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

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                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

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                             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
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   0
                   CRLIFQRNIR DELIVERED COSTS
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               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
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£30
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               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

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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

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                                 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.

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                                    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

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                                                              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

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                                                          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

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        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

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                             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

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                            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

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                             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

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                            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

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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

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                    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.

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                                 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

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      •      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.

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                                    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

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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

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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

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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

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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

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                                   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

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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

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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

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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

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                                                       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

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                             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

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                       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.

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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

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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

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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

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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.
                                          61

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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.
                                        62

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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
                                         63

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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.
                                        64

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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.
                                         65

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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.
                                           67

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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).

                                          68

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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

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                                               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).

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                                      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.
                                        71

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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

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                                    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.

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                                 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

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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

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                            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

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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

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                                  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

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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

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                                                          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

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                    EXHIBIT 7-3:
SHORT  RUN  METHRNOL  SUPPLY  CURVE
  90
/—s

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00
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                   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

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                   EXHIBIT 7-4;
LONG  RUN  METHRNOL  SUPPLY  CURVE
CO
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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

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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

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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
                                         89

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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.
                                          90

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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.
                                         91

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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.
                                         91

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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."
                                        92

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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.
                                         93

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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.
                                         96

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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.
                                         97

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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
                                        101

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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
                                       103

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