS 6
REPORT OVERVIEW 9
METHANOL PRODUCTION PROCESSES 12
FEEDSTOCK 12
PROCESS TECHNOLOGY 12
METHYL TERTIARY BUTYL ETHER 15
WORLD METHANOL CAPACITY 17
WORLD METHANOL SUPPLY AND DEMAND 26
LOCAL METHANOL SUPPLY AND DEMAND 27
U.S. METHANOL SUPPLY 27
THE COST OF PRODUCTION FROM EXISTING
CAPACITY 32
FIXED COSTS 33
VARIABLE COSTS 34
TOTAL COSTS 49
THE COST OF DELIVERY 53
11
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TABLE OF CONTENTS - (continued)
CHAPTER
PAGE
6 PRODUCTION FROM ADDITIONAL CAPACITY 66
TOTAL COST PRICING 66
POTENTIAL LOCATIONS FOR NEW PLANTS 68
FIXED COSTS 68
VARIABLE COSTS 75
TOTAL COSTS 75
7 THE DELIVERED PRICE OF METHANOL 80
THE PRICE OF THE CURRENT (SHORT RUN) MARKET. 83
PRICE IN AN EXPANDING MARKET 85
SENSITIVITY OF THE ESTIMATES 85
USE OF THE ESTIMATES 90
BIBLIOGRAPHY 92
APPENDIX A: THE INTERRELATIONSHIPS OF CRUDE OIL, PETROLEUM,
NATURAL GAS AND METHANOL 98
RELATIONSHIP BETWEEN CRUDE OIL AND
NATURAL GAS PRICES 98
RELATIONSHIP BETWEEN CRUDE OIL AND
METHANOL PRICES 101
PETROLEUM PRICES 102
ill
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LIST OF EXHIBITS
EXHIBIT PAGE
1-1 U.S. METHANOL DEMAND SCENARIOS: TRANSPORTATION
USE ONLY 3
1-2 WORLDWIDE METHANOL DEMAND SCENARIOS: ALL
USES . 4
1-3 SHORT RUN METHANOL SUPPLY CURVE 7
1-4 LONG RUN METHANOL SUPPLY CURVE 8
1-5 FORECASTED METHANOL PRICES BY SCENARIO, FOR
SELECTED YEARS 10
2-1 SIMPLIFIED GAS-BASED METHANOL PRODUCTION
PROCESS 14
2-2 TWO-STAGE MTBE PROCESS 16
3-1 IDENTIFIED ESTIMATES OF METHANOL CAPACITY
BY PLANT AND COUNTRY, 1990 18
3-2 LOCAL METHANOL SUPPLY AND DEMAND, 1990 .... 28
3-3 AVAILABILITY OF METHANOL TO THE U.S., BY
COUNTRY 29
3-4 WORLDWIDE METHANOL DEMAND SCENARIOS: ALL
USES 31
4-1 FEEDSTOCK COSTS PER GALLON FOR POTENTIAL
U.S. SUPPLIERS, BY COUNTRY 37
4-2 MAINTENANCE COSTS PER GALLON FOR POTENTIAL
U.S. SUPPLIERS, BY COUNTRY 41
4-3 UTILITY COSTS PER GALLON FOR POTENTIAL
U.S. SUPPLIERS, BY COUNTRY 42
4-4 LABOR COST DIFFERENTIAL INDEXES 45
4-5 LABOR COSTS PER GALLON FOR POTENTIAL
U.S. SUPPLIERS, BY COUNTRY 47
4-6 SUMMARY OF AVERAGE VARIABLE COSTS OF METHANOL
PRODUCTION, BY COUNTRY 48
5-1 DELIVERED COST OF METHANOL FROM CURRENT
PRODUCERS TO U.S. DESTINATIONS, BY COUNTRY . . 54
5-2 POTENTIAL ECONOMIES OF SCALE, OCEAN SHIPPING
METHANOL: MIDDLE EAST TO UNITED STATES ... 57
IV
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LIST OF EXHIBITS (continued)
EXHIBIT PAGE
6-1 WORLD NATURAL GAS PRODUCTION, 1983 AND
RESERVES AS OF JANUARY 1985 69
6-2 POTENTIAL ANNUAL METHANOL SUPPLY, SELECTED
COUNTRIES 71
6-3 CAPITAL COSTS AND OTHER COMPONENTS OF FIXED
COSTS FOR NEW (227.5 MILLION GALLON) METHANOL
PLANTS BY COUNTRY 74
6-4 SUMMARY OF AVERAGE VARIABLE COSTS OF
METHANOL PRODUCTION FROM NEW PLANTS, BY
COUNTRY 76
6-5 TOTAL PRODUCTION COSTS FOR NEW CAPACITY, BY
COUNTRY 77
7-1 U.S. METHANOL DEMAND SCENARIOS: TRANSPORTATION
USE ONLY 82
7-2 WORLDWIDE METHANOL DEMAND SCENARIOS: ALL
USES 84
7-3 SHORT RUN METHANOL SUPPLY CURVE 86
7-4 LONG RUN METHANOL SUPPLY CURVE 87
A-l PETROLEUM PRICE SCENARIOS 103
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CHAPTER 1:
INTRODUCTION AND SUMMARY
In recognition of the environmental benefits of the use of methanol as an alternative
transportation fuel, the U.S. Environmental Protection Agency's Office of Mobile
Sources conducts on-going research on the use of methanol in transportation appli-
cations. In support of EPA*s efforts, Jack Faucett Associates, Inc. prepared this report
to provide an analytical tool for policy makers concerned with methanol as a
transportation fuel.
Consumer confidence in methanol as a transportation fuel will be developed during the
early years of methanol use. During this period consumer confidence, so critical to the
eventual success of methanol, may suffer significant damage if fuel prices are unstable
and unpredictable. Thus, it is important for public policy analysts concerned with the
transition to an alternative transportation fuel to understand how the market price of
methanol will change as the current conditions of excess production capacity abate and
new, fully-costed capital is brought into use.
Future prices of transportation fuels are uncertain. The prices will be affected by
market demand, production costs and international trade agreements, as well as war,
blockades, embargos, cartels, and other unpredictable acts of nations and producers. In
spite of these uncertainties, it is incumbent upon public policy analysts to develop
assumptions about pricing trends if sound public policy is to be developed. Most
analysts agree that gasoline will some day be replaced as our principal transportation
fuel. Today, methanol is a leading candidate in the U.S. as the transportation fuel of
the future.
RESEARCH OBJECTIVE
In order to assist policy makers in consideration of methanol as a dominant U.S.
transportation fuel, this report includes:
Information on the global capacity available to produce methanol
Estimates of the costs of production from existing capacity
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Estimates of the costs of production from capacity that may be added as
demand increases, and
Estimates of the delivered prices of methanol to selected U.S. ports
during the period of transition, beginning with current market conditions
(characterized by excess capacity and regionalized demand) and
continuing to the point where worldwide demand exceeds available
capacity.
The estimates developed in this report are based on secondary sources that provide data
on current methanol production costs and engineering estimates of future costs, as
available. General assumptions about the scale of future plants and efficiency
improvements were also developed from secondary sources.
RESEARCH METHODOLOGY
To estimate the delivered price of methanol to selected U.S. ports, four demand
scenarios were developed with the assistance of Energy and Environmental Analysis,
Inc. (EEA). Because most of the current and projected near term domestic use of
methanol as a vehicle fuel is in California, the scenario development is centered in
California. The first two scenarios are for methanol consumption in California
exclusively, with alternatives for low and high levels of consumption within the state.
The two additional scenarios demonstrate a national transition, and include deliveries to
ports located on the Gulf of Mexico, in the Northeast and Great Lakes regions, as well
as California. Again a low and a high demand scenario are used. The levels of demand,
by scenario, are shown in Exhibit 1-1.
To characterize the market conditions of supply and demand during transition, it is
necessary to view each demand scenario (for U.S. transportation fuel) in terms of the
global demand for methanol. Since worldwide demand for methanol includes demand
that is satisfied by producers that will not also supply the U.S. because of location,
political differences, etc., Exhibit 1-2 presents total demand as well as total demand
less demand that will be satisfied by producers that will not supply the U.S. The
additional U.S. demand assumed to be generated by methanol vehicles, by scenario, is
added to other competing demand to provide total demand used to formulate the U.S.
supply curve. The range of scenarios reflects periods wherein U.S. transportation
demand will represent only a slight fraction of total methanol demand up to and
including a scenario in which U.S. transportation demand represents more than 300
2
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EXHIBIT 1-1;
U.S. METHANOL DEMAND SCENARIOS;
TRANSPORTATION USE ONLY1
(Millions of Gallons)
Year
1988
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
California
Low Demand
Case
11
11
22
25
28
46
55
71
103
128
California
High Demand
Case
7
21
47
59
82
95
108
136
154
180
219
252
National
Low Demand
Case
138
282
421
646
890
1,255
1,670
2,375
3,216
4,252
National
High Demand
Case
150
150
3,300
6,500
9,800
13,000
15,800
18,600
21,400
24,200
27,000
For reference, 10,000,000 gallons would fuel approximately 15,000 vehicles for one
year. (15 mpg, 10,000 mi/yr)
Source: All scenarios except the National High Demand were formulated by Energy
and Environmental Analysis, Die. (EEA) in related research undertaken for
EPA, reference: EEA Working Paper f 3, "Scenarios for Rapid Development
of a Fuel Methanol Market in the California South Coast Basin", and EEA
Working Paper #4, "A Scenario for Rapid Development of a Fuel Methanol
Market in the U.S." The National High Demand Case was formulated by
JFA for this effort.
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EXHIBIT 1-2:
WORLDWIDE METHANOL DEMAND SCENARIOS; ALL USES
(Millions of Gallons)
Projected Worldwide
Demand, Excluding
U.S. Transportation
Use
Year Total1
1990 5,700
1995 6,900
2000 8,400
Demand Not
Competing with
U.S.2
2,500
3,000
3,200
Demand Competing
with U.S.
Demand
3,200
3,900
4,700
Worldwide Noncaptive Demand, Including
U.S. Transportation Use
California
Low Demand
Case
3,200
3,930
4,830
California
High Demand
Case
3,220
4,010
4,950
National
Low Demand
Case
3,200
4,890
8,950
National
High Demand
Case
3,350
16,900
31,700
A four percent growth rate for chemical methanol demand is assumed. This is because the demand for chemical methanol
has been observed to increase with GNP in developed countries.
2
It is assumed that this quantity of demand will be satisfied by countries that do not supply the U.S. As shown in Exhibit 3-3,
there is 3.751 billion gallons of nameplate capacity for non-U.S. suppliers of which 625 million gallons is dedicated for
conversion to gasoline (New Zealand). The remaining 3.1 billion in capacity (and future additions to that capacity) is
assumed to operate at about 80 percent utilization in supplying noncompeting methanol users. Thus, the number in the table
is estimated based on an assessment of available capacity, not actual market demand.
Source: EEA and JFA estimates.
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percent of all other uses combined. This range of scenarios offers a framework for
analysts to examine market responses under a wide array of assumptions.
To estimate the delivered price of methanol within each scenario, a supply curve for
methanol was developed. The supply curve has two components: the first segment of
the curve represents the short run supply of methanol available from existing (or soon
to be completed) capacity. Because available capacity far exceeds current demand,
producers cannot expect to receive a selling price that reflects a fully-costed product.
In fact, the market now is characterized by producers who are willing to supply product
if the price received is greater than variable cost. Notwithstanding this type of market
imperfection, the first segment of the supply curve represents the compilation of the
variable costs plus transportation costs of all individual producers and only those
producers to the left of any point on the curve (those with relatively lower variable
costs) will recover any fixed costs at market clearing prices. As such, the costs
indicated along the supply curve should be viewed as the minimum price possible for a
given level of supply and, in fact, the actual price may be higher as demand increases
along the curve and higher variable cost producers are drawn into production. Market
fluctuations can also result in the market price falling below variable costs, but
producers will quickly adjust by reducing production to the point that price equals or
exceeds variable costs. Moreover, in the spot market the price of methanol has been
observed to drop below that of variable costs because supply exceeds demand at various
times. This triggers producer decisions to stop production until the excess product
clears the market.
The second component of the supply curve represents the long-run scenario, when
demand exceeds available capacity and new capacity roust be brought on line. While in
the short-run excess capacity indicates that variable cost will be the controlling factor
for price, in the long run (beginning at the point where available capacity is or will soon
be fully utilized), entrepreneurs will require a market price that covers total costs.
Thus, short of speculative investment and/or decisions to subsidize new methanol
production capacity, new capacity will not be added (and long-term supply will not be
increased) until the demand (and subsequently price) of methanol is high enough to
cover the total production costs of methanol plants built during a future period.
The costs of methanol in the short- and long-run scenario were developed by first
distinguishing between fixed and variable costs. Costs were considered fixed costs if
they lacked any connection to quantity produced, i.e., the cost of the plant in idle
condition. By definition fixed costs include the actual cost of capital and the
5
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opportunity cost of capital as well as incidental costs that may be necessary to
maintain the plant during idle periods. Tims, variable costs include all other costs that
are associated with operation, including maintenance, overhead, selling costs, feedstock
costs, etc. In the estimates presented in this report, it was necessary to combine the
incidental categories of fixed costs (maintenance required when the plant is closed,
base levels of utility use, property taxes, insurance, etc.) with variable costs because
data were not available to identify components of primarily variable cost categories
that represent fixed costs. This misstatement of fixed and variable costs does not
significantly impact the numbers because the total amount of incidental fixed costs is
slight when compared to total fixed costs or total variable costs. It should be noted
that while consideration of marginal costs may have enhanced the analysis, reliable
information on marginal costs were not available from secondary sources. Because the
research undertaken indicated that plants operate at full capacity or not at all, i.e.,
operators run the plants in short bursts at full capacity rather than longer periods at
lower capacity-utilization levels, the omission of marginal cost analysis was not
considered a limiting factor.
RESEARCH RESULTS
The global supply of methanol includes product supply that is not available to the U.S.
To describe the U.S. supply condition, global supply is adjusted downward to reflect only
those countries that already supply or can be expected to supply methanol to the United
States. An approximation of the short-run U.S. supply curve, representing the minimum
delivered price of methanol from available capacity by quantity demanded, is presented
in Exhibit 1-3. Each point on the curve represents the price required to cover variable
production costs plus transportation costs of the least efficient producer in operation.
An approximation of the long-run supply curve, as shown in Exhibit 1-4, represents
estimated prices based on total production costs (fixed plus variable) plus transportation
costs. In both exhibits, the higher curve represents delivered costs (including
transportation to California) and the lower curve indicates the associated production
costs.
In the short run when conditions of excess capacity exist, variable costs determine price
and while detailed information on fixed costs for existing capacity would be of interest,
these costs cannot be reasonably estimated from secondary sources. The estimate of
fixed costs would require detailed analysis of each plant based on individual construc-
tion costs, age, opportunity costs of capital, financing costs and so on. However, in the
long run when capacity is designed to meet increased demand, the fixed plus variable
costs will determine price. The market shift from variable cost pricing (short run) to
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EXHIBIT 1-31
SHORT RUN METHflNOL SUPPLY CURVE
50
CD
00
C
o
Z30
D
0)
\
CO
c20
Q>
ylO
cr
o_
0
CRLIFQRNIR DELIVERED COSTS
f
r 1
RVERflGE VRR1RBLE
PRODUCTION COST
'0 1
CUMULATIVE OUTPUT
2345
(NAMEPLATE CAPACITY, BILLION GALLONS/YEAR)
COUNTRY
CUMULATIVE
CAPACITY CAPACITY
(MIL.GAL./YR)
PRODUCTION DELIVERED
COST PRICE
(CENTS/OAL.)
1 MEXICO
2 CANADA
3 TRINIDAD
* ARGENTINA
5 CHILE
6 BRAZIL
7 MALAYSIA
8 TAIWAN
9 CHINA
10 ARAB EMIRATES
11 BURMA
12 SAUDI ARABIA
13 BAHRAIN
1ft INDIA
15 ALGERIA
16 U.S.
60
62$
230
261
250
»5
220
6ft
256
267
50
A16
110
50
36
1,900
60
685
915
1.176
1.426
l.»71
1.691
1.755
2.011
2.278
2.328
2.7ftft
2,85ft
2.90ft
2.940
ft.8ftO
15.9
22.1
15.6
13.2
1ft. ft
17.3
20.5
20.6
20.8
1ft. 1
22.1
1ft. 5
15-2
23.3
16.9
33.7
18.9
23.7
25.6
26.2
26. ft
28.3
30.5
30.6
30.7
32.1
32.1
32.5
33.2
3ft. 3
3ft. 9
35.7
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EXHIBIT 1-4:
LONG RUN METHRNOL SUPPLY CURVE
CD
§7°
^50
o
O)
\
CO
40
£30
LLJ
ct:
CL
CflLlFORNIR OB.IVERED COSTS
r
nr
IJ
TOTflL PRODUCTION COSTS
SHORT RUN SUPPLY CURVE
20
10
°0 10
CUMULATIVE OUTPUT
20 30 40 50 60
(NAMEPLATE CAPACITY, BILLION GALLONS/YEAR)
COUNTRY
* CURRENT CAPACITY
1 CANADA
2 MEXICO
3 ALGERIA
5 ARAB EMIRATES
* BAHRAIN
6 SAUDI ARABIA
7 TRINIDAD
8 ARGENTINA
9 BRAZIL
1O U.S.
11 CHILE
12 CHINA
13 BURMA
14 MALAYSIA
15 INDIA
CUMULATIVE PRODUCTION DELIVERED
CAPACITY CAPACITY COST PRICE
(MIL. GAL./YR) (CENTS/OAL. )
_
ft. 600
1.500
17,600
2.OOO
ft 00
6.000
8OO
1.000
6OO
15.200
1.000
5OO
10O
600
200
ft. 840
9.*»0
10,9*0
28.5*0
30.5*0
30.9*0
36.9*0
37.7*0
38.7*0
39,3*0
5*. 5*0
55.5*0
56.0*0
56.1*0
56.7*0
56.9*0
_
»3.*
*3.O
»3.3
*3.5
*3.5
*3.5
»9.7
»7.*
»9.5
5*. 0
49.5
5*.»
5*.»
53.7
5ft. A
-
ftft.t
*5.0
52.3
52.5
52.5
52.5
5*.7
55.0
55.0
55.5
55.5
59.*
59.*
59.*
59.9
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total cost pricing (long run) requires the careful attention of policy makers. The
considerable price increase may stifle consumption and the attendent risks faced by
entrepreneurs (who must invest heavily) could result in a difficult period in the
transition to methanol.
The short-run curve has been superimposed onto Exhibit 1-4 to indicate the price
adjustment that will be required for the market to move from short-run (less-than-
fully-costed) production to long-run (fully-eosted) production.
Exhibit 1-5 presents the price estimates generated from the supply assumptions
described above.
In general, the cost per gallon of methanol will increase significantly as the demand for
methanol grows under each transition scenario. Moreover, an unstable market will
persist until the global demand for methanol approaches the level of supply that can be
produced from existing capacity, approximately eight billion gallons per year. Until
demand approaches the levels of available capacity, the product will be traded at a
price measured by variable costs and plants will be drawn into and out of production as
the price moves above or below the variable cost of individual production facilities.
REPORT OVERVIEW
The remainder of this report is organized as follows:
Chapter 2 provides a nontechnical overview of the methanol production process.
Chapter 3 discusses the supply and demand conditions at the global level, by world
regions and within the U.S.
Chapter 4 sets forth the assumptions for and estimates of the production costs of
current methanol producers. The variable costs (including incidental fixed costs) are
detailed by the categories of feedstock, maintenance, catalyst, utility, and other costs.
Fixed costs associated with capital are discussed qualitatively, no estimates are
provided.
Chapter 5 examines the delivery system and presents estimates of current delivery
costs and explains potential economies of scale that might be achieved in high demand
scenarios.
9
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EXHIBIT 1-5;
FORECASTED METHANOL PRICES
BY SCENARIO. FOR SELECTED YEARS
(1986 Dollars per gallon, FOB Los Angeles, Excluding Taxes)
California California National National
Low High Low High
Year Demand Demand Demand Demand
1990 .36 .36 .36 .36
1995 .40 .40 .45 .50
2000 .45 .45 .46 .55
10
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Chapter 6 provides a discussion of the market changes that will move the market from
variable cost pricing to fully costed (fixed plus variable costs) as demand increases.
Estimates are presented for fixed, variable and total costs of future methanol capacity.
Chapter 7 summarizes the estimates presented in previous chapters into the estimated
delivered cost of methanol to U.S. destinations. A discussion of the sensitivity of the
estimates according to primary assumptions is also included. The recommended use of
estimates, including limitations, is discussed.
Finally, general caution to all readers is appropriate. The information used to develop
the estimates in this report represents an extensive collection of secondary
information. The estimates reflect the data available from these sources, and averages
or assumptions as noted, and the research effort was limited by the available
information. Actual operating costs, by plant, were not available for current suppliers.
Site-specific engineering estimates were not used to estimate the capital costs for
future suppliers. Natural gas costs were developed from inference, assumptions and
anecdotal information because the current prices paid by individual producers were not
available and future prices in a quite different marketplace are highly speculative.
Generally, the research results presented herein are a first step in understanding the
current and future methanol marketplace. Additional research, comments (and
criticisms) from participants in the industry and input from policy makers worldwide
will enhance and refine the preliminary estimates presented here.
Com ments regarding this report are encouraged and can be directed to:
Mike Gold or Jeff Alson
U.S. Environmental Protection Agency
Office of Mobile Sources
2565 Plymouth Road (SDSB-12)
Ann Arbor, Michigan 48105
and/or
Michael Lawrence or Linda Lent
Jack Faucett Associates, Lie.
