EPA 460/3-87-05
ASSESSMENT OF IMPACTS
ON THE
REFINING AND NATURAL GAS LIQUIDS
INDUSTRIES OF
SUMMER GASOLINE VAPOR PRESSURE CONTROL
24 August 1987
Prepared for
The U.S. Environmental Protection Agency
Under Subcontract to
Southwest Research Institute
under
Contract 68-03-3353, Work Assignment B3
SWR-8701 Bonnet 6 Mom Management Stienca
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DISCLAIMER
This report was furnished to the U.S. Environmental
Protection Agency by Bonner & Moore Management Science under
subcontract to Southwest Research Institute, 6220 Culebra
Road, San Antonio, Texas, in fulfillment of Work Assignment
B3 of Contract No. 68-03-3353. The contents of this report
are produced herein as received from Bonner & Moore. The
opinions, findings, and conclusions expressed are those of
the authors and not necessarily those of Southwest Research
Institute or the U.S. Environmental Protection Agency.
Mention of company or product names is not to be considered as
an endorsement by the authors, Southwest Research Institute
or the U.S. Environmental Protection Agency.
SWR-8701 Borawr 6 Moore Management Science
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TABLE OF CONTENTS
Paragraph Page
SECTION 1
INTRODUCTION
1.1 STUDY BACKGROUND 1-2
1. 2 ACKNOWLEDGEMENTS 1-2
1. 3 REPORT ORGANIZATION 1-3
SECTION 2
APPROACH AND METHODOLOGY
2.1 GENERAL APPROACH AND METHODOLOGY 2-1
2.1.1 Product Demands 2-5
2.1.2 Crude Availabilities 2-5
2.1.3 Other Raw Mater ials 2-6
2.1.4 Refinery Process Configuration 2-6
2.1.5 Economics 2-7
2.1.6 Product Qualities 2-7
2.1.7 Alcohol Usage 2-9
2. 2 STUDY PARAMETERS AND CASES 2-9
2.2.1 Crude Acquisition Cost 2-9
2.2.2 No-Investment Effects 2-10
2.2.3 Control of Ethanol-Containing
Gasol ine 2-10
2.2.4 Butane Market Price.Effects 2-10
2.2.5 Bunker Sales Volume Effects 2-11
2.2.6 Case Run Summary 2-11
2.3 STUDY LIMITATIONS AND AREAS EXCLUDED 2-13
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TABLE OF CONTENTS (Cont'd)
Paragraph Page
SECTION 3
SUMMARY OF RESULTS
3.1 NATIONAL AND REGIONAL ESTIMATED COSTS 3-1
3.1.1 Refining Costs 3-4
3.1.2 NGL Industry Costs 3-8
3.2 PARAMETER EFFECTS 3-14
3.2*1 Effect of Crude Cost on
RVP-Control Costs 3-14
3.2.2 Effect of Process Investment
Exclus ion 3-16
3.2.3 Effect of Ethanol Blend Control 3-19
3.2.4 Effect of Domestic Butane Price 3-20
3.2.5 Bunker Fuel Sales Volume Effects.... 3-23
3.3 CONCLUSIONS 3-25
SECTION 4
DETAILED RESULTS
4.1 CASES WITH CRUDE AT $22 PER BARREL 4-2
4.2 ALTERNATE CRUDE-COST CASES 4-18
4.3 NO-IN VESTMENT CASES 4-26
4.4 CONTROLLED ETHANOL BLENDING CASES 4-30
4.5 BUTANE PRICE CASES 4-33
4.6 INCREASED BUNKER FUEL SALES CASES 4-36
4.7 VARIABLE-VOLUME GASOLINE ADJUSTMENTS 4-39
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TABLE OF CONTENTS (Cont'd)
Paragraph Page
4.8 NGL SECTOR COST IMPACT 4-41
4.8.1 Butane Markets 4-41
4.8.2 Butane Storage 4-44
4.8.3 Natural Gas Processing Economics.... 4-46
4.8.4 Industry Cost Impact 4-49
REPORT BIBLIOGRAPHY 4-53
LIST OF APPENDICES
A PRODUCT DEMAND FORECASTS A-1
B RAW MATERIAL SUPPLY FORECAST B-l
C PRODUCT SPECIFICATIONS C-l
D ECONOMIC AND FINANCIAL FACTORS D-l
E BASE CONFIGURATION E-l
F- OXYGENATE BLENDING VALUES F-l
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LIST OF ILLUSTRATIONS
Figure Page
2-1 Regions Defined for Modeling Refining
Operations 2-3
3-1 Refining Costs for Control of RVP in
Summer Gasoline 3-5
3-2 Added Cost of Controlled Gasoline
(W/Crude @ $22/BBL) 3-6
3-3 Crude Cost Effect on Refinery Costs
For RVP-Control (Region 3) 3-15
3-4 Crude Cost Effect on Refining Plus NGL
Costs for RVP-Control Region 3) 3-17
3-5 No-Investment Effect on RVP-Control
Refining Costs (Region 3) 3-18
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LIST OF TABLES
Number Page
2-1 REGION DEFINITIONS 2-2
2-2 REGIONAL RVP CONTROL LEVELS 2-8
2-3 CASES STUDIED 2-12
3-1 ESTIMATED COSTS FOR CONTROLLING MAXIMUM
RVP OF SUMMER GASOLINE 3-2
3-2 REDUCTION IN U.S. REFINERY PURCHASES
OF NORMAL BUTANE 3-8
3-3 EFFECTS OF CONTROLLING RVP OF ETHANOL
BLENDS 3-19
3-4 SUMMARY OF BUTANE PRICE EFFECTS 3-22
3-5 SUMMARY OF BUNKER FUEL VOLUME EFFECTS 3-24
4-1 EAST COAST MODEL RESULTS 4-2