7300 Pearl Street Suite 200
Bethesda, Maryland 20814
11
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CHAPTER 2
METHANOL PRODUCTION PROCESSES
This chapter presents a general description of the chemical process and physical plant
operation of methanol production. Since all available world capacity is currently
operated or last operated in the production of chemical grade methanol, the following
discussion is limited to chemical grade methanol processing. The production process of
methyl tertiary butyl ether (MTBE), a high octane additive to gasoline that is produced
from methanol, is also included.
FEEDSTOCK
According to available information, over 90 percent of the available world methanol
capacity is designed for natural gas feedstock because of its higher relative hydrogen
content. Higher capital costs are required to process other feedstocks (naphtha,
residual oil, coal and lignite) due to their lower hydrogen content. While limited
production of methanol from feedstocks other than natural gas is undertaken, these
processes tend to be less efficient (naphtha, residual oil), not fully commercially tested
(coal and lignite) or not commercially available (wood and other biomass processes).
For these reasons the following pages are limited to a discussion of the processes used
to produce methanol with natural gas as the feedstock.
PROCESS TECHNOLOGY
Prior to 1923 methanol was produced by the destructive distillation of wood from which
it obtained its common name, wood alcohol. The Haber chemical process, the
fundamental chemical reaction underlying all synthetic methanol production, was
introduced commercially in 1923. In this process the feedstock was burned to produce a
synthesis gas. Once the correct composition of synthesis gas was obtained, the
conversion to methanol was obtained under high pressure and temperature in the
presence of a chromium oxide - zinc oxide catalyst.
The single most important improvement in methanol production came in the 1960*8,
when a low-pressure synthesis process using a copper-based catalyst was developed.
Methanol could then be produced by bringing a synthesis gas (primarily hydrogen and
12
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carbon monoxide) into contact with a catalyst under a relatively lower pressure (about
50 atmosphere:
in Exhibit 2-1.
50 atmospheres) and at a temperature of 270 C. The steps of this process are outlined
The two commonly-used low-pressure processes are the Imperial Chemical Industries'
(ICO Process, and the Lurgi Process. Every low-pressure methanol plant in the world
today uses one of these or a similar process. There are many similarities between
processes used worldwide, but the main differences are in the proprietary catalyst, the
configuration of the feeding of the synthesis gas over the catalysts, heat recovery, and
the handling of the recycle stream.
In an efficiently operated plant both the reforming catalyst and the synthesis catalyst
last four to five years before the catalysts' performance fall below acceptable levels.
Catalyst activity is carefully monitored by observing the conversions-per-pass in the
processing cycle.
Plant size also impacts the efficiency of plant production. Plant size is usually
indicated by tons-per-day. In the early ISTO's 500 tons per day plants were operated by
a single train and considered large. Plants built since have achieved significant
economies of scale at up to 1,500 - 2,000 tons per day and are also operated with single
trains though additional efficiency above this size may not be possible.
Today's methanol plants are highly instrumented and automated facilities. Under
favorable conditions these plants are operated for a year or longer without shutdown.
Shutdowns are either unscheduled, where unexpected mechanical or catalyst problems
have developed, or scheduled at 12-18 month intervals to do periodic maintenance and,
if needed, change-out the catalyst charges. Day-to-day operating considerations are
worker safety, protecting the plant from damage, yields, product quality and thermal
efficiency.
Many methanol plants are located within a chemical or refinery complex and are
integrated within that complex with respect to hydrocarbon supply and utilization,
energy conservation and plant management. In U.S. petrochemical plants and
refineries, periodic maintenance is generally performed by independent contractors. In
areas where these units are concentrated, contract maintenance and plant
"turn-arounds" by maintenance contractors have many advantages including lower year-
round staff costs for the plant operator. The only reasonable efficiency improvement
13
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EXHffirr 2-1;
SIMPLIFIED GAS-BASED METHANOL PRODUCTION PROCESS
1.
2.
3.
4.
5.
Desulfurization of feedstock to remove sulfur compounds that would otherwise
poison the reforming and synthesis catalysts.
Feedstock is reformed and cooled, which means it is combined with steam at a
specific ratio, preheated and distributed to nickel-based catalyst-filled tubes in
the reformer radiant section. The reformer furnace is fired by the feedstock and
tail gas from the synthesis step.
Basic Reactions Occurring:
CH4(methane)
-CO
3H2 and
CO + H2O
This synthesis gas, composed mainly of carbon monoxide, hydrogen, carbon
dioxide and* some unconverted methane, leaves the reformer, and is subjected to
several gas-cooling steps. These steps utilize heat-recovery to save heat for use
in power generation, preheating, and rebelling purposes in the following
distillation step.
The next step is synthesis gas compression: the synthesis gas is compressed by a
steam turbine-driven compressor to the synthesis pressure.
The compressed gas is combined with an unconverted recycle stream (already
compressed in a recycle gas compressor), preheated in a heat exchanger, and
delivered to the methanol converter within the methanol synthesis step.
Basic Reactions in Converter are:
2H2 + CO
CHjOH (methanol) and
6. The water and other compounds (resulting from side reactions) are removed in
the final distillation step.
Source: World Bank, Emerging Energy and Chemical Applications of Methanol;
Opportunities for Developing Countries. April 1982.
rgy
Coi
14
-------
related to existing plant operation would be improvement of the catalyst to permit
lower pressure processing.
In summary, a large percent of the available world-wide capacity for the production of
methanol is characterized by a natural-gas fed plant operated by a low-pressure process
fed by a single train and capable of processing 1500 or more tons per day. The plants
are frequently operated within a refinery and physical inputs are characterized by the
feedstock and catalysts, which must be replaced every 4-5 years. Moreover, older
plants may utilize a less-efficient high-pressure process or be smaller and fail to
achieve the economies of scale associated with the larger (newer) plants. A limited
number of plants are designed to use residual oil or naptha as a feedstock. The use of
coal/lignite as a feedstock is in the commercial-testing phase and no commercial plants
operate using wood or other biomass feedstock.
Methyl tertiary butyl ether (MTBE) is a product produced from methanol that has
gained acceptance as a high-octane fuel additive. MTBE, like methanol, is well suited
for refinery production. The production of MTBE from methanol is described below.
METHYL TERTIARY BUTYL ETHER
Methyl tertiary butyl ether (MTBE) is one of the most popular of the recently developed
uses of methanol. It is an excellent high-octane additive because it is completely
compatible with gasoline, is relatively inexpensive to produce, and the transportation
and distribution pose no major problems. For these reasons, MTBE has frequently
replaced toluene as the standard octane-enhancer. The MTBE process is a means of
converting isobutylene into a quality blending agent well suited for alkylation
operations at many refineries (see Exhibit 2-2).
15
-------
EXHIBIT 2-2;
TWO-STAGE MTBE PROCESS
(T Feed Stock
MEOH
Primary
Reactor
Important Characteristics
The MTBE process is well suited for large refinery/petrochemical
facilities, because the isobutylene required for the etherification of the
methanol feedstock is available from several other petrochemical
production streams.
The MTBE process is capable of operating on a mixed butane/butylene
stream.
The MTBE process can be located anywhere isobutylene is available at
market prices.
Methanol accounts for roughly one- third of the feestock of the MTBE
process.
Source: Department of Commerce, A Competitive Assessment of the U.S. Methanol
Industry. May 1985.
-------
CHAPTER 3
WORLD METHANOL CAPACITY
This chapter presents estimated world methanol capacity and examines the supply-
demand relationships by major regions. The estimates developed in this study represent
the first comprehensive plant-specific estimates of global capacity and were derived
from a wide range of sources. As such, the estimates are subject to considerble error.
Plant specific data on world methanol capacity is unreliable and estimates available
from the various sources are often conflicting. Information on individual plant
capacities, production processes, feedstocks and ownership for North America, Western
Europe, and Japan are available in the Chemical Economics Handbook (Stanford
Research Institute), but this information is somewhat dated. The United Nations
Industrial Development Organization (UNIDO) has provided information on capacities in
the developing and selected developed countries by country and year, however, some
guesswork is often required to infer individual plant capacities from this data.
Information on the plant capacities in the Eastern Bloc countries is even more
aggregated and contradictory than that for the developing countries. Numerous other
sources provide information on U.S. capacity as well as data on selected new plants.
Exhibit 3-1 provides estimates of plant capacities, production processes, feedstocks and
ownership by plant and country. These estimates were developed through the
comparison of all available information provided in the various sources listed at the end
of the exhibit. Plant capacities that are presented represent plants that were identified
in at least two sources. The footnotes contain the actual estimates provided in the
sources along with the expected opening date for plants under construction or in
planning stages. New plants that were listed in only one source and were not
substantiated by any other source are shown with zero capacity. Plants that were
identified as shutdown were included if it was believed that they were capable of
reopening and if they had operated recently (since 1983) Additionally, for U.S. plants,
the location of the plant and last known status (if not operating) is indicated.
Most sources of capacity data are stated in nameplate capacity, the theoretical upper
limit of a plant's productive ability. It is the maximum theoretical annual output under
ideal working conditions. No plant, under normal circumstances, ever achieves this
level of efficiency. There are usually shutdowns for routine maintenance and/or for
17
-------
EXHIBIT »-li
IDENTIFIED ESTIMATES OP MBTHANOL CAPACITY BY PLANT
AND COUNTRY. IMP (MUUoo« of Gallons)
(Conversion Pactori 3)4.$ fallow per metric ton)
(Convention Pactori 127.$ million faUons/yeer « 2000 tons/day)
Location
NORTH AMERICA
United States
Canute
Mtzioo
gUTBRN EUROPE
Austria
Pranea
Italy
Netherlands
Norway
Spain
Sweden
United Kingdom
Wait Germany
Capacity
(Mil. Oal./Yr.)
0
130
200
200
150
230
2$0
200
126
100
100
13$
60
240
240
14$
$7
67
10
11
12
13
14
IS
16
It
20
21
22
23
20
72
2$
40
-TIT
20
39
241
0
as
20
10
11
221
60
67
134
0
~~2TT
12
13
13
13
14
Paaditock (Procaai)
Natural Oat (1C! Low Preesure) ,
Natural Gas (Lurfi Low Pressing)
Natural Oat (ICI Low Pressure)!
Natural Oai (1C! Low Preseurer ,
Natural Gas (Lurfi Low PressUM)*
Natural Oa* (1C! Low Pressure)* ,
Residual Pual Oil (Lurfl Low Pressure)*
Natural Oai (Lurfl Low Preaautt)
Natural Oat (ICI Low Pressure)1 .
Refinery Gai (Lurfi Low Pressure)
Natural Gas (ICI Low Pressure)* .
Natural Gas (Lurfl Low Pleasure)
Coal (Lurfi Low Pressure)
Natural Gas (ICI Low Pressure)}'
Natural GasjUCI Low Pressure)
Natural Gas1*
Natural Gas*
Ownership
Air Produc/s'-PanaaeoU, PL
Allemania -Plaquamlna, LA (tamp cloaad 7/64)
ARCO Chemical .HctUfton. TX. /
Bordan Chemical1"'3*11''1"' <** (pvtlally cloaad)
Celaneae Cnemlcal|-Bishop, TX
Celane^ Chemlcal'-Clear Lake, TX (cloaad)
Du Pont'-Oaar Park, TX (cloaad)
Du Pont -Beaumont, TX
Georfla, Pacific-Plaquemine, LA
Texaco -Delaware City, DE (mothballad)
Monsanto -Texas City, TX (may soon cloaa)
Tenneco -Houston, fX
Tennessee Eastman -Klnfsport, TN
Alberta Gas Chemicals Limited17
Celaneae Canada
Ocelot Industries Limited17
Afeerta Gas Chemicals Limited10,,
Blewaf Energy Resources Limited11
PEMEX
PEMBX
24
Natural OasIICI Low/Medium Pressure)1 Association du Mathanol da VUlars Saint-Paul'
M»ti».i nmm" n^hi«.« V.IM iriit.i_.._ »*
Natural Gas!
Natural Gas*
Refinery off-fas (Montedison)3
Natural Gas (Pauser)*
Pechiney Vfine Kuhlmano
Societe Uethanolacq 8A
EniChem*
EniCnam'
Natural Gas (ICI Low/Medium Pressure)3 MeUianor,VoP3
Methanor7
Norsk Hydro «J. ($1% State owned)3
DYNO*
Natural Gas (ICI Proceas)"
Refinery off-fas (ICI Low Pressure) Compania Espanola da Petroleoa3
Natural Gas (ICI Low/Medium Pressure)3 Imperial Chemical Industries (ICO3
Natural Gas (BASF Process)3 BASP Aktienfesellschaft3 .
Heavy Oil, Chemisette Werke Huels AG9 ,
Heavy Oil9 Union Rhelnlsche Braunkohlen Kraftstoff AG3
Shell
18
-------
EXHIBIT 3-1 1 - (continued)
Location
LATIN AMERICA
Argentina
Bolivia
Braxfl
Chfle
Trinidad
MIDDLE BAST
Saudi Arabia
Bahrain
D.A. Emirates (Sharjah)
ASIA
Burma
Bangladesh
China
Mia
Korea
Malaysia
Philippines
Taiwan
IDENTIFIED ESTIMATES OF
AND COUNTRY,
(Conversion Factor i
(Conversion Factor i I2T.I
Capacity
(MO. Oal./Yr.) Feedstock
»
200 *
50 *
2H
12 5
45 «
250 7
ISO '
100 "
~TW
36 1
110 «
110 3
TBS
200 }
-»
no4
267 «
501
O2
87
35 |
134 *
21?
»
20 5
w
no7
in*
no *
-TTO
711
64 "
Mo13
51
Natural Gas }!
Natural Gas ,Q
Natural Gas
Natural Gas 10
Natural Gas 10
Natural Gas 10
Natural Gas |?
Natural Gas
Natural Gas 8
Natural Gas f.
Natural Gas
Natural Gas I
Natural Gas '
Natural Gas T
Natural Gas 7
Natural Gas 14
Natural Gas }1
Natural Gas : J
Natural Gas
Natural Gas JJ
Natural Gas
Natural Gas 14
Natural Gas }1
Natural Gas
Natural Gas 14
Natural Gas 14
METHANOL CAPACITY BY PLANT
1990 (MUlkMs.oT Oallons)
334. $ gallons per metric ton)
million gallons/year 2000 tons/day)
(Process) Ownership
Petroqulmlca Austral , Huarpes
Recinfor7
Signal Group
NEC3
NMC4, State5
SaMo/Japan* .
SaMc/Olanese
Gulf Petrochemicals5, GPIC2
Beslmco
Petronas', Sabah.10
Bordon*, Sabah10
CPDC9
19
-------
Location
OTHER PACIFIC
Japan
Australia
N«w Zealand
hdonesie
EASTERN BLOCK
East Germany
U.S.S.R
Yugoslavia
WORLD TOTAL
EXHIBIT 8-11 - (continued)
IDENTIFIED ESTIMATES OF METHANOL CAPACITY BY PLANT
AND COUNTRY, 1HO (Millions of Gallons)
(Conversion Faetori JJ4.5 gallons par metrle ton)
(Conversion Faetori 11T.S million gallons/year 20M torn/day)
Capacity
(MO. Oal./Yr.)
133
44
0
130 87
495 ">T
114
200 l
700 3
m.'
~m
310;
67 "
Feedstock (Process)
Natural Gas (Mitsubishi Process)?
Natural Gas (Mitsubishi Process)*
Natural Gas
Natural Gas (Lurgi)
(ICO9
Ownership
Mitsubishi Gas Chemical Co., Inc.2
Mitsui Toatsu Chemicals, Inc.
Petral Gas, .
Petral Gas8, N2/Mobil°
MSKJ
»,743
SOURCES
(ON 15) Current World Situation In Petrochemicals. UNIDO/PC.1J8 United Nations Industrial Development Organization, November 14, 19(5, Amez
1 and Annex 2, and a special supplement entitled Methanol Capacities in the Developing Countries, provided by UNIDO Sectoral Studies
Branch, Vienna, Austria.
(CB M) "More Hitches in Methanol's Growth Plan", Chemical Business. June 1984, p. 28.
UPL 83) Jet Propulsion Laboratory, California Methanol Assessment, Volume H: Technical Report, pp. 7-7, 7-8.
(TBNN 85) Simmons, Richard E. (Sales Manager for Methanol of Tenneco Ofl Company), Methanol-World Supply/Demand Outlook, presented at the 1985
National Conference on Alcohol Fuels, Renewable Fuels Association, Washington, D.C., September 1985.
(DOC 85) Department of Commerce, A Competitive Assessment of the U.S. Methanot Industry, May 1985, p. 35.
(*MC 85) Papers presented at the "1985 World Methanol Conference", especially paper IV, p. 3.
(CHBV 84) Chevron U.S.A. Inc., The Outlook for Use of Methanol as a Transportation Fuel, November 1984, Table 1-1.
(HU83) Stanford Research Institute International, Chemical Economies Handbook, October 1983, pp. 874.5022J, 674.5022K, (74.5025B, 674.502SF.
674.S025G, 674.5022K.
20
-------
EXHIBIT 3-11 (continued)
FOOTNOTES
For each footnote capacity is given in million gallons per year as provided in the
reference document (except where it has been converted from metric tons). Following
the capacity figures are source citations as provided above. For example, the first
footnote indicates that sources (CB 84), (WMC 85), (CHEV 84) and (DOC 85) reported
capacity for this plant as 60 million gallons per year, while the source (SRI 83) reported
capacity for this plant as 50 million gallons per year.
The (*) denotes that plant capacity, which is shown in million gallons per year, was
converted from metric ton data in the original source. This conversion is based on a
factor of 334.5 gallons per metric ton. This factor was derived from the number of
pounds in a metric ton (2204.6) and the number of pounds in a gallon of methanol (6.59).
The number of pounds in a gallon of methanol is from Arthur M. Brownstein, U.S.
Petrochemicals, The Petroleum Publishing Company, Tulsa, Oklahoma, 1972, p. 81.
Footnotes for North America
1. 60 (CB 84) (WMC 85) (CHEV 84) (DOC 85), 50(SRI83).
2. (SRI 83).
3. 130(CB 84) (WMC 85) (CHEV 84) (DOC 85) (SRI 83).
4. 200 (CB 84) (WMC 85) (CHEV 84) (DOC 85) (SRI 83).
5. 200 (CB 84) (WMC 85), 190 (CHEV 84), 210 (DOC 85), 200-210 (SRI 83).
6. 150 (CB 84) (WMC 85) (CHEV 84) (SRI 83), 145 (DOC 85).
7. 200 (CB 84), 230 (WMC 85) (CHEV 84) (DOC 85) (SRI 83).
8. 250 (CB 84) (WMC 85) (DOC 85), 225 (CHEV 84), 200 (SRI 83).
9. 200 (CB 84) (WMC 85) (CHEV 84) (DOC 85), 250 (SRI 83).
10. 126 (CB 84) (WMC 85), 120 (CHEV 84) (SRI 83), 130 (DOC 85).
11. 100 (CB 84) (WMC 85) (CHEV 84) (DOC 85) (SRI 83).
12. 105 (CB 84), 100 (WMC 85) (CHEV 84) (DOC 85) (SRI 83).
13. 135 (CB 84) (CHEV 84), 130 (WMC 85) (SRI 83), 150 (DOC 85).
14. 0 (CB 84), 60 (WMC 85) (DOC 85), 65 (CHEV 84), 50-65 (SRI 83).
15. 240 (CB 84), 240.8* (SRI 83).
16. (SRI 83).
17. (CB 84) (SRI 83).
18. 240 (CB 84), 234.2* (SRI 83).
19. 145 (CB 84), 133.8* (SRI 83).
20. 240 (CB 84), 0 (DOC 85). Alberta Gas Chemicals Limited Plant in Scot ford,
Alberta. No target date; no site work started yet (CB 84).
21. 530 (CB 84), 0 (DOC 85). Biewag Energy Resources, Ltd., plant in Waskatenau,
Alberta. No target date; still seeking government approvals (CB 84).
22. 57.2* (UN 85), 57 (CB 84), 57.5* (SRI 83).
23. 218.8* (UN 85), 275 (CB 84), 270 (JPL 83), 220 (DOC 85). To be added in 1988
(UN 85), in 1986, or later (CB 84), 1985 (JPL 83), planned or under construction
(DOC 85).
24. (JPL 83).
Footnotes for Europe
1. 30 (DOC 85), 22.1 * (TENN 85).
2. 100 (DOC 85), 132 (CB 84), 97*(TENN 85), 137.1* - 3 plants of 71.9*, 25.1*,
40.1* (SRI 83).
3. (SRI 83).
21
-------
EXHIBIT 3-1; (continued)
Footnotes for Europe (continued)
4. 35 (DOC 85), 93 (CB 84), 67*(TENN 85), 58.5» 2 plants of 20.1*, 38.5* -(SRI
83).
5. 230 (DOC 85), 240 (CB 84), 247.5*(SRI 83).
6. 140 (JPL 83), 0 (DOC 85), 0 (CB 84). To be added in 1986 (JPL 83), planned or
under construction (DOC 85).
7. (JPL 83).
8. 20.1* (TENN 85), 20.1* (SRI 83).
9. 170 to be added in 1988 (JPL 83).
10. 68 (CB 84), 73.6* TENN, 66.9* (SRI 83)
11. Proposed capacity of 233 (CB 84).
12. 240 (DOC 85), 270 (JPL), 220.8* (SRI 83).
13. 275 (DOC 85), 223 (CB 84), 281* 3 plants of 80.3*, 66.9*, 133.8* (SRI 83).
14. 0 (DOC 85), 0 (CB 84), 130 to be added in 1987 (JPL 83).
Footnotes for Latin America
1. 12.0* (UN 85), 11 (CB 84), or 10 (DOC 85)
2. 228.8* (UN 85), 100 (CB 84), 250.9* plants 200.7* and 50.2* TENN (85). 200
(JPL 83), (DOC 85). To be added to capacity in 1988 (UN 85), target 1987-1988 +
(CB 84), 1988-1989 (TENN 85), 1986 (JPL 83).
3. (TENN 85)
4. (JPL 83)
5. 12.4* (UN 85).
6. 56.9* (UN 85), 30 (CB 84), 45 (DOC 85). Note: UN 85 shows capacity in Brazil
at 51.2* in 1983-1984, increasing to 56.9 in 1985 and to 70.2 in 1988.
7. 254.2* (UN 85), 280 (CB 84), 200.7 (TENN 85), 250 (DOC 85). To be added to
capacity in 1988 (UN 85), planning stage, no target date (CB 84), 1988-1989
(TENN 85).
8. 130.5* (UN 85), 145 (CB 84), 110 (JPL 83), 140 (DOC 85).
9. 89.0* in unspecified Latin American country (UN 85), 0.0 (CB 84), 100.4 (TENN
85), 0.0 (JPL 83), 340 (DOC 85).
10. This plant is assumed to use natural gas as a feedstock based on the authors
general knowledge of the methanol industry. No specific reference was
available.
Footnotes for Africa
1. 36.8* (UN 85) or 36 (CB 84).
2. 110.4* (UN 85) or 0.0 (CB 84).
3. 110.4* (UN 85), 120 (CB 84), 100.4* (TENN 85), 110 (JPL 83). To be added to
capacity in 1986 (UN 85), reportedly 1985 (CB 84), 1985-1986 (TENN 85), 1984
(JPL 83).
4. (JPL 83).
5. (TENN 85).
6. This plant is assumed to use natural gas as a feedstock based on the authors
general knowledge of the methanol industry. No specific reference was
available.
Footnotes for the Middle East
1. 200.7* (UN 85), 200 (CB 84) or 220 (JPL 83). To be added to capacity in 1983
(UN 85), 1984 (CB 84), 1984 (JPL 83).
22
-------
EXHIBIT 3-1: (continued)
Footnotes for the Middle East (continued)
2. (JPL 83).
3. 217.4* (UN 85), 216 (CB 84) or 220 (JPL 83). To be added to capacity in 1984
(UN 85), 1985 (CB 84), 1985 (JPL 83).
4. 110.4* (UN 85), 120 (CB 84), 100.4* (TENN 85), 110 (JPL 83). To be added to
capacity in 1985 (UN 85), early 1985 (CB 84), 1985-1986 (TENN 85), 1985 (JPL
83).
5. (TENN 85).
6. 267.6* at unspecified Middle East location (UN 85), 432 (CB 84), 167.3 in Sharjah
(TENN 85). To be added to capacity in 1985-1990 (UN 85), late 1980's (CB 84),
1988-1989 (TENN 85).
7. This plant is assumed to use natural gas as a feedstock based on the authors
general knowledge of the methanol industry. No specific reference was
available.
Footnotes for Asia
1. 50.2*(UN 85), 55 (CB 84), 50.2* (TENN 85), 50 (DOC 85). Existing (UN 85),
probably added in 1986 (CB 84), to be added 1985-1986 (TENN 85).
2. 110 (DOC 85), 110 (JPL 83). Planned or under construction (DOC 85), to be
added in 1986 (JPL 83).
3. 133.8* - 2 plants 87.0* and 46.8* (UN 85), 35 (JPL 83), 35 (DOC 85).
4. 133.8* (UN 85), 35 (DOC 85). Added in 1989 (UN 85).
5. 45.2* (UN 85), 27 (CB 84), 30 (DOC 85).
6. 0.0 (UN 85), 17 (CB 84), 20.1* (TENN 85), 20 (DOC 85). Planning stages (CB 84),
to be added in 1985-1986 (TENN 85).
7. 110.4* (UN 85), 18 (CB 84), 0.0 (DOC 85)
8. 200.7* (UN 85), 240 (CB 84), 200.7 (TENN 85), 220 - 2 plants 110 each - (JPL
83), to be added in 1985 or before (UN 85), planned, no target date (CB 84), 1985-
1986 (TENN 85), 1986 (JPL 83).
9. (JPL 83).
10. (TENN 85).
11. 6.7* (UN 85).
12. 63.6* (UN 85), 232 (CB 84), 35 (JPL 83), 20 (DOC 85), existing capacity except
(JPL 83) which shows addition in 1983.
13. 220 (CB 84), 0.0 (DOC 85). To be added in early 1984 (CB 84).
14. This plant is assumed to use natural gas as a feedstock based on the authors
general knowledge of the methanol industry. No specific reference was
available.
Footnotes for Other Pacific
1. 133.8* (UN 85), 117 (CB 84), 130 (DOC 85), 176.6* - 2 plants of 132.5* and 44.2*
(SRI 83).
2. (SRI 83).
3. 0 (UN 85), 33 (CB 84), neg. (DOC 85), 200 (JPL 83). Planning stages, no date (CB
84), planned or under construction (DOC 85), to be added in 1985 (JPL 83).
4. 110 (DOC 85), planned or under construction.
5. 135 (CB 84), 130 (DOC 85), 130 to be added in 1984 (JPL 83).
6. 0 (JPL 83) (CB 84), 495 (DOC 85), 501.8* (TENN 85), 200 (JPL 83), planned or
under construction (DOC 85), to be added in 1985-1986 (TENN 85), to be added in
1987 (JPL 83).
7. For conversion to gasoline (TENN 85), for conversion to gasoline by the Mobile
MTG process (DOC 85).
8. (TENN 85).
9. This plant is assumed to use natural gas as a feedstock based on the authors
general knowledge of the methanol industry. No specific reference was
available. 23
-------
EXHIBIT 3-1; (continued)
Footnotes for Eastern Block
1. 200.7* (TENN 85). To be added to capacity in 1985-1986.
2. (TENN 85).
3. 700 (CB 84) capacity is most likely in several plants but no information on
individual plants was available.
4. 270.9* (TENN 85), 270 (JPL 83). 600 - 2 plants - (CB 84), to be added in 1985-
1986 (TENN 85), in 1983 (JPL 83), in 1984-1985 (CB 84).
5. (CB 84).
6. (JPL 83).
7. 310 (CB 84) Figure for East Block Nations other than U.S.S.R.
8. 66.9* (TENN 85), 135 (JPL 83). To be added in 1985-1986 (TENN 85), in 1982
(JPL 83).
24
-------
equipment breakdowns. Most observers believe that 90 percent nameplate capacity is a
reliable indication of maximum annual output. Thus, a reasonable indicator of
maximum available capacity is 90 percent of the capacity shown in Exhibit 3-1. The
capacities in the various sources were stated in one of three ways: (1) millions of
gallons per year, (2) tons per year or (3) tons per day. These estimates were translated
into millions of gallons per year (if required) by converting tons to gallons (334.5
gallons/ton). Per day capacities were annualized based on 340 operating days/year.
Ill is represents an ideal engineering capacity, allowing appropriate time for current and
preventative maintenance. In addition, factors such as weather, input difficulties,
shipping and other natural and market occurrences will result in actual output less than
potential. (Another useful equivalence is that 2000 tons/day equals 227.5 million
gallons/year.)
Today's methanol producers primarily supply chemical grade methanol to chemical
plants worldwide. The market for chemical methanol is characterized by tremendous
excess capacity relative to the current levels of demand and considerable surpluses of
product on the market in recent years. Product price has fallen to quite low levels
resulting in the closure of a number of plants, usually (or hopefully) on a temporary
basis. As mentioned above, the capacity estimates in Exhibit 3-1 include plants that
are closed but still believed to be in operable condition. The generating
status of U.S. plants, as of January 1986, is given in the exhibit. Due to limited resources
the status of all other plants worldwide could not be verified.
In spite of the poor market conditions facing the methanol industry, it is interesting to
observe the amount of capacity that has been or is scheduled to be added to world
capacity. Moreover, it is unlikely that the large amounts of capacity additions have
been made based on the stable but relatively slow growth trend (2-3 percent above GNP
in the U.S.) of the demand for chemical methanol. It is easier to speculate that
producers are positioning themselves for an expanded market demand. Growth in the
demand for fuel methanol or methanol derivatives such as MTBE are favorable
candidates.
25
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WORLD METHANOL SUPPLY AND DEMAND
The pattern of global methanol consumption relative to capacity in millions of gallons
since 1980 is as follows :
1980 1981 1982
Total Available (100%) Capacity: 4,783 4,984 5,051
Consumption: 3,880 3,613 3,579
Surplus Capacity: 903 1,371 1,472
Percent Plant Utilization:* 81 72 71
Note that 90% of utilization is the expected operating level of an efficient plant.
1
Data through 1984 calculated from data in "Methanol World Balance" by Robert Coxon
as presented to the 1985 World Methanol Conference, Amsterdam, December 1985.
Data are converted from metric tons: One metric ton equals 334.5 gallons of methanol.
It should be noted that the capacity shown in Exhibit 3-1 includes capacity built since
1984 as well as plants recently closed. Coxon % estimates have been adjusted for plant
closures. Moreover, by 1990 the numbers become more dramatic. According to the
identified capacity listed in Exhibit 3-1, available nameplate capacity (100%) would
equal 8,100 million gallons, excluding 625 million gallons of capacity in New Zealand
that is earmarked for conversion to gasoline. If consumption for chemical uses rises at
the 4.0 percent per year, demand will increase to about 5,300 million gallons. Others,
such as the World Bank and the 1985 Methanol Conference have suggested higher 1990
demands of about 5,700 million gallons (a 5.2% increase, see Exhibit 3-2). The implied
surplus capacity in 1990 would be 2,400-2,800 million gallons. This is nearly 200
percent of the 1983 surplus, the highest level of excess capacity since 1980. The
capacity utilization rate would be approximately 68 percent (the desirable utilization is
90 percent). Of course, if conditions such as these do occur, it is likely that some
portion of the available capacity that has been or will be temporarily closed will be
permanently closed/dismantled thereby reducing the surplus capacity. To the extent
that investors wish to hold on to capacity, the plants can be shut-down and operated
periodically (as demand/price levels for methanol permit) or with new technology
removed and mounted on a floating platform to take advantage of low feedstock and/or
transportation costs that might be available to a "floating*1 plant that would not be
available to a stationary plant. While the world balance of supply and demand for
chemical methanol depict a universal surplus of methanol, specific world regions will be
affected more directly by local conditions of supply and demand, as discussed below.
26
-------
LOCAL METHANOL SUPPLY AND DEMAND
The projected capacity/supply and demand for chemical methanol (millions of gallons)
in 1990 is estimated in Exhibit 3-2. However, the estimates are misleading. In North
America, the U.S. has shutdown considerable capacity as is also true in Western Europe.
Thus, while it is possible for the U.S. and Western Europe to supply much of their
methanol requirements, the current situation is that demand requirements are more and
more being filled by lower-cost imported methanol. The U.S. imports primarily from
Canada and South America and Western Europe imports from other surplus producers.
Japan has the largest demand in the Far East/Asia and also imports much of its
requirements.
In general, the current (depressed) marketplace is dictated by countries that produce
with relatively lower cost that are located in South America, the Middle East and Asia.
This situation will continue unless additional demand supports production from higher
cost producers in North America and Western Europe. In fact, if current conditions
persist, production in North America and Western Europe will continue to drop.
Moreover, even if demand and price begin to climb, it is possible that additional
demand, in the long run, will be met by added capacity for low-cost producing regions
rather than by available (but underutilized) capacity in North America or Western
Europe.
U.S. METHANOL SUPPLY
For this analysis it is necessary to determine which countries are potential suppliers of
methanol to the United States. Exhibit 3-3 presents a listing of methanol producers and
the availability of their supply to the U.S. It has been determined that the methanol
produced in several countries would not be available to the U.S. for numerous reasons.
These include:
Country is situated in a net import region several regions, especially
Europe, are characterized as large net importers. It would be inefficient
for a European producer to export product to the U.S., given the high
transportation costs, when substantial market opportunities are available
in that region. It is also assumed that Korea will export any excess supply
to Japan based on the same reasoning.
27
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EXHIBIT 3-2;
LOCAL METHANOL SUPPLY AND DEMAND, 1990
(Millions of Gallons)
to
00
Region
North America
Western Europe
Far East/Asia
South America
Mid East/Africa
Eastern Europe
World Total
Demand
(World Methanol
Conference)
1,888
1,474
1,339
103
103
926
5,833
2
Demand
(World
Bank)
1,828
1,748
855
120
60
1,075
5,686
Available3
Supply
2,361
948
1,060
718
944
1,392
7,423
Surplus
(World Methanol
Conference)
473
(526)
(279)
615
841
466
1,590
Surplus
(World
Bank)
533
(800)
205
598
884
317
1,737
"Methanol: The More Distant Future,11 by James R. Crocco, presented to the 1985 World Methanol Conference,
The Netherlands, December 1985. Note that regional distributions are approximated based on graphs presented.
World Bank, Emerging Energy and Chemical Applications of Methanol; Opportunities for Developing Countries,
April 1982, p.48.
Calculated from Exhibit 3-1, 90 percent of nameplate capacity. In addition, 495 million gallons of capacity in
New Zealand, which is dedicated for conversion to gasoline, has been omitted.
-------
EXHIBIT 3-3:
AVAILABILITY OF METHANOL TO THE U.S.. BY COUNTRY
(Millions of Gallons Annually)
Supply
Supply Nameplate Not ,
Region/Country Available Capacity Available
NORTH AMERICA X 2,623
United States
Canada
Mexico
EUROPE 1
Austria
France
Italy
Netherlands
Norway
Spain
Sweden
United Kingdom
West Germany
LATIN AMERICA
Argentina X 261
Bolivia 2
Brazil X 45
Chile X 250
Trinidad X 230
AFRICA
Algera X 36
Libya 3
MIDDLE EAST X 793
Saudi Arabia
Bahrain
U.A. Emirates
ASIA
Burma X 50
Bangladesh 2
China X 256
India X 50
Korea 4
Malaysia X 220
Philippines 2
Taiwan X 64
OTHER PACIFIC
Japan 1
Australia 2
New Zealand 5
Indonesia X 114
EASTERN BLOCK
East Germany 3
U.S.S.R. 3
Yugoslovia 3
TOTAL 4,992
Nameplate
^Capacity
1,053
12
220
0
110
7
177
0
625
200
970
377
3,751
Key: 1 = Net Import Region
2 = Capacity Insignificant
3 = Supply Unavailable to U.S. (for political reasons)
4 - Excess Supply Exported to Japan
5 = Supply Used for Conversion to Gasoline
29
-------
Insignificant capacity several countries have extremely small methanol
capacity. It is assumed that the bulk of this supply would be used locally.
Supply unavailable to U.S. for political reasons it has been concluded
that several countries are unlikely to trade methanol with the U.S. These
countries include Libya, East Germany, the U.S.S.R., and Yugosalovia.
Supply used internally for conversion to gasoline the majority of the
capacity shown for New Zealand is for a plant which will directly convert
methanol to gasoline. Output from this plant will therefore be
unavailable to the U.S.
Except for the reasons stated above, production from each country has been assumed
available to the United States. To develop the U.S. supply curve, it is necessary to
adjust world supply for the supply that will not be available to the United States. As
shown in Exhibit 3-3, the non-U.S. suppliers' total is 3.751 billion gallons. After
adjusting for New Zealand's dedicated-to-gasoline production, the total is 3.1 billion.
In Exhibit 3-4, total demand is adjusted to exclude the demand that will not compete
with U.S. demand, by year. The adjusted demand is used to develop the supply curves,
and represents a rough approximation of the expected demand components. Moreover,
it is not possible to detail this demand adjustment by world regions, because the demand
estimates by region are sketchy and conflicting (see Exhibit 3-2).
30
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EXHIBIT 3-4:
WORLDWIDE METHANOL DEMAND SCENARIOS; ALL USES
(Millions of Gallons)
Projected Worldwide
Demand, Excluding
U.S. Transportation
Use
Year Total1
1990 5,700
1995 6,900
2000 8,400
Demand Not
Competing with
U.S.2
2,500
3,000
3,200
Demand Competing
with U.S.
Demand
3,200
3,900
4,700
Worldwide Noncaptive Demand, Including
U.S. Transportation Use
California
Low Demand
Case
3,200
3,930
4,830
California
High Demand
Case
3,220
4,010
4,950
National
Low Demand
Case
3,200
4,890
8,950
National
High Demand
Case
3,350
16,900
31,700
A four percent growth rate for chemical methanol demand is assumed. This is because the demand for chemical methanol
has been observed to increase with GNP in developed countries.
2
It is assumed that this quantity of demand will be satisfied by countries that do not supply the U.S. As shown in Exhibit 3-3,
there is 3.751 billion gallons of nameplate capacity for non-U.S. suppliers of which 625 million gallons is dedicated for
conversion to gasoline (New Zealand). The remaining 3.1 billion in capacity (and future additions to that capacity) is
assumed to operate at about 80 percent utilization in supplying noncompeting methanol users. Thus, the number in the table
is estimated based on an assessment of available capacity, not actual market demand.
Source: EEA and JFA estimates.
-------
CHAPTER 4;
THE COST OF PRODUCTION FROM EXISTING CAPACITY
This chapter presents estimates of the cost of methanol production available to the
United States by plants that are currently in operation, could be reopened, or are under
construction. Because the methanol industry is characterized by significant excess
capacity, methanol is now and will continue for some time to be available to the U.S. at
less than fully costed prices. A major premise of this report is that the short-run price
of methanol will be less than the lowest variable cost of the plants that are idle. This
determination is based on the economic principle that governs periods of excess
capacity: economic reasoning dictates that firms will produce methanol from existing
plants (sunk capital) if the market price exceeds the average variable cost of
production.
The methanol industry today is characterized by considerable excess capacity. Plants
produce methanol or close down production based on the current and expected market
price of methanol compared to the average variable costs of the individual production
facility. If the market price of methanol exceeds variable costs and a market for the
product is available, plants will operate because production is desirable so long as the
plant does not sustain operating losses. Though plant owners would prefer to cover all
costs of production (fixed and variable), losses are minimized as long as variable costs
are covered. Prices received in excess of variable costs (contributions to fixed costs)
are welcomed but not a prerequisite to the decision to produce for existing capitaL
Throughout this report, reference is made to the variable, fixed and total costs of
production. When comparing production costs to market prices, the correct comparison
is average variable costs (or average total costs for new capacity) and market prices.
For most types of production, average variable (or average total) costs vary with
respect to output (capacity utilization) at the plant level. Thus, a unique average
variable (or average total) cost is associated with each potential level of plant output.
However, in this study, when average variable (total) costs were estimated, only one
estimate was made: the average variable (total) cost of production at full (about 90%)
operating capacity. No estimates were made for lesser (or greater) levels of output
32
-------
because no data were available to support these estimates and their omission was not
considered limiting. Moreover, available evidence indicates that plant owners are more
likely to run at full capacity for short periods of time (on a campaign basis) than less
than full capacity for longer periods. Thus, throughout this report, the estimates and
references to variable, fixed or total production costs represent the average (per unit of
output) variable (fixed, total) cost of production at full capacity. These measures are
appropriately compared to the market price per unit of output (gallon) of methanol.
Because firms (in this case existing methanol plants) will maximize profits (minimize
losses) in the short run by producing when variable costs are covered, the identification
of the variable cost of each producer leads to the development of the short-run industry
supply curve. The short-run supply curve of the industry is, by definition, a composite
of the average variable cost curves of each plant operating in the industry. As the
product demand increases and approaches the potential level of supply from existing
capacity, the price will increase and returns to capital for the highest cost producer
may be achieved. At the point where entrepreneurs believe that new capacity can be
expected to recover fixed and variable costs (and perhaps excess profits/economic
rent), decisions to invest in additional capital (that may require higher market prices to
cover fixed and variable costs when compared to existing capacity) will formulate the
long-run supply curve. Long-run costs based on future capacity are discussed in
Chapter 6. It should be remembered in all cases that spot prices may fall below
variable costs or above total costs, due to short-term market imperfections.
The following sections discuss the fixed, variable and total costs of production from
existing capacity and their relationship to the short run industry supply curve.
FIXED COSTS
Fixed costs are, by definition, the costs that are incurred by the owners of existing
plants even if the plant is closed. These costs include basic levels of maintenance and
overhead that are necessary to keep the plant from depreciating more rapidly than it
would if operating. Perhaps more important to methanol plant owners, fixed costs
include recovery of and a return on investment from the sunk capital that was required
to build the plant. Fixed costs are of great concern to owners because these costs
represent the maximum loss that will be sustained in the event that the plant is not
operated at all. If the market prospects offer no hope to owners, the burden of fixed
33
-------
costs will be unacceptable. The only way to stop the on-going loss of fixed costs is to
abandon the plant entirely which has the effect of consolidating the future stream of
fixed-cost losses into a lump-sum loss. Unfortunately for the owners of methanol
plants, the excess supply conditions in the present marketplace dictate that owners are
the only ones concerned with fixed costs. As long as excess capacity is available, the
market price will squeeze existing plants so that, for a given level of supply, the price
will not exceed the variable costs of the lowest variable cost plant in idle condition.
For those operating, the returns to fixed costs are expected to be less than or equal to
the difference between the variable cost of their plant and the lowest variable cost
plant not operating.
While distressing for plant owners, the limited return on fixed costs is representative of
a young industry that has grown in capacity more quickly than demand conditions
warrant. Indeed, if the market for methanol increases dramatically because of
transportation (or other) uses, existing plant owners will shift from minimizing losses to
maximizing profits and may receive economic rent, in addition to a return of variable
and fixed costs. Until then, however, economic theory dictates that the supply curve
(and associated market prices) will be predicated on the variable costs of the individual
producers.
The fixed costs associated with methanol plants are very plant-specific. Fixed costs
depend on the age of the plant, the costs of building the plant, the financing costs
incurred to build the plant, the opportunity cost of the funds used to build the plant, the
location of the plant and so on. Secondary sources do not provide this level of plant-
specific information for most U.S. plants: estimates of fixed costs for foreign plants
would be highly speculative and based on limited anecdotal information. However,
since the fixed costs of existing plants do not affect the short-run industry supply
curve, this lack of data on fixed costs does not hinder the development of the short-run
industry supply curve or estimates of delivered prices. Fixed costs do become very
important, however, when the supply curve moves from the short-run to the long-run.
As explained in Chapter 6, the fixed costs associated with future (long run) capacity
play a very important part in the long-run supply curve for the methanol industry.
VARIABLE COSTS
The variable costs of methanol production were estimated based on available estimates
of methanol production costs. First, variable costs were divided into their major
34
-------
components. For each component, an average unit cost (baseline) was estimated based
on available information for U.S. plants. A 113.5 million gallon per year plant was
selected as the baseline size. The impact of factors such as location, size of plant, type
of feedstock, and production process were each researched and estimated to reflect the
individual production costs of each methanol plant that was identified as a potential
U.S. supplier. The plant-specific costs of production were used to estimate a weighted
average unit cost by country of production.
The cost categories for production estimates are (1) feedstock, (2) maintenance, (3)
catalyst, (4) utility, (5) labor, and (6) other costs. The costs are discussed according to
relative size for most plants, with feedstock and maintenance representing the largest
cost share. Because data were not available to distinguish between fixed and variable
costs within the identified categories, all fixed costs that are incurred during plant
operation, except those related to capital, are included in the estimates. Thus,
estimates include taxes, insurance, and maintenance costs that may actually be fixed
costs in addition to costs that are clearly variable costs, e.g., feedstock costs.
Therefore, the estimates of "variable" costs presented in this report represents an
overstatement (believed to be relatively small) of the actual variable costs (some fixed
costs are included). Moreover, the largest factor of fixed costs, those representing
capital recovery and charges, are excluded from the variable cost estimates. Without
extensive additional research it cannot be determined precisely how much the variable
costs presented in this chapter are overstated due to the inclusion of fixed costs. The
overstatement is, however, believed to be small and not have a significant impact on
estimates of production cost.
Feedstock Costs
A major problem in estimating production prices for methanol is the identification of
the cost of natural gas for individual plants. In the U.S., natural gas prices for broad
categories of users are available from published sources. However, in many developing
countries natural gas prices are difficult to estimate. These countries often build
methanol plants because they have little or no alternate uses for the natural gas. In
countries where natural gas is transacted, there are often no data available on selling
prices. Furthermore, gas supplies are frequently co-products or by-products with crude
oil production. In some countries the gas is vented, flared, or fed back into the ground
for repressuring indicating little or no opportunity cost. In addition, feedstock costs are
35
-------
highly site specific depending on transportation distance and difficulty as well as the
available collection infrastructure. The difficulty associated with valuing natural gas
was reflected in Alcohol Week in an article that discussed the cost of methanol
production from the Trinidad plant. One source contacted by Alcohol Week stated that
natural gas costs were $0.50 per million Btu. A second source estimated natural gas
costs for this plant to be more like $1.00 per million Btu.
Natural gas feedstock costs in cents per gallon for countries assumed to be potential
U.S. suppliers are presented in Exhibit 4-1. These costs are based on natural gas values
2
developed by DeWitt <5c Company, a major methanol marketing advisor and consultant.
These estimates reflect the value of the gas and costs for collecting and transporting
the gas to the methanol plant. Where estimates for specific countries were not
available they were estimated based on countries with similar locations, gas resources,
3
and production and consumption profiles. For the most part, with the exception of the
U.S. and Canada, the natural gas value is assumed to be zero. Obviously, more research
on the individual natural gas market is required to develop site-specific input cost that
will reflect current opportunities as well as the changes in the market that will occur as
transportation use of methanol increases world-wide.
Feedstocks other than natural gas are also used in the production of methanol.
However, for the countries assumed to be potential U.S. suppliers there are only two
plants that use alternative feedstocks. Both of these plants are located in the U.S. One
of these plants is the Eastman Chemical Co. plant in Kingsport, Tennessee. This plant
uses a coal feedstock and a Lurgi low pressure process. The capacity of the plant is
approximately 60 million gallons per year. Feedstock costs for this plant were based on
cost data for a Lurgi low pressure coal-to-methanol plant indicating total coal costs of
$107.5 million for a 242 million gallon per year plant or 44.42 cents per gallon.
The second plant is the Du Pont plant in Deer Park, Texas. This plant uses a heavy
liquids feedstock and a Lurgi low pressure process. Plant capacity is approximately 200
to 250 million gallons per year. Feedstock costs for this plant were based on
illustrative economic comparisons of methanol production from various raw materials in
the form of an index of feedstock and fuel energy requirements. The index for a gas-
based methanol plant is 100 while the index for a residual oil-based methanol plant is
120 and upwards. The minimum factor of 120 percent was applied to the adjusted
natural gas cost of 22.24 cents per gallon to arrive at a feedstock cost for this plant of
26.69 cents per gallon.
36
-------
EXHIBIT 4-1:
FEEDSTOCK COSTS PER GALLON
FOR POTENTIAL U.S. SUPPLIERS. BY COUNTRY
($, 1985)
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
Arab Emirates
Burma
China
India
Malaysia
Taiwan
Dollars Pet
Million Btu
2.50
1.50
0.50
0.25
0.50 2
0.50 2
0.50
0.50 3
0.50 3
0.50
0.50 3
1.00 4
1.00 4
1.00 4
1.00
1.00 4
Cents5
Per Gallon
23.50
13.34
4.45
2.22
4.45
4.45
4.45
4.45
4.45
4.45
4.45
8.90
8.90
8.90
8.90
8.90
Data from R.G. Dodge, "Competitive Methanol Production Economics," presented
to the 1985 World Methanol Conference, Amsterdam, The Netherlands, December
9-11, 1985.
2
Price for Brazil and Chile are imputed based on price for Trinidad.
o
Price for Algeria, Bahrain, and the United Arab Emirates are imputed based on
price for Saudi Arabia.
4
Price for Burma, China, India, and Taiwan are imputed based on price for Malaysia.
Gas use was converted from dollars per million Btu to cents per gallon using a
factor of 0.1124 million Btu per gallon. This factor was derived based on an
estimate of gas use of 13,500 Btu per pound of methanol (World Bank, Emerging
Energy and Chemical Applications of Methanol; Opportunities for Developi
Countries, April 1982, p.42) and 6.59 pounds of methanol per gallon (Arthur
Brownstein, U.S. Petrochemicals, The Petroleum Publishing Company, Tulsa,
Oklahoma, 1972, p.81.). For a comparable factor of 0.1139 million Btu per gallon
in the U.S. for 1982 see The Outlook for Natural Gas Use in Methanol and Ammonia
Production in the U.S., prepared for the American Gas Association by Chem
Systems Inc., March 1983, p.28.
37
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Maintenance Costs
Methanol plants require periodic shutdowns for maintenance as well as unscheduled
shutdowns for mechanical or catalyst problems. The costs associated with maintenance
are developed separately from manufacturing labor costs because this periodic
maintenance is generally performed by independent contractors, especially in areas
where chemical plants and refineries are concentrated. This is because plant "turn-
arounds" by maintenance contractors have many advantages, including lower year-round
g
staff costs for the plant operator.
1
Maintenance costs are generally given in the literature as a percent of fixed capital.
Therefore, it is assumed that these costs, in total, will increase with the plant size, but
will drop on a per unit (output) basis. As a result of this approach, maintenance costs
are assumed to be higher in developing countries where capital costs are generally
higher.
Maintenance costs may also vary depending on capacity utilization of the plant.
However, it is uncertain as to the extent or direction of this change. For example, if
the plant is running at low utilization or on a campaign basis there may be different
maintenance requirements. In addition, there is evidence that catalysts wear down if
not used periodically. This may cause per unit costs for the maintenance associated
with catalyst replacement to rise as capacity utilization falls. Since data on the
maintenance costs for idle plants (a fixed cost) or less than fully-operating plants are
not available, it is assumed per unit maintenance costs do not vary with capacity
utilization.
Two sources were used to estimate the cost of maintenance for the baseline plant, a
113.5 million gallon U.S. natural gas plant. The World Bank report indicates that
maintenance will cost 2.5 percent of fixed capital for a plant in a developed site in an
g
industrialized country. Fixed capital for this plant is estimated as $98.5 million (for a
113.5 million gallon per year plant). Maintenance is therefore $2.46 million per year or
2.17 cents per gallon. The Chem Systems report estimates that maintenance, material
and labor will cost 5.0 percent of capital costs inside battery limits, estimated at $70.2
million for a 113.5 million gallon per year plant.9 Maintenance is therefore $3.51
million per year or approximately 3.09 cents per gallon according to this source.
Although this category includes labor it appears to refer only to the labor associated
with maintenance because normal operating labor costs are given separately. The
38
-------
average of the two available baseline maintenance cost estimates is 2.63 cents.
Because these sources report data for the 1980-1983 time period the estimate 3.0 cents
per gallon (1986 $) was used for the baseline.
For the two U.S. plants that use alternative feedstocks, costs can be expected to differ.
The Jet Propulsion Laboratory report estimates maintenance costs of $26.3 million for
242 million gallons per year of methanol production from a dry bottom Lurgi coal-to-
methanol plant, or 10.9 cents per gallon. This estimate was used for the Eastman
Chemical Plant. No data were available to estimate the maintenance cost for the
heavy oil (Deer Park) U.S. plant. Thus, maintenance costs (per unit) for this plant were
assumed to equal a natural gas plant (3.0 cents per gallon).
To estimate the effect of location (developed versus undeveloped country), World Bank
estimates of the influence of location based on a fixed percentage of capital costs were
utilized. The World Bank estimates that capital costs in developing countries can be 30
percent, 60 percent or 100 percent above the industrialized country reference case,
depending on a number of factors including available infrastructure, site development,
remoteness and the need for expatriate project management.
The assumption used for this study is that industrialized countries pay the baseline
estimated cost for maintenance. For extremely undeveloped countries, a 60 percent
markup (over baseline) was assumed. For developing countries or countries that have a
substantial oil industry a 30 percent markup (over baseline) was used.
Maintenance costs will also vary by size of plant. To estimate the effect of capacity on
maintenance costs data from two sources were used. For plants over 80 million gallons
per year, estimates from the World Bank were used. The World Bank reports
maintenance costs for 1000 tons per day and 2000 tons per day plants. These costs are
based on 2.5 percent of fixed capital or $2.46 million and $4.0 million. Assuming a
linear relationship, this results in a change of $36 in maintenance costs per million
gallon change in capacity. For plants under 80 million gallons per year, estimates were
taken from U.S. Petrochemicals. This source shows the total of maintenance and
labor costs of 0.89 cents per gallon for a 80 million gallon per year plant and 2.50 cents
per gallon for a 15.0 million gallon plant. Again, assuming a linear relationship, this
results in a change of $248 per million gallon change in capacity. (For this study it was
assumed that the mix of labor and maintenance is constant for plants smaller than 80
million gallons.)
39
-------
Exhibit 4-2 provides estimates of maintenance costs for each country assumed to be a
potential supplier to the U.S. utilizing the baseline estimate of 3.0 cents per gallon and
adjusting feedstock, location, and capacity factors as discussed above.
Catalyst Costs
Methanol is produced by bringing a synthesis gas, composed of carbon monoxide and
hydrogen, into contact with a catalyst in the presence of heat and pressure. The two
leading methanol processes, the ICI and the Lurgi processes, have many similarities, but
use different proprietary catalysts and have somewhat different configurations
12
regarding the way the synthesis gas is fed over the catalyst. One efficient methanol
converter design is a vessel containing copper-based catalyst-filled tubes surrounded by
13
boiler feed water.
In a well-operated methanol plant both the reforming and synthesis catalysts will
usually last from four to five years before their activity falls below acceptable
levels. In methanol plants
of any loss in effectiveness.
levels. In methanol plants catalyst activity must be carefully monitored to keep track
There are three sources that provide separate estimates of the cost for catalysts in a
natural gas-to-methanol plant. The World Bank estimates that "Catalysts and Supplies'1
will cost 1.5 cents per gallon. The Chem Systems report estimates that "Catalysts &
Chemicals" will cost $750,000 on an annual basis for a 113.5 million gallon per year or
16
0.66 cents per gallon. The Dodge paper estimates that "Catalysts and Chemicals"
17
cost approximately 0.88 cents per gallon. Moreover, estimates show little (JPL -
Texaco Coal Gasification) or no (World Bank and Dodge) variation across plant sizes or
location. Catalyst costs are therefore estimates to be 1.0 cents per gallon. No
variation in these costs across loaction or plant size is assumed.
For alternate stocks a JPL estimate of 1.16 cents per gallon, based on a 242 million
gallon/year dry bottom Lurgi, was used for the coal-to-methanol plant. Lacking a
better estimate, the catalyst cost for the "heavy liquids" plant was estimated to be the
same as for a natural gas based plant.
Utility Costs
Utility costs by country are shown in Exhibit 4-3, and were developed from the Dodge
18
paper presented at the 1985 World Methanol Conference. Utility costs include
40
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EXHIBIT 4-2;
MAINTENANCE COSTS PER GALLON
FOR POTENTIAL U.S. SUPPLIERS, BY COUNTRY
($, 1985)
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
Arab Emirates
Burma
China
India
Malaysia
Taiwan
Source: JFA estimates.
Note: Value shown in
Country
Status and
Maintenance Markup
Developed (1.0)
Developed (1.0)
Developing/Refining (1.3)
Developing (1.6)
Developing (1.6)
Developing (1.6)
Developing (1.6)
Developing/Refining (1.3)
Developing/Refining (1.3)
Developing/Refining (1.3)
Developing/Refining (1.3)
Developing (1.6)
Developing (1.6)
Developing (1.6)
Developing (1.6)
Semi-Developed (1.3)
parenthesis indicate the marki
Cents
Per Gallon
3.04
2.62
4.80
4.80
6.38
4.01
4.78
5.48
3.92
3.45
3.18
6.18
5.06
7.14
4.82
4.57
ip applied (U.S. costs = 1.0
to the estimated operating costs for similar plants located in the U.S.
41
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EXHIBIT 4-3;
UTILITY COSTS PER GALLON
FOR POTENTIAL U.S. SUPPLIERS. BY COUNTRY
($, 1985)
Dollars Per Metric Ton
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
Arab Emirates
Burma
China
India
Malaysia
Taiwan
Cooling
Power Water
0.3 4.4
0.2 2.8
0.1 1.4
0.1 1.6
0.1 2.7
1.6 2.2
Makeup
Water Total
0.2 4.9
0.1 3.1
0.1 1.6
0.1 1.8
0.1 2.9
0.1 3.9
Cents
Per Gallon
1.46
0.93
1.463
0.48
0.484
0.484
0.54
0.875
0.875
0.87
0.875
1.176
1.176
1.176
1.17
1.176
2
Data from R.G. Dodge, "Competitive Methanol Production Economics," presented to
the 1985 World Methanol Conference, Amsterdam, The Netherlands, December 9-11,
1985.
Data are converted from metric tons to gallons using a factor of 334.5 gallons per
metric ton. This is based on 2204.6 pounds per metric ton and 6.59 pounds per gallon.
The factor of 6.59 pounds per gallon is from Arthur M. Brownstein, U.S.
Petrochemicals, The Petroleum Publishing Company, Tulsa, Oklahoma, 1972.
Costs for Mexico are imputed based on costs for the U.S.
Costs for Brazil and Chile are imputed based on costs for Argentina.
'Costs for Algeria, Bahrain, and the United Arab Emirates are imputed based on costs
for Saudi Arabia.
6
Costs for Burma, China, India, and Taiwan are imputed based on costs for Malaysia.
42
-------
charges for power, cooling water, and makeup water. Where estimates for specific
countries were not available, they were imputed based on countries with similar
locations and/or similar economic characteristics.
Labor Costs
A modern methanol plant is a highly instrumented and automated facility. Labor costs
are generally low, as the typical plant will employ a small number of workers to
monitor technical apparatus and perform other duties on a daily basis. Methanol plants
also require labor during periodic shutdowns for maintenance, as well as unscheduled
shutdowns where unexpected mechanical or catalyst problems have developed. Labor
dedicated to maintenance activity is estimated separately as part of maintenance costs.
Full-time labor associated with a methanol plant operation has been categorized by the
19
Chem Systems report to include supervisors, foremen, and laborers. The Chem
Systems report provides estimates of the number of employees and applicable salary for
each position. Data are provided for a 113.5 million gallon plant in 1980. Included is
one supervisory position at $32,700 per year, 5 foremen at $27,100 per year, and 23
laborers at $23,900 per year for a total of $719,000 (.63 cents per gallon). Estimates
for the plant labor are based on one foreman and five laborers per shift. Several other
sources provide labor cost data either on a per unit basis or as a percent of capital
(2,4,6). Comparisons are difficult because somewhat different definitions are used in
each source. In general, labor costs as estimated in the various available sources in
various year dollars and under a variety of assumptions in the range of 0.63 to 1.5 cents
per gallon. For the purpose of this study we have made the conservative assumption
that labor costs are 1.5 cents per gallon in 1985 dollars for a 113.5 million gallon per
year plant located in the U.S. The small differences in other published labor cost
estimates will have little impact on the total production costs.
In many production processes capacity utilization would have a large impact on labor
costs per unit of output. However, methanol manufacturers are generally unwilling to
run plants below full capacity, and when forced to do so, will operate the unit on short
bursts. Furthermore, since the labor pool is small, it is relatively easy to lay off or
furlough workers during slack operating periods. Therefore, labor costs per unit of
output do not vary considerably with capacity utilization and thus, no adjustment was
made for capacity utilization.
43
-------
The production process used may also alter labor requirements for methanol production,
however, as most plants currently utilize one of the two low pressure processes (ICI and
Lurgi) the production process is not particularly important. A comparison of labor costs
20
for coal versus natural gas are provided by SRI International. Estimates of labor
required for a bituminus coal plant labor costs are 3.8 cents per gallon. This estimate
was used for the one identified coal-based methanol plant.
Perhaps the most important factor affecting labor costs is location. The World Bank
21
has estimated labor costs for various site and country locations. For a developed or
developing site in a developing country labor costs are estimated to be about 50 percent
less than the labor costs in an industrialized country. For a remote or undeveloped
location in a developing country, labor costs are estimated to be 75 percent of the labor
costs in the industrialized country case. Labor costs are assumed to be higher in the
remote site/developing country than the developed site/developing country due to the
possible need for expatriate assistance. The Bureau of Labor Statistics (BLS) collects
22
data on hourly costs for production workers for various industries and countries.
These data demonstrate a much larger labor differential than those calculated by the
World Bank, and indicate that the 50 percent factor applied to developing countries by
the World Bank would be more applicable to developed countries other than the U.S. A
factor of approximately 25 percent seems appropriate for developing countries. It
should be noted that the BLS data are for production workers only. The Chem Systems
report indicates that approximately 75 percent of labor costs are for production
23
workers. Thus, labor cost differentials for this analysis were calculated based on the
BLS index for 75 percent of costs (i.e., that attributable to laborers), while the
remaining 25 percent of costs (i.e., that attributable to foremen and supervisory labor)
were assumed to be at U.S. costs. Countries for which data from BLS were not
available were estimated based on nearby countries or countries with similar GDP per
capita. The resulting labor cost indexes are shown in Exhibit 4-4.
The final factor effecting labor cost is the size of the plant or plant capacity. To
estimate the effect of capacity on labor costs data from two sources was used. For
plants over 80 million gallons per year estimates from the World Bank were used. The
World Bank reports labor costs for 1000 tons per day (113.5 million gallons per year) and
24
2000 tons per day (277 million gallons per year) plants. Assuming a linear
relationship, these estimates indicate a change of $47 per million gallons of additional
capacity. For smaller plants, the rate of change was estimated from U.S.
Petrochemicals. This source shows the total of labor and maintenance costs increasing
44
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LABOR COST DIFFERENTIAL INDEXES
VI
North America
South America
Africa
Asia
Europe
Australia and Oceana
Source: JFA estimates.
United States
Canada
Mexico
Argentina (Brazil)
Brazil
Chile (Brazil)
Trinidad (Singapore)
Algeria (Portugal)
Libya (Israel)
Bahrain (Isreal)
Bangladesh (India)
Burma (India)
China (India)
India
Indonesia (Korea, India)
Japan
Korea
Malaysia (India)
Saudi Arabia (Isreal)
Taiwan
United Arab Emirates (Isreal)
Austria
East Germany (W. Germany)
France
Italy
Netherlands
Spain
Sweden
United Kingdom
USSR (Port)
West Germany
Yugosolovia (Port)
Austrailia
New Zealand
i
Labor Cost Index
100
82
14
10
10
10
19
12
37
37
4
4
4
4
8
51
11
4
37
13
37
51
74
59
59
68
37
74
46
12
74
12
74
33
Labor Cost Index -
Adjusted for Supervisory
100
87
36
33
33
33
39
34
53
53
28
28
28
28
31
63
33
28
53
35
53
63
81
69
69
76
53
81
60
34
81
34
81
50
BLS
BLS and World Bank using Jack Faucett Associate's methodology.
-------
the rate of $25 per million gallons in capacity for plants smaller than 80 million gallons
per year. For this study it was assumed that the mix of labor and maintenance is
constant for plants smaller than 80 million gallons.
Exhibit 4-5 provides estimates of labor cost for each country assumed to be a potential
U.S. supplier based on the estimate of 1.5 cents per gallon for a 1000 ton (113.5 million
gallon) U.S. plant and the production process, feedstock, location, and plant size factor
adjustments developed above.
Other Costs
Other costs include insurance, general and administrative, selling costs and overhead
costs. While available estimates do not distinguish between fixed and variable costs,
fixed costs are assumed to be small. Tenneco estimates "selling & administrative" cost
to be 3.0 cents per gallon for plants in the U.S. Gulf and Western Europe, and 4.2 cents
25
per gallon in remote areas. Hie Chem Systems report provides separate estimates
for direct overhead ($323 thousand), general plant overhead ($2748 thousand), and
insurance and property taxes ($1,420 thousand), for a total of $4491 thousand. These
figures are for a 113.5 million gallon plant and convert to 4.0 cents per gallon. The
World Bank also provides separate estimates for several categories of "other" costs.
These include $1.4 million for overhead, $1.1 million (3% of sales) for general,
administrative and marketing, and $1.0 million (1% of fixed capital) for insurance and
other for a total of $3.5 million. These estimates are also for a 113.5 million gallon
plant and convert to 3.1 cents per gallon. In all cases, the estimates do not change by
plant size.
A baseline estimate of 3.4 cents per gallon for these costs was based on the average of
the estimates from Tenneco (3.0 cents per gallon), Chem Systems (4.0 cents per gallon),
and World Bank (3.1 cents per gallon). For developing countries the Simmons (Tenneco)
estimate of 4.2 cents per gallon was used.
The Sum of Variable Costs
The variable production costs of each country identified as a potential supplier to the
U.S. are shown in Exhibit 4-6. The delivered U.S. cost is based on the average variable
46
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LABOR
FOR POTENTIAL
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
Arab Emirates
Burma
China
India
Malaysia
Taiwan
EXHIBIT 4-5:
COSTS PER GALLON
U.S. SUPPLIERS, BY COUNTRY
($, 1985)
Cents
Per Gallon
1.30
0.88
0.80
0.47
0.83
0.28
0.58
0.93
0.80
0.56
0.42
0.67
0.46
0.84
0.42
0.72
Source: JFA estimates.
47
-------
EXHIBIT 4-6
00
SUMMARY OF AVERAGE VARIABLE COSTS OF METHANOL PRODUCTION, BY COUNTRY
(Cents Per Gallon, 1986 $)
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
Arab Emirates
Burma
China
India
Malaysia
Taiwan
Feedstock
23.50
13.34
4.45
2.22
4.45
4.45
4.45
4.45
4.45
4.45
4.45
8.90
8.90
8.90
8.90
8.90
Catalyst
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
Labor
1.30
0.88
0.80
0.47
0.83
0.28
0.58
0.93
0.80
0.56
0.42
0.67
0.46
0.84
0.42
0.72
Maintenance
3.04
2.62
4.80
4.80
6.38
4.01
4.78
5.48
3.92
3.45
3.18
6.18
5.06
7.14
4.82
4.57
Utility
1.46
0.93
1.46
0.48
0.48
0.48
0.54
0.87
0.87
0.87
0.87
1.17
1.17
1.17
1.17
1.17
Other
3.37
3.37
3.37
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
TOTAL
33.67
22.14
15.88
13.17
17.34
14.42
15.55
16.93
15.24
14.53
14.12
22.12
20.79
23.25
20.51
20.56
Source: JFA estimates.
-------
production costs plus transportation costs as discussed in Chapter 5. Moreover, the
variable production costs are based on the weighted average production costs by
country and thus implicitly assumes that a country will supply methanol based on the
weighted average production costs of plants within the country.
Again, the reader is reminded that the costs shown in Exhibit 4-6 are presented as
variable costs but do include a small amount of fixed costs, e.g., undistinguished fixed
overhead, insurance, and maintenance costs. The total of these fixed costs that are
included in the variable costs, however, are not believed to exceed the margin of error
on these estimates and thus do not significantly distort the findings.
TOTAL COSTS
In economic terms, the total cost of production is the sum of the fixed and variable
costs with fixed cost defined to include an economic return on the investment. As
discussed previously, in the current methanol market variable costs are most important
because with the excess supply (capacity) conditions, producers make decisions based on
variable costs. Thus, to predict short-run supply, variable costs must be estimated.
The secondary sources available to estimate production costs limit the procedure.
Fixed costs are not available per se, though some fixed costs are included in available
estimates of production costs. The data inadequacies thus prevent accurate estimates
of total costs and limit the accuracy of the estimates presented for variable costs.
Basically, the variable cost estimates presented in the previous section include some
fixed costs, but these costs (particularly on a per-gallon basis) are small.
This research effort did not include the additional research that would be required to
quantify fixed costs. Moreover, the cost of capital and profit for existing plants that
are the primary components of fixed cost were not estimated. The estimation of these
elements would require detailed and plant-specific information that is not generally
available. However, the absence of estimates of fixed costs of existing capacity is not
considered limiting because (1) in the short-run, prices will be established based on
variable costs (due to conditions of excess capacity) and (2) in the long-run, prices will
be influenced by the total costs of additional (future) capacity, rather than the total
costs of existing capacity. Thus, while estimates of total costs of existing capacity
49
-------
would be informative, their primary value is limited to identifying the producer surplus
that may be earned by plant owners as the market place shifts from the short-run
(excess capacity conditions) to the long-run where the cost of future additional capacity
will dictate the prices paid to methanol producers.
50
-------
CHAPTER 4 FOOTNOTES
1. Alcohol Week, issue date, p.4.
2. R.G. Dodge, "Competitive Methanol Production Economics," presented to the
1985 World Methanol Conference, Amsterdam, The Netherlands, December 9-11,
1985.
3. Data used for this purpose include the Energy Information Administration's
International Energy Annual, 1984, DOE/EIA-0219(84), pp. 63-70, 80, and World
Bank, Emerging Energy and Chemical Applications of Methanol; Opportunities
tpng Energy and Chemical App
ung Countries. April 1982, p.60.
for Developing Countries. April 1982
4. Jet Propulsion Laboratory, California Methanol Assessment, Volume II:
Technical Report, pp. 4-9, 4-10.
5. World Bank, Emerging Energy and Chemical Applications of Methanol!
Opportunities foTDeveloping Countries, April 1982, p.39.
6. U.S. Department of Commerce, A Competitive Assessment of the U.S. Methanol
Industry," May 1985, p.6.
7. World Bank, p.42, and Chem Systems, Inc., The Outlook for Natural Gas Use in
Methanol and Ammonia Production in the U.S., Prepared for the American Gas
Association, Mary 1983, p.26.
8. World Bank, p.42.
9. Chem Systems, Inc., p.26.
10. Jet Propulsion Laboratory, pp. 4-9, 4-10.
11. Arthur M. Brownstein, U.S. Petrochemicals, The Petroleum Publishing Co.,
Tulsa, Oklahoma, 1972, p.U?I
12. U.S. Department of Commerce, p.3.
13 World Bank, p. 36.
14. For example, in the ICI process conversion of carbon oxides per pass is normally
40 to 60 percent. Loss of effectiveness is shown in reductions in conversions per
pass.
15. World Bank, p.42
16. Chem Systems, Inc., p.26
17. R. G. Dodge.
18. R. G. Dodge.
19. Chem Systems, Inc., p.26.
20. SRI International, Chemical Economics Handbook, October 1983.
51
-------
CHAPTER 4 FOOTNOTES (continued)
21. World Bank, p.42.
22. U.S. Department of Labor, Bureau of Labor Statistics, unpublished computer
printouts.
23. Chem Systems, p.26.
24. World Bank, p.42. Note: tons per day are converted to gallons per year based on
334.5 gallons per metric ton and 330 days of expected operation.
25. Tenneco, "Methanol, World Supply/Demand Outlook," a paper presented by R. E.
Simmons at the 1985 National Conference on Alcohol Fuels, p.18.
52
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CHAPTER 5;
THE COST OF DELIVERY
The production costs of foreign producers, as estimated in Chapter 4, range from 12 to
30.3 cents per gallon compared to a U.S. cost estimate of 33.4 cents per gallon.
However, the cost of shipping the product from these countries to the U.S. is high and
can run as much as 18 cents per gallon. Hie per gallon cost of production from existing
plants is shown along with delivered prices in Exhibit 5-1. For some foreign producers,
the added transportation costs to U.S. markets more than double the plant gate product
cost. For this reason, it is important to understand the currently available transpor-
tation options as well as future alternatives that may reduce the cost of delivery to the
U.S.
High transportation costs are a major concern to policy makers. Since there are
already a number of potential suppliers for a U.S. methanol-for-transportation market
that produce at quite low cost, the primary avenue for reducing delivered U.S. prices is
by reducing transportation costs. However, transportation economies of scale that
would permit lower transportation costs (and thus lower the delivered U.S. price) are
only achievable in higher demand scenario than currently exists.
The estimates shown in Exhibit 5-1 represent the total cost of delivering product from
the country identified to the U.S. location by traditional means in quantities up to about
one billion gallons of U.S. demand for methanol. Because shipping costs are priced
based on total costs from origin to destination, separate estimates of ocean transport,
overland haulage, inland waterway costs or loading charges are not included. The costs
shown represent rough estimates based on available literature and opinions of shipping
experts. Actual rates paid will depend on a variety of factors, including volume
shipped, loading/unloading requirements, availability of vessels, types of long-term
agreements and so on.
Economies of scale associated with large volumes such as those that are achieved by
crude oil shipments would considerably lower the transportation costs presented in
Exhibit 5.1. However, these scale economies require the use of the largest vessels
53
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EXHIBIT 5-lt
DELIVERED COST OP METHANOL AT LOW LEVELS OP DEM AND1 PROM CURRENT PRODUCERS TO U.S. DESTINATIONS. BY COUNTRY
(Cents per gallon, 1986 $)
TRANSPORTATION CHARGES
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
Arab Emirates
Burma
China
India
Malaysia
Taiwan
Average
Variable
Cost
33.67
22.14
15.88
13.17
17.34
14.42
15.55
16.93
15.24
14.53
14.12
22.12
20.79
23.25
20.51
20.56
California
2.0
2.0
3.0
13.0
11.0
12.0
10.0
18.0
18.0
18.0
18.0
10.0
10.0
11.0
10.0
10.0
Source: JPA estimates based on information
shippers and freight forwarders.
Gulf of
Mexico
4.0
2.0
11.0
9.0
10.0
8.0
16.0
16.0
16.0
16.0
12.0
12.0
13.0
12.0
12.0
contained
Northeast
2.0
4.0
3.0
11.0
9.0
11.0
8.0
16.0
16.0
16.0
16.0
13.0
13.0
14.0
13.0
13.0
in Competitive
Greak Lakes
3.0
2.0
5.0
13.0
11.0
13.0
10.0
18.0
18.0
18.0
18.0
15.0
15.0
16.0
15.0
15.0
Methanol Production
TOTAL DELIVERED U.S. PRICE
California
35.67
24.14
18.88
26.17
28.34
26.42
25.55
34.93
33.24
32.53
32.12
32.12
30.79
34.25
30.51
30.56
Economics, R.G.
Gulf of
Mexico
33.67
26.14
17.88
24.17
26.34
24.42
23.55
32.93
31.24
30.53
30.12
34.12
32.79
36.25
32.51
32.56
Dodge, Dewitt
Northeast
35.67
26.14
18.88
24.17
26.34
25.42
23.55
32.93
31.24
30.53
30.12
35.12
33.79
37.25
33.51
33.56
& Co., and
Great Lake*
36.67
24.14
20.88
26.17
28.34
27.32
25.55
34.93
33.24
32.53
32.12
37.12
35.79
39.25
35.51
35.56
discussions wit
U.S. demand of up to one billion gallons per year.
-------
currently moving crude oil: 200,000-300,000 plus dead weight ton (dwt) vessels. A
2
200,000 dwt tanker holds about 68 million gallons of methanol. Since, in the California
high demand scenario, only 252.3 million gallons of methanol per year would be
required, use of a 200,000 dwt tanker would imply less than four shipments per year.
Because demand in California would utilize at least two terminals, the large carriers
could only be used if the two terminals received a total of four shipments per year,
combined. This is untenable. Moreover, the estimates of distribution system
3
requirements developed by EEA include storage requirements of only 500,000 barrels
or 21 million gallons (8.3 percent of annual demand) for methanol in a demand scenario
of 250 million gallons per year.
A 21 million gallons per year storage capacity would allow receipt from no larger than a
50,000 dwt tanker that would deliver 15 times per year. Thus, at the highest point of
consumption in the California scenario, it might be feasible to have a relatively small
(50,000 dwt) tanker "dedicated" to methanol movement. Whether even this level of
economy could be achieved depends on a number of variables, including:
The availability and cost of 50,000 dwt vessels;
the ability to economically schedule a single vessel for routes that could
include producers geographically distant; and
the availability of backhaul shipments to reduce the cost of the otherwise
empty movements from California to methanol producers or added
shipments of other types to fully utilize the tanker.
Given the constraints that would be encountered in economically utilizing a 50,000 dwt
tanker (that was very cost-effective in the ISSO's but now does not compare to the
economies of scale achieved by the large 200,000 to 300,000 dwt plus carriers), few if
any economies of scale in transportation can be expected in the California scenario (the
highest level of demand in the California scenarios is 250 million gallons per year).
The national scenario offers greater potential for economies of scale in transportation,
especially in the high demand case. For example, in the year 2000 at the low demand
estimate of 4,252 million gallons per year, the U.S. (as a whole) could accept about 42
55
-------
deliveries from a 300,000 dwt carrier or 63 deliveries from a 200,000 dwt carrier. The
limited number of deliveries from a 300,000 dwt carrier would not be feasible given
geographically dispersed U.S. destinations, but the 200,000 dwt could perhaps be
utilized. Assuming about 8 percent of annual consumption available for storage as
indicated in the EEA report, total U.S. storage would equal 340 million gallons and
delivery size for 200,000 dwt tanker would be about 68 million gallons. Average time
between deliveries under this scenario would be about eight days. It should be noted,
however, that consumption probably needs to equal about 4,000 million gallons per year
(with 320 million gallons of available storage capacity) before the delivery system could
even begin to utilize the size of vessels that yield the significant economies of scale
available in crude oil shipments. Moreover, since the transport of crude oil by the
200,000 dwt plus tankers is usually from a single origin to a single destination, the costs
of transporting methanol from several plants to various U.S. destinations are not likely
to be as low as petroleum even in the highest demand of the national scenarios.
Additionally, higher transportation costs for methanol that result from higher capital
costs for stainless steel and/or specially lined tanks as well as generally higher handling
costs for the product methanol when compared to crude (a raw material) will result in
higher shipping costs for methanol, even in high demand scenarios.
In summary, crude is currently delivered to the U.S. from foreign destinations at a cost
of 1.5 to 6 cents per gallon compared with 10 to 18 cents per gallon for methanol
transport, excluding transport from Canada and Mexico. Because there are a number of
additional costs in transporting methanol when compared to crude and there are
economies of scale that will not be available to methanol under the highest of demand
scenarios examined here, the lowest assumed transportation cost per gallon of methanol
(from countries other than Mexico and Canada) is about 5-8 cents per gallon.
Generally, the greater portion of this savings (perhaps two thirds) will only become
possible in the national high U.S. demand scenario (above 4,000 million gallons per
year). The other one-third savings (1.6-3.3 cents per gallon) may potentially be
achieved at levels up to 4,000 million, though the threshold for achieving any savings
(relative to the costs shown in Exhibit 5-1) is estimated to be about 250 million gallons.
Exhibit 5-2 depicts the nature of the relationship between methanol transport cost and
volume shipped. The location of the inflection points for this curve are highly
speculative and will depend on the specific structure of the future methanol market.
56
-------
FREIGHT 12 -
RATE
CENTS/GAL
10 -4
EXHIBIT 5-2;
POTENTIAL ECONOMIES OF SCALE. OCEAN SHIPPING METHANOL;
MIDDLE EAST TO UNITED STATES
CURRENT
METHANOL
FREIGHT
RATE
CURRENT
CRUDE OIL
FREIGHT
RATE
2 34 5
BILLIONS OF GALLONS SHIPPED PER YEAR
30
-4-+
AB
DEMAND IN THE YEAR 2000, BY SCENARIO
A - California Low Demand
B - California High Demand
C - National Low Demand
D - National High Demand
128 Million Gallons
250 Million Gallons
4,252 Million Gallons
27,000 Million Gallons
-------
A final note on methanol transportation costs relates to the accuracy of the estimates
presented above. Hie estimates of the current cost of transportation as well as future
potential economies of scale are rough. Generally, there is not enough methanol
currently transacted in U.S. markets to make price estimates reliable. The estimates
of current transportation cost per gallon of methanol between countries were developed
from information contained in Competitive Methanol Production Economics, R. G.
Dodge, DeWitt & Company, December 1985 and discussions with several shipping firms
and freight forwarders to ensure reasonableness and estimate costs for regions not
previously served. These rates are believed to be reasonable, however, particular
requirements such as volume per year, loading and unloading requirements, long-term
agreements, and movement of other products for the same shipper can all affect the
actual contract rate. Data available on the current transportation rates for methanol
are constrained to limited shipments of methanol moving in the chemical trades.
Growing transportation requirements for methanol will lead to changes in the rates as
larger shipments and more regular delivery patterns give methanol buyers more
leverage with carriers. The rates listed in Exhibit 5-1 are representative of near-term
methanol movements and are based on current chemical trade activities. These rates
may vary by as much as thirty percent as a result of changing economic conditions in
the tanker shipping industry. The rates shown are for a reasonably stable market.
Delivering methanol to a Great Lakes destination such as Chicago will add about 2
cents per gallon over East Coast delivery rates as a result of the transloading cost from
ocean to lake tankers. Delivery of methanol to many midwest locations may be less
expensive if the product is shipped to New Orleans instead of Chicago and delivered by
barge along the inland waterway system. Differences in rates between U.S. East Coast,
Gulf and California delivery points are a function of cargo origin, distance and the
existence of regular chemical trades along each origin and destination. These factors
will become less important as the methanol trade expands.
Generally, the widely accepted series for crude oil transport documented in Plattte
Handbook and Lloyd^s Shipping Economist do provide a good measure of the price of
crude transport. It is certainly true that the cost of methanol transport will be higher
than the price of crude transport through all scenarios, since in the highest range
methanol represents less than 20 percent of the crude now transported (for all uses).
Moreover, higher methanol handling costs related to tank requirements and product
characteristics will also keep the price of methanol transport higher. Nonetheless, the
58
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actual delivery volumes required to improve the economies of scale for U.S. delivery of
methanol are rather speculative. The demand for methanol must not only increase but
remain firm, long-term agreements must be reached between producers and terminals,
and U.S. terminals from different geographical locations will have to work together
closely to improve the bargaining position for U.S. deliveries. The estimates are not
nearly as sensitive to whether the shipments originate from Trinidad or Saudi Arabia for
delivery to Chicago or Los Angeles as they are sensitive to total market demand and
unified buying strategies. Moreover, the estimates given here are rough indicators of
future costs and current prices of shipments. The only historical data available are for
the prices charged for crude oil shipments and the actual prices charged for shipments
will depend on many different factors. Extensive primary research, well beyond the
limits of this study, would be required to improve the accuracy of these estimates.
Special Handling Requirements
Methanol is currently transported throughout the world as part of the chemical tanker
trade. Shipment can be both liner (scheduled) and tramp (charter) and cover a broad
range of volumes from 1 to 6 million gallons. In order to efficiently utilize even the
smallest tanks on typical chemical tankers volumes of 3-6 million gallons per shipment
are desired. As volumes increase, larger tanks can be utilized and discounts are
generally provided. These vessels regularly handle cargo with corrosive, explosive and
hazardous characteristics. Special international standards for tank cleaning, product
handling, last load carried, and other issues are generally incorporated in contracts.
One of the two largest chemical tanker operators in the world, a Norwegian firm called
Odfjell Westfol-Larsen Tankers currently transports over 300 million gallons of
methanol per year. Their tankers are constructed with epoxy-lined tanks, zinc silicate-
lined tanks, and stainless steel tanks. Methanol is carried in either zinc-silicate lined or
stainless steel tanks. Stainless steel tankage is the most desirable for methanol,
however, the smooth silicate coating associated with zinc linings offer generally
acceptable tanks for methanol according to this firm. Stainless steel tanks are
considerably more expensive than the coated soft steel tanks. Newly constructed
chemical tankers generally have a mix of tank types. Odfjell Westfol-Larsen's tankage
is 45 percent stainless, 35 percent zinc-silicate and 20 percent epoxy. The large oil
tankers currently utilize soft steel tanks. According to industry specialists, a large
59
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dedicated methanol tanker would probably utilize stainless steel tanks which would
increase construction cost by 10-15 percent. A major research effort is underway by
the paint industry to find a methanol acceptable coating that would allow the use of
lower cost soft steel tanks. The paint industry recognizes that such coatings could
offer the industry a substantial market.
In addition to the reactive nature of methanol, toxicity and fire detection also require
special planning and equipment. It is estimated by shippers that fire detection and
suppression systems and special loading/unloading systems would add one to three
percent to the cost of a production tanker.
Capacity Expansion
Methanol use in highway transportation has the potential of placing significant new
requirements on the ocean transportation industry. As methanol has about half the
energy value per barrel of oil, the tanker fleet may have to expand its capacity if oil
imports are replaced with methanol imports. It is also possible that more methanol
supply will come from foreign sources because U.S. producers may not be able to
compete with low-cost producers in gas-rich countries. Currently there is an active
market for used tankers of all sizes. Hie current fleet is well in excess of current
demands with used ships currently selling for as little as $40 per dwt for VLCC/ULCC
and $200 per dwt for smaller vessels. This compares to new vessel cost of $188 per dwt
for VLCC/ULCC and $560 per dwt for smaller vessels. In today's spot and one year
charter markets a new 250,000 dwt oil tanker costing about $50 million can generate
about $18 million in revenues for the carrier per year in the spot market and $12 million
per year on charters. When and if methanol shipments absorb the excess capacity
currently available for tankers , new capital will be required.
Shipyards currently specialize in constructing one or a very few off-the-shelf vessels of
standard design. Shipyard productivity, measured in man-hours per ton of erected steel,
is greatly enhanced as the shipyards eliminate design problems and production bottle-
necks associated with constructing the first of a series of vessels. Construction time
for a large crude carrier was cut by the early 1980^s from two to three years to nine
g
months. The Japanese yards' early entry into building large crude carriers, their
pioneering efforts in advancing shipbuilding techniques, their access to low-cost steel
60
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produced by efficient mills and to a low-cost, highly dependable and industrious work
force, their encouragement by government agencies, and the availability of government
shipyard credit facilities to prospective owners has helped Japanese shipyards capture
half of the world order book for new vessel construction (newbuildings).
The following sections provide a general description of the aspects and considerations
involved in ocean transport. These descriptions are provided so as to give the reader a
general understanding of the way shipments are negotiated.
Contract Structure
In the current methanol trade the product is carried by specialty tankers. These ships
are generally much smaller (20-40,000 deadweight-tons) than crude oil tankers and
usually contain 6-20 separate tanks of varying sizes. Many different products are
carried on a single voyage and separate products may have unique origins and
destinations. During the initial stages of a growing methanol market the product would
be carried by these vessels. As of January 1, 1986 there were almost a thousand
chemical tankers in the world fleet offering almost twelve million dead-weight tons of
n
cargo space. This fleet is more than adequate to service the current chemical trades
and initial methanol transportation requirements. In latter stages of methanol growth,
it will become economic for shippers to charter whole vessels as is now the common
practice in the oil transport market.
Captive tanker fleets are currently chartered to oil companies for most or all of their
useful lives on a cost-of-service basis. Under cost-of-service contracts, owners bear
little or no financing or operating risks. These risks are borne by the oil companies.
Owners with these contracts sell their ability to manage and operate vessels. Through
these arrangements, the shipper has access to the ship management talents of
competent ship operators for a relatively modest fee. The actual percentage of owned
and controlled fleets to total tanker needs varies considerably among the major oil
companies, depending on their experience with ownership, their relationship with
independent tanker owners and shipping companies, the business philosophy of the
chartering managers, their perception of future tanker needs, and the availability of
corporate funds for acquiring tankers.
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When there is no excess tonnage available to satisfy an incremental demand for tanker
capacity, shippers must select other means to satisfy their need. They may order
tankers for their own account, enter into a life-of-asset transportation agreements with
a captive fleet owner, or arrange a charter (contract) with an independent tanker owner
or tanker-owning shipping company on a long-, medium-, or short-term basis. Charter
parties (written contracts) are concluded after considering the owner's past per-
formance and reputation as a ship operator and his proposed rates and terms. A charter
is fixed if the rates and terms are satisfactory to both the charterer and the owner;
that is, when the business objectives of both parties are satisfied. They are negotiated
in an extremely competitive environment with numerous owners attempting to garner
contracts from a few major charterers.
Economy of Scale of Large Tankers
In the late 1940s and early 1950s, there was a plentiful supply of war-built tankers of
about 16,000 dwt. These later became known as handles for their versatility in serving
every oil terminal in the world. By the mid-1950s, world economic activity had
absorbed all the excess war-built tonnage. In response to a growing demand for tanker
capacity, certain shipyard managers, oil company chartering managers, and owners
developed, ordered, and built larger-sized tankers of 20,000, 25,000, 30,000, and 35,000
dwt. In the late 1950s, the 50,000-dwt supertanker made its debut. The combination of
lower operating costs and capital servicing charges to transport a ton of crude oil in
these vessels provided economies of scale that led to lower shipping costs.
In 1966 and 1967, the first tankers of over 200,000 dwt, Very Large Crude Carriers
(VLCCs), were delivered and within a few years there were Ultra Large Crude Carriers
(ULCC) of greater than 300,000 dwt. By 1970, the world VLCC/ULCC fleet numbered
130 vessels. Exxon, Texaco, and Shell owned about a third; Greek and Hong Kong
shipping firms were added to the roster of owners, who collectively owned another third
of the fleet. The remaining third was owned by a Japanese Line and the British shipping
company, Peninsular and Orient Steam Navigation (P & O). Even in the 1986 U.S. oil
market with significantly reduced imports, about six oil tankers made U.S. deliveries
per week with one being a VLCC/ULCC vessel. Thirty VLCC/ULCC's leave the Arabian
Gulf each month.
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If methanol demand grows to be a substantial portion of the U.S. and world trans-
portation energy use, vessels of the VLCC/ULCC class would supply the shipping at
rates similar to current crude oil rates, plus additional handling and capital costs.
Pricing
Historically, 90-95 percent of the transportation needs of the major crude shippers are
filled by ownership, control of captive fleets, and an assortment of long-, medium-, and
short-term chartered-in tonnage. The remainder is satisfied by open market chartering
of tanker capacity on a single-voyage basis called the spot market. If the chartering
manager of an oil company must transport crude oil between two ports on a specified
loading date and there are no suitably sized tankers in the company^ owned, controlled,
or chartered-in fleet which can meet the date, the chartering manager will attempt to
charter-in a vessel from the spot market. Usually he contacts brokers who, for a
commission, seek out tanker owners of uncommitted, suitably sized, advantageously
positioned tonnage. The search extends not just to owners but also to other oil
companies. The practice of oil companies chartering out owned or chartered-in tonnage
to competitors is called reletting.
A tanker on the spot market is under charter only for the duration of the loaded leg of a
single voyage, which may last from a few days to a month. Once the cargo is
discharged, the vessel is free to compete for another cargo wherever it happens to
originate to wherever the destination, as long as the vessel is suitably sized for the
intended cargo, is physically sized to come alongside the loading and discharging berths
and to pass through intervening canals and restricted waterways, and can meet the
desired loading date. The spot market is an extremely sensitive indicator of the
marginal demand and supply of tanker capacity, a key signal to oil companies and
owners on whether or not to expand the world stock of tanker capacity, and a means to
allocate the worldwide fleet of tankers among the many crude oil trade routes.
Rate of freight in the spot or single-voyage market are expressed in Worldscale or
Worldscale Points to facilitate the decision-making process for fixing tankers. World-
scale equates the daily revenue-earning rate of a tanker independent of any specified
trade route. For example, if an owner has a tanker in the Persian Gulf and receives two
offers one to transport a cargo of crude from the Persian Gulf to Europe via the
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Cape of Good Hope and the other to Japan both at Worldscale 100 (W100) in theory,
he would be indifferent because both offers would generate the same daily revenue.
From a practical viewpoint, he is not indifferent. He may select the Persian Gulf to
Japan (PG/Japan) to have his vessel in the Far East to take advantage of a low-cost
repair yard for planned maintenance. Or he may select the longer-distance PG/Europe
voyage because he feels spot market rates may be falling and wants to maintain the
current daily earning rate longer. If he thinks rates are going up, he may select the
PG/Japan voyage because its shorter duration would increase the vessel's earnings in a
rising spot market more than selecting the longer PG/Europe voyage.
For example, assume that the Worldscale 100 rate per dwt of cargo on the PG/Europe
voyage was $10 and $5.70 on the PG/Japan voyage. The round-trip time at a speed of
15 knots to complete the PG/Europe via the Cape of Good Hope voyage is about 64
days, 40 days for the PG/Japan voyage. If an owner fixes his vessel at W100 on either
voyage, the gross receipts of tons of cargo carried multiplied by the W100 rates less
bunker (fuel) costs, port charges, and canal tolls divided by the roundtrip voyage time
would yield essentially the same daily earnings rate for both voyages. Out of the daily
earnings rate, the owner must pay all operating costs (crew, maintenance, insurance,
and stores) and any financing charges. The underlying basis for computing Worldscale
rates by the International Tanker Nominal Freight Scale Association for over 50,000
voyages is the preservation of the earning power of a standard tanker at the base rate
of W100 regardless of the voyage. Worldscale 100 rates were adjusted annually to
compensate for changes in port and canal charges and bunker costs.
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CHAPTER 5 FOOTNOTES
1. According to Lloyd's Shipping Economist, monthly, and Plan's Oil Price
Handbook, the (comparable) cost of ocean transport of crude oil ranges from 1.5
to 6 cents per gallon in the current shipping market.
2. Based on 334.5 gallons of methanol per metric ton times 1.016 metric tons per
dwt (long tons) =339.9 gallons per dwt.
3. Energy and Environmental Analysis' report "Distribution of Methanol for Motor
Vehicle Use in the California South Coast Basin, p.6-4.
4. See for example, Transportation Benefits of the Proposed Wabash Waterway,
Jack Faucett Associates, December 1986.
5. According to the Lloyd's Shipping Economist, only 17 percent of tankers of
150,000 dwt plus were actively shipping in summer of 1986.
6. The world record is 2 weeks between keel laying and launching for the much
smaller WWII Liberty vessels built in U.S. yards.
7. Tankers in the World Fleet, U.S. Department of Transportation, Maritime
Administration, January 1, 1986.
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CHAPTER 6;
PRODUCTION FROM ADDITIONAL CAPACITY
This chapter presents estimates of the cost of methanol supplied to the United States
by potential new methanol plants. Significant expansion of methanol capacity will not
occur until the market for methanol increases to the point that current (excess)
capacity approaches full utilization. Because additional capacity will not be built
unless the product can be sold at fully costed (fixed plus variable) prices, an estimate of
capital costs is a key element in determining the cost of methanol from additional
capacity. The location of future (hypothetical) plants was selected based on the
availability of surplus natural gas (currently vented, flared or reinjected) in those
countries that now produce or are preparing to produce methanol.
This chapter is divided into four sections. The first discusses the conceptual
importance of total cost pricing as the current excess capacity conditions abate. As
methanol fuel demand causes total methanol demand to exceed methanol supply from
existing or soon to be constructed production facilities, the cost of production from new
capacity will become important. Later sections present estimates of fixed and variable
costs of methanol production from new plants. Finally, the last section provides a
summary of fixed, variable and total costs per unit of output for additional capacity.
TOTAL COST PRICING
Chapter 4 explained the procedures used to estimate methanol prices during a period of
excess supply. This chapter examines the costs that will be associated with new capital
as demand grows and excess capacity diminishes. The resulting estimates are used to
develop the long-run methanol supply curve.
It is a general assumption of this report that methanol is sold in a competitive market.
In a competitive market it is expected that, in the long run, price will be determined by
demand and the long run average total cost of producers. If price exceeds industry
average total cost, economic profits are earned by existing plant owners and new firms
will be attracted to the industry. The new supply will drive the price down to long run
66
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average cost. For the delivery of methanol to U.S. markets, individual producers will
still have different production and delivery costs due to local prices for inputs and
transportation costs.
After estimating the long-run supply curve (based on average total costs for new
plants), it is also possible to calculate the "gap" in prices between the lowest cost plant
on the long-run curve and the highest cost plant on the short run supply curve (based on
average variable cost for existing plants). However, the potential jump in market
prices may be larger or smaller than this "gap" because of the leadtime required to
bring new capacity on line (larger) or the tendency of entrepreneurs to anticipate
methanol demand and thereby increase capacity before demand is increased (smaller).
In general, the leadtime required to bring new methanol capacity on line has been
increasing in recent years and it now takes about three years to construct new plants.
However, the actual point in the transition wherein individual countries and/or
entrepreneurs will make decisions to add capacity is uncertain. Because the methanol
industry has, to date, anticipated market conditions, decisions to add new capacity may
be made well before supply and demand come into balance. This has in the past, and
may in the future, be based more on the potential for economic exploitation of
otherwise underutilized gas reserves in underdeveloped countries than actual market
conditions. Anticipatory decisions to build new plants will smooth the price adjustment
between the short- and long-run production scenarios.
However, if the decision to build new capacity does not match the growth in demand,
prices may rise above the average total cost for new plants allowing existing plants to
earn excess profits (higher than the difference between the existing plants' total costs
and the total cost of new plants) until new capacity comes on line. In this situation
existing plants will capture a higher economic rent and the associated jump in methanol
prices will be larger than the "gap" between the lowest average total cost new plant and
the highest average variable cost existing plant. The economic rent earned by existing
plants will then decrease to the difference between total costs of the existing plants
and new plants as the new plants come into production.
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POTENTIAL LOCATIONS FOR NEW PLANTS
Methanol plants could be constructed in almost any country that has associated gas, gas
which is flared or reinjected, or large gas resources. Exhibit 6-1 provides estimates of
natural gas reserves and production, as well as quantities of natural gas that are vented,
flared or used in repressuring for selected countries. Countries that currently produce
methanol are identified.
For this analysis it is assumed that only those countries that have already been
identified as U.S. suppliers and have sufficient quantities of low-cost (vented, flared,
reinjected) natural gas will be likely locations for new plants. This assumption is not
limiting because these sources are capable of supplying more than enough methanol to
meet the levels of demand specified in the scenarios of interest, as shown in Exhibit
6-2. Furthermore, it is reasonable to assume that countries which have shown a current
interest in methanol production have done so because of the relative cost at which they
could supply methanol. While other countries could produce methanol, their lack of
interest in this market provides an indication that (1) better alternatives exist for
utilization of their natural gas supply and/or (2) higher production or capital costs
prevent cost-effective production. This could change as market prices for methanol
increase and demand becomes more secure. Moreover, countries with high levels of low
cost natural gas that do not appear on Exhibit 6-2 and do decide to produce methanol
will probably do so within the range of fixed costs discussed below. The vented, flared
and reinjected gas represented by countries that already supply the U.S. is enough gas
to fuel the production of almost 53 billion gallons of methanol per year, or the
equivalent production of 258-227.5 million gallons per year plants operating at 90
percent capacity. It should be noted that the vented and flared and reinjected natural
gas shown for the U.S. is located primarily in Alaska.
FIXED COSTS
In order to estimate the fixed cost of methanol production from potential new plants a
number of assumptions are required. These include: 1) the size of new methanol plants,
2) the capital cost for new plants, 3) the appropriate rate of return on investment, 4)
the assumed number of years over which plants should be depreciated, and 5) the
countries that will potentially build new plants. Each of these assumptions is discussed
below. The sum of all fixed costs divided by output over the life of the plant generates
the estimate of average fixed cost (stated as cents per gallon of output).
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EXHIBIT -!»
o>
(O
WORLD NATURAL GAS PRODUCTION, 1983 AND RESERVES AS OF JANUARY 1985
Region
Country
NORTH AMERICA
Canada
Mexico
United States
TOTAL
CENTRAL AND SOUTH AMERICA
Argentina
Bolivia
Chile
Colombia
Trinidad and Tobago
Venezuela
Other
TOTAL
WESTERN EUROPE
France
Germany, West
Italy
Netherlands
Norway
United Kingdom
Other
TOTAL
EASTERN EUROPE AND U.S.S.R
Germany, East
Hungary
Poland
Romania
U.S.S.R
Other
TOTAL
Methanol
Capability
In Place
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Gross
Production
(Bcf)3
3,441
1,480
18,597
23,518
570
178
170
183
212
1,122
237
2,672
337
629
462
2,638
1,079
1,774
244
7,162
268
238
193
1,409
19,490
47
21,646
Vented
Flared
(Bcf)3
60
166
95
321
95
7
0
26
86
61
75
350
0
0
0
1
10
134
4
149
0
0
0
5
380
0
385
Reinjected
(Bcf)3
431
NA
1,458
1,889
32
79
117
55
0
454
31
768
0
0
0
0
165
166
15
346
0
0
0
0
NA
0
0
Reserves
(Tcf)3
92.3
77.0
197.5
366.8
24.6
b
b
b
10.6
55.4
17.4
108.0
b
b
b
68.5
89.0
27.8
21.4
206.7
b
b
b
b
1450.0
16.5
1466.5
-------
EXHIBIT 6-1: (continued)
-a
o
WORLD NATURAL
Region
Country
MIDDLE EAST
Bahrain
Iran
Iraq
Kuwait
Qatar
Saudi Arabia
United Arab Emirates
Other
TOTAL
AFRICA
Algeria
Egypt
Libya
Nigeria
Other
TOTAL
FAR EAST AND OCEANIA
Australia
Brunei
China
Indonesia
Malaysia
Pakistan
Other
TOTAL
WORLD TOTAL
GAS PRODUCTION, 1983 AND
Methanol
Capability
In Place
X
X
X
X
X
X
X
X
X
X
Gross
Production
(Bcf)3
186
908
142
192
194
950
548
242
3,360
3,173
143
441
536
205
4,499
462
345
480
1,186
196
347
633
3,649
66,506
RESERVES
Vented
Flared
(Bcf)3
16
454
119
21
3
576
216
56
1,460
154
26
68
442
136
826
39
14
49
151
65
0
35
353
3,845
AS OF JANUARY
Reinjected
(Bcf)3
28
127
0
20
0
46
0
57
278
1,592
0
226
13
29
1,860
0
0
0
256
0
0
11
267
5,407a
1985
Reserves
(Tcf)3
7.3
478.6
28.8
36.6
150.0
127.4
32.0
8.7
869.4
109.0
7.0
21.2
35.6
14.4
187.3
17.9
7.3
30.9
40.0
50.0
15.8
35.2
197.1
3401.8
Sum of reported totals only.
Included in regional other reserves.
NA = Not available.
Note: Sum of components may not equal total due to independent rounding.
Source: Energy Information Administration, International Energy Annual, 1984, DOE/EIA-0219(84).
-------
EXHIBIT 6-2;
POTENTIAL ANNUAL METHANOL SUPPLY, SELECTED COUNTRIES1
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
U.A. Emirates
Burma
China
India
Malaysia
TOTAL
Vented
and
Flared
(Bcf)
95
60
166
95
35
0
86
154
16
576
216
5
49
21
65
1,639
Re injected
(Bcf)
1,458
431
NA
32
25
117
0
1,592
28
46
0
5
0
5
0
3,739
Total
(Bcf)
1,553
491
166
127
60
117
86
1,746
44
622
216
10
49
26
65
5,378
Potential
Methanol
Total Supply
(Billion Btu) (Million Gallons)
3/
1,601,143
490,509
159,858
118,364
61,980
116,883
90,042
1,852,506
46,068
651,234
226,152
10,470
51,303
26,884
67,210
5,570,606
15,206
4,658
1,518
1,124
589
1,110
855
17,593
437
6,185
2,148
99
487
255
638
52,902
SOURCE: Energy Information Administration
NA = Not Available
This exhibit is limited to countries which have indicated current interest in producing
methanol for U.S. supply. Other countries with natural gas may also provide additional
sources in the future. (See Exhibit 6-1)
2
Based on a 1990 forecast of 0.1053 million Btu per gallon methanol average natural gas
consumption. This factor was taken from the Chem Systems report entitled The Outlook for
Natural Gas Use in Methanol and Ammonia Production in the U.S., prepared for the American
Gas Association, March 1983, p.28, table ffl-F-1.
3
Located primarily in Alaska.
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New Plant Size
A basic assumption required to calculate the fixed cost of methanol production from
new plants is the size of the new plants. For this analysis it is assumed that the size of
new plants will be 2000 tons per day or 227.5 million gallons per year. Plants with
capacities of 500 tons per day (tpd) for a single train were considered large in the early
1970*8. Much larger single-train plants of 2,000-2,500 tpd are the current standard,
resulting in reduced costs through economies of scale in production. Although 5,000 tpd
single-train unit designs are reportedly available, no significant economy of scale
advantage is predicted beyond the 1,500-2,000 tpd range.
Capital Costs for New Plants
A second assumption that must be made in order to estimate the fixed costs of new
capacity is the capital cost of new plants. Capital costs, when coupled with
assumptions on depreciation schedules and rates of return, represent a large share of
fixed costs.
Numerous sources provide estimates of the capital cost of new methanol plants.
Tenneco estimates costs to be $200 million for a 600,000 metric ton per year plant
(200.7 million gallons per year) in the U.S. Gulf or Western Europe. Similar size plants
in remote locations could cost $300 million. The World Bank estimates new methanol
plants to cost between $175 and $335 million for a 2,000 tons-per-day plant (227.5
million gallons per year) depending on the level of development of both the site and
country in which the plant is located. Costs of $106.5 to $205 million are estimated for
o
a plant one-half of this size. Chem Systems estimates a plant with a 113.5 million
3
gallon plant built in the U.S. Gulf in 1980 would have cost $101.7 million. Jean M.
Tixhon of the International Finance Corporation, estimated a cost of $300 million for a
2,000 ton-per-day (227.5 million gallons per year) theoretical project. It was noted that
the rather high total cost was related to a remote location that required a power plant,
harbor and housing compound. Dewitt and Company has estimated the base cost of a
world class facility to be $215 million.
While there is a great deal of variance in these estimates, there is general agreement
that a plant of 227.5 million gallons per year would cost from $200 to $300 million per
72
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year depending upon location and available infrastructure. To adjust for differences in
location and infrastructure, representative capital costs were chosen for categories of
countries. The developed countries (U.S. and Canada) have been assigned capital costs
of $200 million. However, it should be noted that much of the available surplus gas in
the U.S. is located in Alaska which would most likely require much higher capital cost.
Countries that are either fairly developed or have a substantial petroleum industry, and
thus have reasonably developed international transportation facilities, have been
assigned capital cost of $250 million. These countries include Mexico, Algeria, Saudi
Arabia, Bahrain, and the United Arab Emirates. The less developed countries
(Argentina, Brazil, Chile, Trinidad, Burma, China, India, and Malaysia) have been
assigned capital cost of $300 million to account for higher infrastructure and general
development costs.
Exhibit 6-3 presents per plant capital costs by country and the resulting costs per gallon
required for the rate of return and payback of the cost of capital discussed below.
Rate of Return on Investment
The rate of return on investment for new methanol plants is assumed to be 20 percent
before taxes. Most of the sources reviewed for this study estimated a rate of return of
15 percent or higher. The World Bank, for example used a required rate of return on
investment (ROD of 20 percent before taxes in estimating the range of production costs
for new gas-based methanol plants. Sources also noted that the return could be higher
with higher than usual debt financing as well as risk levels that can be associated with
location in some countries. The ROI is a function of a number of factors that together
reflect the cost of capital and associated risk based on market conditions and location
factors. Income tax laws, subsidies, and overall stability of government (including
protection of private ownership rights) are relevant. The 20 percent rate used here
could be low (in high risk locations) or high (if governments subsidize plants) but
probably represents a reasonable average of ROJs that will be required for future
plants.
The per-unit cost associated with the required rate of return is calculated by
multiplying the capital cost by the required rate of return (0.20) and dividing by total
annual production of the plant (227.5 million gallons).
73
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EXHIBIT 6-3:
CAPITAL COSTS AND OTHER COMPONENTS OF
FIXED COSTS FOR NEW (227.5 MILLION GALLON) METHANOL PLANTS BY COUNTRY
Country
U.S.4
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
U.A. Emirates
Burma
China
India
Malaysia
Capital Cost
($, Million)
200
200
250
300
300
300
300
250
250
250
250
300
300
300
300
($ 1986)
Return on.
Investment
(^/gallon)
17.58
17.58
21.98
26.37
26.37
26.37
26.37
21.98
21.98
21.98
21.98
26.37
26.37
26.37
26.37
Capital
Charge:
Depreciation
(t/gallon)
5.86
5.86
7.33
8.79
8.79
8.79
8.79
7.33
7.33
7.33
7.33
8.79
8.79
8.79
8.79
Total
Fixed
Costs
Related to
Capital3
23.44
23.44
29.31
35.16
35.16
35.16
35.16
29.31
29.31
29.31
29.31
35.16
35.16
35.16
35.16
Based on a 20 percent ROI, before taxes.
o
Based on a 15 year life.
o
Fixed costs related to maintenance and overhead including taxes, insurance, etc., are
included in estimates of variable costs in Exhibit 6-4.
Reflects location of plants in the mainland U.S., excluding Alaska. While most of the
vented-flared-reinjected gas is in Alaska, adverse conditions including lack of infra-
structure, weather, and government restrictions on development of many regions will
most likely limit production in Alaska, except for local use. Capital costs for Alaska
would be significantly higher should plants be constructed in locations where gas is
currently vented and flared or reinjected. Capital costs for Alaska were not estimated
in this study.
74
-------
Depreciation
The annual capital charge on a per gallon basis is calculated by dividing the total
capital cost by the assumed number of operating years and the yearly production of the
plant. For this analysis it is assumed that the life of a methanol plant will be fifteen
years. This estimate combines actual estimated operating life of the plant (20+ years)
with realistic assumptions about the payback that investors will desire in projects of
this type, perhaps as short as 2 years.
VARIABLE COSTS
The variable costs in new methanol plants are calculated using the same procedures
explained in Chapter 4 for existing plants except that feedstock costs are assumed to be
5 percent lower for new plants due to energy reduction measures that will be
incorporated in plant design. This efficiency change is based on information presented
in the Chem Systems report and by others noting that increases in energy costs in the
last decade are providing economic incentive for energy reduction measures in plant
design. Variable costs by category and country for new methanol plants (227.5 million
gallon per year) are provided in Exhibit 6-4. As discussed in Chapter 4, each category
of costs presented includes fixed and variable cost of the type specified. The total
amount of fixed costs included are small as most of the fixed costs for methanol are
related to capital (see Exhibit 6-3).
TOTAL COSTS
The total costs associated with methanol from additional capacity are shown in
Exhibit 6-5. These costs range from 43.5 to 54.5 cents per gallon in 1986 dollars. The
fixed costs, ranging from 23 to 39 cents per gallon, represent in all cases except the
U.S. more of the total cost than do variable costs (14 to 20 cents), in some cases up the
three times the variable costs. The relative size of fixed costs are important because
these amounts represent the approximate size of the market (plant gate) price increases
that will occur as the market shifts from variable to total cost pricing. These costs are
also very high relative to transportation costs and will clearly affect the delivered
market price of fully costed product more than variable or transportation costs (less
than 18 cents per gallon). The assumptions in these fixed costs are straightforward: a
75
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EXHIBITS-*;
SUMMARY OF AVERAGE VARIABLE COSTS OF METHANOL PRODUCTION FROM NEW PLANTS, BY COUNTRY
o>
Country
U.S.3
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
U.A. Emirates
Burma
China
India
Malaysia
Feedstock
21.12
12.67
4.23
2.11
4.23
4.23
4.23
4.23
4.23
4.23
4.23
8.46
8.46
8.46
8.46
(Cents
Maintenance
2.59
2.59
3.36
4.14
4.14
4.14
4.14
3.36
3.36
3.36
3.36
4.14
4.14
4.14
4.14
Per Gallon, 1986 $)
Catalyst
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
Utility1
1.46
0.93
1.46
0.48
0.48
0.48
0.54
0.87
0.87
0.87
0.87
1.17
1.17
1.17
1.17
Labor
0.97
0.84
0.35
0.32
0.32
0.32
0.38
0.33
0.51
0.51
0.51
0.27
0.27
0.27
0.27
Other2
3.37
3.37
3.37
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
4.20
Total
30.52
21.40
13.77
12.25
14.37
14.37
14.49
13.99
14.17
14.17
14.17
19.24
19.24
19.24
19.24
Note: Each category shown includes all costs, fixed and variable, of the type specified. The total fixed costs included are
small as most of the fixed costs for methanol are related to capital and shown separately in Exhibit 6-3. To the
extent that the costs above differ from those shown in Chapter 4, it is because of the plant size and/or the
increased efficiency estimated for future plants affects the variable indicated.
Includes charges for power, cooling water, and makeup water.
2
Includes charges for insurance, general and administrative, selling, and overhead costs.
j
Reflects location of plants in the mainland U.S., excluding Alaska. While most of the vented, flared, reinjected gas is in
Alaska, adverse conditions including lack of infrastructure, weather, and government restrictions on development of many
regions will most likely limit production of methanol in Alaska, except for local use. In Alaska, feedstock costs would be
lower but all other costs would be higher than indicated. Production costs for Alaska were not estimated in this study.
-------
EXHIBIT 6-5;
TOTAL PRODUCTION (PLANT-GATE) COSTS FOR NEW CAPACITYT BY COUNTRY
(Cents per gallon, 1986 $)
Country
U.S.
Canada
Mexico
Argentina
Brazil
Chile
Trinidad
Algeria
Bahrain
Saudi Arabia
U.A. Emirates
Burma
China
India
Malaysia
Fixed Costs
(Capital)
23.44
23.44
29.31
35.16
35.16
35.16
35.16
29.31
29.31
29.31
29.31
35.16
35.16
35.16
35.16
Variable Costs1
30.52
19.95
13.67
12.25
14.37
14.37
14.49
13.99
14.17
14.17
14.17
19.24
19.24
19.24
18.53
Total Production
Costs
53.96
43.39
42.98
47.41
49.53
49.53
49.65
43.30
43.48
43.48
43.48
54.40
54.40
54.40
53.69
1 Include some fixed costs that could not be separately estimated including labor,
maintenance and other costs.
77
-------
20 percent before tax rate of return and a 15-year depreciation schedule with capital
costs ranging from $200-$300 million, depending on location. While it is clear that the
analysis undertaken herein is influenced tremendously by the capital cost assumptions,
it is equally clear that any reasonable range of these costs will not significantly alter
their overall influence on the total cost of methanol, including transportation, delivered
to U.S. destinations.
78
-------
CHAPTER 6 FOOTNOTES
1. Tenneco, "Methanol, World Supply/Demand Outlook," a paper presented by R. E.
Simmons at the 1985 National Conference on Alcohol Fuels, p. 18.
2. World Bank, Emerging Energy and Chemical Applications of Methanol: Oppor-
tunities for Developing Countries, April 1982, p.42.
3. Chem Systems, Inc., The Outlook for Natural Gas Use in Methanol and Ammonia
Production in the U.S., Prepared for the American Gas Association, Mary 1983,
p.26.
4. Jean M. Tixhon, "Financing Methanol Plants from an Investor's Perspective,"
Presented to the 1985 World Methanol Conference, Amsterdam, The
Netherlands, December 9-11, 1985, p. K-5.
5. R.G. Dodge, "Competitive Methanol Production Economics," presented to the
1985 World Methanol Conference, Amsterdam, The Netherlands, December 9-11,
1985, Appendix.
79
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CHAPTER 7;
THE DELIVERED PRICE OF METHANOL
The preceding chapters have presented the potential world supply of methanol from the
existing capital stock and from future capital stock. For each country with methanol
capacity, estimates of the production cost per unit of output and current transportation
cost to U.S. markets were developed. This chapter combines the estimates of
production costs from current capacity with current transportation costs and also
presents estimates of production plus transportation costs of future capacity that will
be required to supply the demand levels set forth in the scenarios examined.
The price a product sells for in the marketplace is determined by many factors. These
include the cost of producing, delivering and selling the product from various sources
and the willingness of consumers to pay for the product. Some consumers may have a
higher value-in-use for the product than other consumers and are thus willing to
purchase the product at higher prices. When the market price is lower than some
consumer's willingness-to-pay, these consumers receive benefits in the form of lower
product expenditures or what economists refer to as consumer surplus. Likewise, those
producers with low costs relative to the market price will earn profits in addition to
what is required to attract their capital to the market and these producers enjoy a
producer surplus.
Commodity markets, like that for methanol, are characterized by their highly competi-
tive nature, generally uniform average costs across producers and the overall mobility
of capital. Generally, it can be said that potential producers of methanol fall into two
categories, those who have capital in place to produce methanol and those who have no
capital in place but have access to both the funds and the technology needed to produce
methanol. The decisions of these two groups to produce methanol are based on a
different set of requirements. Since the producer with capital in place must view his
capital cost as sunk, he is willing to produce when the price he receives for his product
exceeds his average variable cost. That is, he will produce when he can receive more in
return for his product than the direct costs he must incur to produce. This production
will occur even though he may be unable to cover the fixed costs associated with the
previously built capital. Alternatively, new producers will not invest unless they have
80
-------
reasonable expectations of selling their output at a price that provides full cost
coverage including an expected return on the investment at least equal to their next
best opportunity for investment.
The availability of low cost natural gas and the prospect for large-scale methanol use as
a transportation fuel or as an additive (e.g. MTBE) has led to large-scale capacity
additions to the methanol production industry. Capacity has been added even though
growth in traditional methanol markets is only expected to slightly exceed economic
growth. Large increases in production capacity have been recently completed and
several other projects are under consideration. This extensive production capacity
substantially exceeds the current or forecasted demand for methanol in traditional uses.
Thus this new investment has been drawn by speculative increases in methanol demand
e.g., transportation use, or the belief by new producers that they can undercut the
delivered cost of methanol from existing facilities. Some also suggest that third-world
countries could be providing large subsidies to new methanol plants to extend local
economic development through the use of underutilized natural gas reserves. These
government subsidies could be based on the hope that the market will increase (and
subsidies will be recouped) or simply represent a form of domestic welfare that has the
net effect of lowering the delivered price of methanol to the United States.
These issues need not be resolved for the purpose of this study. Here the interest is in
determining what the market price of methanol will be under a set of alternative use
scenarios for methanol in transportation. These scenarios were predetermined by a set
of assumptions about the use of methanol as an ozone attainment strategy. Two
scenarios concentrate on the South Coast Air Basin in California and another two
assume a much larger market for methanol concentrated in regional markets across the
country. The scenarios are presented in Exhibit 7-1. Of particular interest in the
national scenario is the point that new capacity will be required to meet methanol
demand.
Ultimately the market price for methanol will be determined by the options available to
consumers and the cost of products and delivery. In this study, the intent is to
understand the minimum compensation producers will require to deliver fuel methanol
to various U.S. markets under defined scenarios. Demand is given, and can be assumed
to originate from market forces or government fiat. While the forecasts cannot be
expected to yield precise estimates of market clearing prices, they can help public
81
-------
EXHIBIT 7-1:
Year
1988
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
U.S. METHANOL DEMAND SCENARIOS'
TRANSPORTATION USE ONLY
California
Low Demand
Case
11
11
22
25
28
46
55
71
103
128
(Millions
California
High Demand
Case
7
21
47
59
82
95
108
136
154
180
219
252
of Gallons)
National
Low Demand
Case
__
138
282
421
646
890
1,255
1,670
2,375
3,216
4,252
National
High Demand
Case
150
150
3,300
6,500
9,800
13,000
15,800
18,600
21,400
24,200
27,000
82
-------
policy analysts to understand how the market operates and to estimate the effect of
selected public policies.
Nontransportation demand for methanol is expected to grow at a rate slightly greater
than the growth in Gross Domestic Product (GDP) for developed nations. For the
purpose of this study methanol demand growth in traditional uses is assumed to be 4
percent per year or about one percent higher than historic GDP growth. Since some
demand will be satisfied by producers that will not supply the U.S., total demand was
adjusted downward so that the demand that will compete with the U.S. market could be
identified as shown in Exhibit 7-2.
THE PRICE IN THE CURRENT (SHORT RUN) MARKET
In order to estimate at what price the market will be willing to deliver a specified level
of product, it is necessary to estimate the industry supply curve. The current structure
of the methanol industry is competitive, with some producers enjoying lower cost than
others due to more efficient capital, lower feedstock cost, and government subsidies.
The average cost of production for plants located in countries that have capacity
available for the world as well as the U.S. market is presented in Chapter 4. Based only
on capacity availability, the U.S. plants could supply more of U.S. demand but the cost
data indicate that plants in Central and South America can deliver products to
California for under $.30 per gallon, even with capital recovery and profit included for
these low-cost facilities. Most U.S.-based plants cannot compete with the price offered
by these low cost facilities, because though capital and transportation costs may be
lower, high natural gas prices in the U.S. keep the U.S. producers' costs high.
Exhibit 7-3 presents the short-run supply curve for the current methanol suppliers that
may be expected to provide methanol to the U.S. market. The upper curve represents
the average delivered price, including transportation costs, for each country. The lower
curve presents the associated average variable production costs. It should be noted that
the top curve (delivered prices) establishes the shape of the U.S. supply curve. The
lowest average cost (including transportation) producer is shown on the left with each
step in the function representing the next highest average cost producer, by country.
The length of each step approximates 90 percent of the annual methanol capacity in
that country. In order to determine the minimum acceptable delivered price for
methanol under each scenario, add the scenario demand from Exhibits 7-1 and the
83
-------
EXHIBIT 7-2:
00
WORLDWIDE METHANOL DEMAND SCENARIOS: ALL USES
(Millions of Gallons)
Projected Worldwide
Demand, Excluding
U.S. Transportation Worldwide Noncaptive Demand, Including
Use U.S. Transportation Use
Demand Not
Competing with
Year Total1 U.S.2
1990 5,700 2,500
1995 6,900 3,000
2000 8,400 3,200
Demand Competing California California National National
with U.S. Low Demand High Demand Low Demand High Demand
Demand Case Case Case Case
3,200 3,200 3,220 3,200 3,350
3,900 3,930 4,010 4,890 16,900
4,700 4,830 4,950 8,950 31,700
A four percent growth rate for chemical methanol demand is assumed. This is because the demand for chemical methanol
has been observed to increase with GNP in developed countries.
2
It is assumed that this quantity of demand will be satisfied by countries that do not supply the U.S. As shown in Exhibit 3-3,
there is 3.751 billion gallons of nameplate capacity for non-U.S. suppliers of which 625 million gallons is dedicated for
conversion to gasoline (New Zealand). The remaining 3.1 billion in capacity (and future additions to that capacity) is
assumed to operate at about 80 percent utilization in supplying noncompeting methanol users. Thus, the number in the table
is estimated based on an assessment of available capacity, not actual market demand.
Source: EEA and JFA estimates.
-------
competing demand from Exhibit 7-2, and read the minimum delivered price from the
top supply curve from Exhibit 7-3. Hie estimates used to develop these curves are
presented in Exhibit 7-3.
PRICE IN AN EXPANDING MARKET
Exhibit 7-4 presents the long run supply curves for methanol based on long run average
variable cost in each location, with and without transportation costs. For comparison,
the short run supply curves are superimposed on the left side of the graph. Again, the
lower curve shows production costs only, and the higher curve indicates the average
delivered U.S. prices. The long-run transportation costs are estimated at about one-
half of the transportation costs shown for the short run. This estimate captures most
of the savings that are available for large-scale methanol shipments (see Exhibit 5-2).
The gap between the two curves identifies the price transition between the short and
long run: the actual curve may smooth between these two points if the market responds
to increased demand in an orderly and organized manner. It is incumbent on policy
makers, interested in promoting and planning for methanol as a transportation fuel, to
anticipate the market adjustments that will be required between the short and long run
supply conditions and ease the transition period.
The long run curve is much flater than the short run, reflecting the use of common
technology in plants of equally efficient sizes in all countries. Assumed feedstock cost
and capital requirements account for most of the production cost difference across
countries. In the long run, all producers' costs will converge such that the supply curve
will approximate the industry average cost curve. To the extent that some producers
can maintain certain cost advantages, they will earn economic rents for the remaining
useful life of their resources. In the short run, new capital may find it difficult to
compete with some of the capital in place and already partially depreciated. However,
within approximately the expected useful life of recently built capital most capacity
should approach the same production cost per gallon. It should be noted that delivered
U.S. cost may differ even in the long-run due to country-specific natural gas costs and
transportation costs for delivery to U.S. markets.
SENSITIVITY OF THE ESTIMATES
In order to develop the supply curves presented in Exhibits 7-3 and 7-4, a number of
limiting assumptions were required. If these assumptions are changed, the delivered
85
-------
EXHIBIT 7-3:
SHORT RUN METHRNOL SUPPLY CURVE
90
/s
CD
00
O
30
o
O)
\
CD
£20
Q)
LLJ 10
tr
GL
CRLIFORNIfl DELIVERED COSTS
f 1
,1
RVERRSE VRRlflBLE
Hj PRODUCTION COST
U0 1 Z 3 4 5
CUMULATIVE OUTPUT (NAMEPLATE CAPACITY, BILLION GALLONS/YEAR)
COUNTRY
CUMULATIVE
CAPACITY CAPACITY
(MIL.OAL./YR)
PRODUCTION DELIVERED
COST PRICE
(CENTS/QAL.)
1 MEXICO
2 CANADA
3 TRINIDAD
1 ARGENTINA
5 CHILE
6 BRAZIL
7 MALAYSIA
6 TAIWAN
9 CHINA
10 ARAB EMIRATES
11 BURMA
12 SAUDI ARABIA
13 BAHRAIN
It INDIA
15 ALGERIA
16 U.S.
60
625
230
261
250
*5
220
6ft
256
267
50
416
110
50
36
1.900
60
685
915
1.176
1.126
l.»71
1.691
1.755
2.011
2.278
2.328
2.7ft«
2.85*
2.90ft
2.9»0
ft.8ftO
15-9
22.1
15-6
13.2
1ft. ft
17.3
20.5
20.6
20.8
1ft. 1
22.1
1».5
15.2
23.3
16.9
33.7
18.9
23.7
25.6
26.2
26. ft
28.3
30.5
30.6
30.7
32.1
32.1
32.5
33.2
3».3
3«. 9
35.7
86
-------
EXHIBIT 7-4;
LONG RUN METHRNOL SUPPLY CURVE
CO
o
O)
\
CO
-*J
c
40
30
UJ
CJ
»I
cr
CL
10
CflLlFORNIR DELIVERS) COSTS
-T~V
r
I
TOTflL PRODUCTION COSTS
SHORT RUN SUPPLY CURVE
°0 10
CUMULATIVE OUTPUT
20 30 40 50 60
(NAMEPLATE CAPACITY, BILLION GALLONS/YEAR)
COUNTRY
* CURRENT CAPACITY
1 CANADA
2 MEXICO
3 ALGERIA
5 ARAB EMIRATES
4 BAHRAIN
6 SAUDI ARABIA
7 TRINIDAD
6 ARGENTINA
9 BRAZIL
10 U.S.
11 CHILE
12 CHINA
13 BURMA
14 MALAYSIA
15 INDIA
CUMULATIVE PRODUCTION DELIVERED
CAPACITY CAPACITY COST PRICE
(MIL. QAL./YR) (CENTS/OAL. )
_ _
a. 600
1.500
17,600
2.000
400
6.000
600
1.000
600
15.200
1.000
500
100
600
200
*,8*0
9.**0
10.9*0
28.5*0
30.5*0
30.9*0
36.9*0
37.7*0
38.7*0
39.3*0
5*. 5*0
55.5*0
56.0*0
56.1*0
56.7*0
56.9*0
- -
*3.«
»3.0
*3.3
*3.5
»3.5
*3.5
*9.7
*7.»
»9.5
5*.0
*9.5
5».»
5».»
53.7
5*.»
_ _
**.«
*5.o
52.3
52.5
52.5
52.5
5*. 7
55.0
55-0
55.5
55-5
59.*
59.*
59.*
59-9
87
-------
methanol prices suggested by these supply curves would also change. The key data
development tasks that underlie these prices were the development of variable and
fixed costs of methanol production and the transportation costs incurred by various
producers to deliver methanol to U.S. ports. Other studies have suggested higher U.S.
delivered prices for methanol than the estimates here, in some cases without the
detailed breakdown of the components of the supply curves presented in this study. The
following paragraphs discuss the sensitivity of the methanol prices presented in this
report with respect to each of the major cost components.
The estimates of variable production costs were developed from a series of engineering
estimates of methanol production cost. The components of variable cost, in order of
importance, were feedstock, maintenance, catalyst, utility, labor and a catchall
category of remaining costs labeled as other costs. An increase in the level of any of
these categories would result in an upward shift in the supply curve, requiring higher
market prices to meet specified levels of demand. Manufacturers should continue to
produce only if all variable costs are recovered at market prices.
The most important component of variable cost is the feedstock expense. For the
purpose of this study it was assumed that, except for plants located in the U.S. or
Canada, natural gas used for methanol production had little or no opportunity cost.
That is, if it were not used for methanol production, it probably would not be utilized at
all. The cost for a feedstock with little or no opportunity cost is only the cost of
collecting the gas and delivering it to the plant. These costs ranged from $.25 to $1.00
per million Btu. For methanol production outside the U.S. and Canada, feedstock costs
represent only 30%-40% of total variable costs. For U.S. plants, a market price for
feedstock of $2.50 per million Btu*s was assumed. These costs represent 70% of U.S.
plant total variable costs. The estimates presented in this report would change
significantly if the assumption of little or no opportunity cost for feedstock is modified.
If feedstock costs for all non-U.S./Canada plants were increased by $1.00 per million
Btu*s, the delivered price of methanol for both long- and short-term supply curves would
increase by approximately $.09 per gallon. If the U.S. feedstock price was assumed for
all plants, the required methanol price would increase approximabely $0.13-$0.17 per
gallon. As the demand for natural gas as a feedstock for methanol plants increases, a
myriad of market forces will affect market prices. Competing demands for natural gas
and feedstock substitutes for natural gas will be important. More research is required
to better understand how natural gas prices and/or collection costs might change as
methanol demand grows.
88
-------
The smaller categories of catalyst, utility, and labor cost, collectively account for only
15%-20% of the variable costs. Most documents reviewed showed little variance in
these categories. "Other" costs account for as much as 25% of total cost, but include
several small categories. Again, most sources agree as to the importance of each of
the subcategories. Maintenance costs also account for about 25% of the estimated
cost. Data on these cost are well known from existing facilities, although some remote
sites could require maintenance cost levels higher than estimated here. For example, if
methanol was produced by plants located on the North Slope of Alaska, higher
maintenance costs could result that would increase the level of maintenance assumed in
this study for remote production sites.
Short-run supply is not sensitive to fixed costs, however, some small fixed cost items
are included in some of the variable cost categories. In the analysis it is assumed that
these fixed costs are small and thus do not have a major impact on the short run
methanol prices.
Long-run prices, expected to provide full recovery of capital and a return that reflects
project risk and market opportunities are sensitive to assumptions on the cost of the
plant, the productive life of the plant, and the rate of return. For all plants except
those located in the U.S. and Canada, the assumed return on investment per gallon of
methanol produced is greater than the long-run scenarios' variable costs of production.
Return on investment and depreciation account for 65%-75% of the total methanol
production costs. If the required rate of return is changed by 5 percentage points (up or
down), the change in the per gallon total cost is approximately 7 cents. If the assumed
depreciable life of the plant is increased from 15 to 30 years, the depreciation per
gallon would be reduced by approximately 4 cents. More research is required to further
refine the assumptions related to capital costs, capital recovery and return on
investment. Moreover, technology may be expected to offer cost reductions, especially
in remote locations.
A review of Exhibits 7-3 and 7-4 will highlight the importance of transportation cost in
the delivered price of methanol to the United States. After adjusting for higher capital
and handling costs, the observed transportation cost for crude oil provides a very good
model for the scale economics that may be realized in ocean methanol transportation as
volume grows and the product is moved more efficiently. Technological innovations
related to the safe handling of methanol may allow methanol transportation costs to
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more closely approach crude oil transportation costs. In this study it is assumed that a
small premium over crude oil transport cost will always be required for methanol
transport. If scale economies could be realized at lower volume than has been assumed,
transportation costs could be cut for the evaluated scenarios by a few cents per gallon.
However, multiple locations for production facilities and the need to deliver the
product directly to end use markets (no refinery link as with crude oil) may offset
savings gained from increased volume by limiting the size of the vessels employed.
Much additional research is required before more precise estimates of future methanol
transportation costs can be developed.
In summary, the delivered price of methanol will be determined by a wide range of
market forces that are difficult to predict. Future petroleum and natural gas
availability and prices, and the acceptance by consumers of the technology and the fuel
will have significant influences. The analysis throughout this report was based on an
assumed level of demand, by specified scenarios, and thus does not reflect any price
effects of competing transportation fuels or market barriers that might arise from
consumer preferences. As developed, the prices in this study are subject to change as a
result of new assumptions or better information.
USE OF THE ESTIMATES
The estimates presented in this report are designed to provide a preliminary tool to
policy makers involved in the consideration of methanol as a U.S. transportation fuel.
Though developed with sparse data and limiting assumptions, these estimates offer a
crude approximation of the short and long run methanol supply horizon. They are not
intended to predict, for a given point in time, the market clearing price of methanol
product. To limit this type of application, the estimates were intentionally stated in
1986 dollars. The value of these estimates are to policy makers who must plan now for
the "what if" scenarios that must accompany stable growth and smooth transition to the
use of fuel methanol. With additional research and time, these estimates will be
debated, criticized, and ultimately modified using more accurate production costs and
supply constraints. Suppliers, by adding new capacity and maintaining idle capacity in
the face of a market that does not come close to demanding the potential available
supply, are already positioning themselves for an expanding methanol market.
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It is now time for the demand side to catch up. Planners need to move quickly to
formulate strategies that will begin to capture the short-term benefits offered by
suppliers that are willing to sell at less than fully-costed prices. Hie methanol
marketplace now offers an advantage to planners: a cushion of supply that will ease the
potentially burdensome and costly pressures of a marketplace wherein demand growth
exceeds supply. Moreover, if the demand component can organize and plan an orderly
transition to fuel methanol, the supply side has already demonstrated an eagerness to
keep one step ahead and anticipate future supply requirements. However, if the
demand for methanol fuel fails to move forward in the short run, suppliers will react by
closing the idle plants, withholding funds for additional capital expenditures and
generally will move into other investment areas that offer a more reasonable return and
a more stable environment. Though enterpreneurs will move quickly into a market
where they perceive reasonable demand promise, they will move with equal haste out of
a market wherein the demand promise fails to materialize in the marketplace.
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It is now time for the demand side to catch up. Planners need to move quickly to
formulate strategies that will begin to capture the short-term benefits offered by
suppliers that are willing to sell at less than fully-costed prices. The methanol
marketplace now offers an advantage to planners: a cushion of supply that will ease the
potentially burdensome and costly pressures of a marketplace wherein demand growth
exceeds supply. Moreover, if the demand component can organize and plan an orderly
transition to fuel methanol, the supply side has already demonstrated an eagerness to
keep one step ahead and anticipate future supply requirements. However, if the
demand for methanol fuel fails to move forward in the short run, suppliers will react by
closing the idle plants, withholding funds for additional capital expenditures and
generally will move into other investment areas that offer a more reasonable return and
a more stable environment. Though enterpreneurs will move quickly into a market
where they perceive reasonable demand promise, they will move with equal haste out of
a market wherein the demand promise fails to materialize in the marketplace.
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BIBLIOGRAPHY
Capacity References (designated in left column refers to Exhibit 3-1 footnotes)
(CB 84) "More Hitches in Methanol's Growth Plan", Chemical Business, June 1984.
(CHEV 84) Chevron U.S.A. Inc., The Outlook for Use of Methanol as a Transportation
Fuel, November 1984.
(DOC 85) Department of Commerce, A Competitive Assessment of the U.S.
Methanol Industry, May 1985.
(JPL 83) Jet Propulsion Laboratory, and California Institute of Technology,
California Methanol Assessment, Volune I, and H. JPL Pub. 83-18 (Vol. I,
ID, March 1985.
(SRI 83) Stanford Research Institute International, Chemical Economics Handbook,
October 1983.
(TENN 85) Tenneco, "Methanol, World Supply/Demand Outlook," a paper presented by
R. E. Simmons at the 1985 National Conference on Alcohol Fuels,
Renewable Fuels Association, Washington, D.C., September 1985.
(WMC 85) Jean M. Tixhon, "Financial Methanol Plants from an Investor's
Perspective," presented to the 1985 World Methanol Conference,
Amsterdam, The Netherlands, December 9-11. 1985, p. K-5
(UN 85) United Nations Industrial Development Organization, Current World
Situation in Petrochemicals, UNIDO/PC.126, November 14, 1985, Annex 1
and 2 and a special supplement "Methanol Capacities in Developing
Countries."
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BIBLIOGRAPHY
Other References
Alcohol Week. Information Resources, Inc., Washington, D.C.
"Danforth Methanol Bill Seeks to Spur Flexible Fuel Vehicle Product."
May 27, 1985.
"Congressional Staffer: Methanol from Coal to be Competitive by 2015."
June 10, 1985.
ITC Says 2000 U.S. Ethanol Use Worth $2.4-Billion; Methanol $236-
Million." January 21, 1985.
"ARCO: Oxygenates Could Reach 5% of European Gasoline Use by 1990."
November 19, 1984.
"Du Pont Won't Disclose Corrosion Inhibitor Receipt; Responds to
Comments.*1 December 24, 1984
"Fuel Methanol Use to Grow 45% A Year Through '90." February 14,
1983.
"Transco Peat Methanol Co. Established to Own Part of Creswell
Project." February 7, 1983.
"CEC's Redwood Oil Contract for Methanol Stations Signed." February 7,
1983.
Automotive News, "Incentive Urged For Methanol Cars," December 30, 1985.
Brownstein, Arthur M., ed., U.S. Petrochemicals. Tulsa: TTie Petroleum Publishing Co.,
1972.
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Other References (continued)
Chemical Engineering. McGraw-Hill Inc., New York, N.Y.
"A Big Boost For Gasoline-From-Methanol." April 7, 1980.
"Methanol Supplied: Too Much Or Too Little?" July 14, 1980.
Chemical & Engineering News. American Chemical Society, Washington, D.C.
"First Methanol-to-Gasoline Plant Nears Startup in New Zealand." March
25, 1985.
"EPA May Modify Du Pont Waiver For Methanol Fuel Blends." September
2, 1985.
"Chemical Plant Capacity Use Continues Comeback." May 28, 1984.
"Methanol Touted as Best Fuel For Gasoline." June 11, 1984.
"Large-Volume Fuel Market Still Eludes Methanol." July 16, 1984.
"Global Methanol Overcapacity Will Get Worse." June 20, 1983.
"Synthetic Fuels Program in U.S. Has Faltered, Yielded Little Output."
October 10, 1983.
"Gas Prices to Alter Methanol, Ammonia Uses." April 4, 1983.
Chem Systems, Inc., The Outlook for Natural Gas Use in Methanol and Ammonia
Production in the U.S., Prepared for the American Gas Association, May 1983.
R. G. Dodge, "Competitive Methanol Production Economics," presented to the 1985
World Methanol Conference, Amsterdam, The Netherlands, December 9-11, 1985.
Jack Faucett Associates, The Effects of Gasoline Volitility Control on Selected Aspects
of Ethanol Blending. Prepared for U.S. Environmental Protection Agency, November
1985.
94
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Other References (continued)
Jack Faucett Associates, Employment Associated With a Domestic Methanol Fuel
Production Industry. Prepared for U.S. Environmental Protection Agency, August 1984.
Methanol Blends Information Center, Methanol Blends Use Throughout the World.
February 1985.
No author, Near-Term and Mid-Term Methanol Markets; A Private-Sector
Development Strategy. Prepared for a workshop, Methanol as an Automotive Fuel,
Detroit, Michigan, September 1981.
Synfuels Week, (now called Coal and Synfuels Technology). Pasha Publications,
Arlington, Virginia.
"Road to New Methanol Uses Approved." January 21, 1985.
"Mobil Mulls Diesel From Methanol." April 16, 1984.
"Calif. Wants Methanol Overfiring Demo." May 14, 1984
"Economics, Not Regs, Slowing Methanol." November 14, 1983.
U.S. Department of Commerce, A Competitive Assessment of the U.S. Methanol
Industry," May 1985.
U.S. Energy Information Administration^ International Energy Annual, 1984,
DOE/EIA-0219(84).
U.S. General Accounting Office, Removing Barriers To The Market Penetration of
Methanol Fuels. GAO/RCED-84-36, October 1983.
U.S. House of Representatives, Methanol as an Automotive Fuel. U.S. Government
Printing Office, Washington, D.C., February 1984.
U.S. House of Representatives, Committee on Energy and Commerce, Methanol as
Transportation Fuel. U.S. Government Printing Office, Washington, D.C., 1984.
95
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Other References (continued)
U.S. International Trade Commission, Methyl Alcohol from Canada, June 1979.
U.S. International Trade Commission, Preliminary Report on U.S. Production of
Selected Synthetic Organic Chemicals (Including Synthetic Plastics and Resin Materials)
Preliminary totals, 1984-85. March 1985.
World Bank, Emerging Energy and Chemical Applications of Methanol; Opportunities
for Developing Countries. April 1982.
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BIBLIOGRAPHY
Additional References
Crocco <5c Associates, Member Dewitt Consulting Groups conversations and selected
newsletter review.
Conversations with shippers, to validate rates paid for methanol shipment.
Conversations wth staff of EPA, DOE and California Energy Commissions on methanol
planning, strategies, capacities and policies.
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APPENDIX A;
THE INTERRELATIONSHIPS OF
CRUDE OIL. PETROLEUM, NATURAL GAS AND METHANOL
RELATIONSHIP BETWEEN CRUDE OIL AND NATURAL GAS PRICES
Recent studies of the decline of crude oil prices and the effect on natural gas prices
indicate that for each 1 percent decrease in crude oil prices, there may be as much as a
0.7 percent decrease in natural gas prices on average through 1990. After 1990, if
crude oil prices remain low, there may be upward pressure on natural gas prices due to
the decreased exploratory drilling associated with low prices and decreased additions to
reserves, but they will likely remain lower than they would have been in the absence of
the reduced oil prices.
American Gas Association Forecasts
The most detailed analysis of oil and natural gas prices is that produced by the
American Gas Association using its Total Energy Resource Analysis (TERA) model.
TERA is a system of supply, price, and demand models for gas, coal, oil, and other
energy sources, that produces annual energy forecasts by region, through the year 2000.
In a recent TERA-based study (April 19, 1986), AGA analyzed the effects of sustained
lower oil prices on U.S. natural gas prices. Two scenarios, one with crude oil at
$20/barrel and one at $15/barrel, were compared to the AGA-TERA Base Case oil price
of $25 per barrel. In the analysis, prices for the portion of natural gas that is market
responsive (70 percent) were assumed to decline at the same rate as crude oil,
maintaining a level of 50 percent of the price of crude oil on a Btu basis. (The 50
percent level was selected after an examination of 1985 spot and contract prices that
showed, on a Btu basis, natural gas varying between 42 and 53 percent of the price of
crude. Subsequent model runs that showed consistency in supply and demand at this
level supported this selection). The results of the simulation are listed below.
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U.S. Average Field Acquisition Cost of Natural Gas
(Constant 1985 $/MCF)
Base Case:
Year $25/barrel $20/barrel $15/barrel
1985 2.58 2.58 2.58
1986 2.14 1.88 1.59
1987 1.90 1.66 1.37
1988 1.91 1.68 1.38
1989 1.93 1.69 1.39
1990 1.94 1.69 1.39
The results show that by 1990, a 20 percent decrease in the price of crude oil (from $25
to $20/barrel), will be associated with a 13 percent decrease in the field acquisition
cost of natural gas, for a cross-elasticity of 0.64. The price responsiveness of natural
gas appears to be even higher in the case of crude oil at $15/barrel, where the 40
percent decrease in the price of crude oil (from $25 to $15/barrel) leads to a 28 percent
decrease in the price of natural gas, for a cross-elasticity of 0.71. AGA assumes that
because natural gas is a regulated industry, all of these price decreases will be passed
on to consumers.
At the retail level the cross-elasticity is somewhat reduced. This is because, while the
savings in dollar terms are at least as great for retail prices as for field acquisition
costs, in percentage terms they are smaller, since other costs (e.g., transportation and
storage) will not be effected by lower oil prices. The results show that by 1990, a 20
percent decrease in the price of oil (from $25 to $20/barrel) will be associated with a 7
percent decrease in the price of natural gas for industrial users, for a cross-elasticity of
0.35. In the case of oil at $15/barrel, the cross-elasticity is 0.41 as shown in the
following figure:
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U.S. Average Industrial Retail Natural Gas Prices
(Constant 1985 $/MCF)
Base Case:
Year $25/barrel $20/barrel $15/barrel
1986 4.02 3.73 3.44
1987 3.74 3.48 3.16
1988 3.72 3.46 3.13
1989 3.70 3.44 3.09
1990 3.75 3.48 3.13
In the long term, the TERA model analysis indicates potential supply problems if oil
prices remain low. As long as crude prices are low, exploratory drilling is reduced.
Projected reserve additions over the period 1986 and 1990 are 6.2 percent and 17.0
percent less in the $20/barrel and $15/barrel scenarios, respectively, than in the $25
base case, exerting upward pressure on prices in the long-term.
Other Analyses
A 1986 study by the Congressional Budget Office comparing the prices of natural gas
and crude oil found that a 1 percent increase (or decrease) in the price of crude was
associated with, over a 3-year period, a 0.30 percent increase (or decrease) in the price
of natural gas at the retail level. The relationship was calculated using 15 years of
energy price data, adjusted for inflation, and a three year distributed lag model that
projected the price of natural gas as a function of the price of crude and of GNP. The
three-year lag in the CBO assessment differs from the AGA analysis, which assumes
price adjustments for natural gas take place entirely in the same year as the change in
price for crude oil. The CBO analysts are familiar with the AGA work and believe that
its projections that natural gas prices will decline at the same rate as crude oil are
optimistic. However, they also note that their own forecasts are based on a set of
historical data that, due to decontrol and other changes in the natural gas industry, may
not provide a realistic picture of the current relationship between crude oil and natural
gas prices.
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A third study of the relationship between crude oil and natural gas markets was
performed by the U.S. Department of Energy's Information Administration. In the EIA
study, EIA energy models were used to estimate the effects on energy markets and the
U.S. economy of crude oil prices that decline from $27/barrel in 1985 to $13/barrel in
1986, then rise to $17/barrel in 1990 and $20/barrel by 1995 due to large demand
pressures (1985 dollars). The results are compared to an EIA base case prediction in
1985 that showed 1985 and 1990 crude oil prices at $27/barrel and 1995 prices of
$30/barrel. Base case predictions of natural gas prices, at the wellhead, called for
prices of $2.60 (MCF) in 1985, $2.58 in 1990, and $3.93 in 1995. With the reduced oil
prices, natural gas prices would fall to $1.96/MCF in 1990 and rise to $3.50/MCF in
1995 (Table 3). The $0.62 difference in natural gas prices with crude at $27/barrel
versus $17/barrel in 1990 is reduced to $0.43 in 1995 by the reduced supplies of natural
gas associated with low prices for crude.
Natural Gas Wellhead
Crude Oil Prices Prices ($/MCF)
Lower Oil
Year Base Case Case Price Scenario Base Case
1985 $27.00 $27.00 $ 2.60 $ 2.60
1990 $27.00 $17.00 $2.58 $1.96
1995 $30.00 $20.00 $ 3.93 $ 3.50
All three studies point to a decline in natural gas prices to accompany a decline in oil
prices. Estimates of the decline in natural gas prices at the retail level range from 0.30
percent to 0.41 percent for each 1 percent decrease in the price of natural gas through
1990. At the wellhead, the estimates range from 0.65 to 0.71 percent reductions in
natural gas prices for each 1 percent reduction in crude oil prices. Both studies that
consider post-1990 prices expect upward pressure on natural gas prices relative to crude
oil prices after 1990 due to supply considerations. However, prices will likely remain
lower than they would have been without the reduced oil prices.
RELATIONSHIP BETWEEN CRUDE OIL AND METHANOL PRICES
The previous section described the relationships between crude oil prices and natural
gas prices and provided a procedure to adjust gas price expectations based on an
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expected change in crude oil prices. The change in gas prices will, in turn, change the
cost of gas inputs to methanol production if those costs are assumed to include more
than a zero opportunity cost for natural gas. The percentage of cost of methanol
production that is associated with the natural gas production varies with both gas prices
and the prices of all other inputs. In general, gas costs are from five to fifteen percent
of the delivered methanol variable cost. Combining this relationship with the cross-
price elasticity calculated in the previous section, yields the following procedure for
calculating methanol production price (cost) changes as a result of crude oil price
changes. The percent change in methanol prices is equal to .07 times the percent
change in the price of crude oil. This is based on the oil-gas cross-price elasticity of .7
and a ten percent share of delivered methanol cost associated with gas cost. This
relationship is most appropriate for current methanol supply scenarios which are based
on average variable cost pricing. Future prices will be less affected by gas price
changes as gas cost will be a smaller portion of a full cost recovery price.
PETROLEUM PRICES
Crude oil prices are given for four separate scenarios in Exhibit A-l. The DOE scenario
is taken from the 1986 publication National Energy Policy Plan; Projections to 2010
(DOE/PE-0029/3). The data were developed using the WOIL: World Energy Model
supplemented by the analysis and judgement of DOE staff. Data for the three other
forecasts were provided by the CEC. All series have been converted to 1985 dollars
using the implicit price deflater for GNP.
Diesel and gasoline estimates were also provided by DOE staff and are unpublished
revisions to data in The National Energy Policy Plan. Diesel data are based on a linear
relationship between diesel and crude prices. Gasoline data are based on a slightly non-
linear relationship. These relationships were used to determine a diesel or gasoline
value for each given crude value.
The DOE diesel and gasoline estimates were then used to trend 1985 diesel, premium
and unleaded prices for California. The DOE gasoline estimates were used to trend
both premium and unleaded prices. The 1985 California prices were taken from the
CEC Quarterly Oil Report for the first quarter of 1986. These data represent weighted
average wholesale prices before taxes as reported by California refiners on DOE from
EIA-782A. Annual prices are based on a simple unweighted average of monthly prices.
The No. 2 distillate prices was used for diesel prices.
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U.S. Department of Energy
California Low
California Medium
California High
EXHIBIT A-l:
PETROLEUM PRICE SCENARIOS
(Wholesale Price,
$ Per
Barrel
85
90
95
2005
85
90
95
2005
85
90
95
2005
85
90
95
2005
Crude
Oil
28.99
24.54
31.93
50.30
28.99
19.50
21.11
27.02
28.99
26.72
29.19
37.37
28.99
41.14
32.23
42.55
1985 $)
Cents Per Gallon
Diesel
75.3
67.1
80.7
114.7
75.3
57.8
60.8
71.8
75.3
71.2
75.7
90.8
75.3
97.8
83.2
104.4
Unleaded
Regular
86.3
80.5
90.1
119.1
86.3
73.9
75.9
83.7
86.3
83.4
86.5
98.1
86.3
103.9
92.0
106.2
Unleaded
Premium
93.1
86.8
97.2
128.5
93.1
79.8
81.9
90.3
93.1
89.9
93.3
105.8
93.1
112.1
99.3
114.6
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