4-2 MID-CONTINENT/ROCKIES/NORTHWEST
MODEL RESULTS 4-6
4-3 GULF COAST MODEL RESULTS 4-10
4-4 CALIFORNIA MODEL RESULTS 4-14
4-5 GULF COAST MODEL RESULTS AT $17
PER BARREL 4-18
4-6 GULF COAST MODEL RESULTS AT $27
PER BARREL 4-22
4-7 GULF COAST MODEL RESULTS WITHOUT
INVESTMENT. 4-26
4-8 GULF COAST MODEL RESULTS WITH CONTROLLED
ETHANOL BLENDING 4-30
4-9 GULF COAST MODEL RESULTS AT
VARYING BUTANE PRICES 4-33
4-10 GULF COAST MODEL WITH
INCREASED BUNKER FUEL SALES 4-36
4-11 NET INCOME-LOSS ESTIMATES 4-40
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LIST OF TABLES (Cont'd)
Number Page
4-12 BUTANES REQUIRED AS PETROCHEMICAL
FEEDSTOCKS IN 1990 4-42
4-13 NORMAL-BUTANE UNDERGROUND STORAGE
CAPACITY 4-45
4-14 GAS PROCESSING ECONOMICS 4-47
4-15 NGL SECTOR COSTS 4-51
SVTO-8701 BonnerB vi
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SECTION 1
INTRODUCTION
This report presents the results of a study of the
economic impact, on the U. S. refining and natural gas
liquids industries, of regulations which would reduce the
vapor pressure of summer gasoline. The study was conducted
under subcontract to Southwest Research Institute (SwRI) of
San Antonio, Texas, the prime contractor for a work assign-
ment project commissioned by the U. S. Environmental
Protection Agency.*
This study was inititated as an extension and re-
evaluation of earlier study on the same subject.1t2,3
Decline in crude oil prices during 1986 and several aspects
of the earlier work were noted as having important impacts on
the results of that study. As a consequence, EPA recognized
the need for further study of vapor pressure control.
Furthermore, EPA has changed its concept of vapor pressure
control from one of absolute change (i.e., one, two or three
psi reductions) to one of relative change (i.e., 10, 20 or 30
percent reduct ion).
This latest study expanded the scope of the earlier
study to include refining models representing all parts of
the U.S.**. Use of alcohols in motor gasoline is more
appropriately treated in this study. Interactions among
natural gas liquids supply and refining and petrochemicals
use were modeled in this study rather than being prejudged
and fixed as in the earlier work.
*Work Assignment B-3 of Contract No. 68-03-3353
**The earlier study used models of East Coast, Gulf Coast and
Great Lakes refineries and extrapolated the results from
these regions to cover the whole nation.
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After a review of results from initially-defined
cases, five additional cases were defined and run to extend
the sensitivity analyses embodied in this study. This report
was, therefore, delayed on publication to allow reporting of
this additional work as part of the whole study.
1.1 STUDY BACKGROUND
The language and content of this report assume that
the reader is generally familiar with petroleum refining and
natural gas liquids production and use. The report, there-
fore, makes use of terms and references to processes used in
these industries without definition. On the other hand,
understanding the results does not require intimate knowledge
of refining and natural gas liquids technologies. The study
can be readily understood with only a general knowledge of
the relationship of results to gasoline manufacture, natural
gas liquids utilization and petrochemical operations.
Those readers who would like an overview of petro-
leum refining and vapor pressure control are encouraged to
review the introductory material supplied in the final report
of the earlier study or similar material included in the
recent report of the National Petroleum Council^.
1.2 ACKNOWLEDGEMENTS
During the design and execution of this study, Mr.
Michael Lidgard of EPA, Ann Arbor, and Mr. Norman R. Sefer of
Southwest Research Institute contributed suggestions and sup-
port and produced comments concerning final documentation.
All of these efforts were helpful and are gratefully
acknowledged.
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1.3 REPORT ORGANIZATION
"This report contains four sections and six appen-
dices. Following this introduction, Section 2 discusses the
approach taken and the methodology employed. Section 3 sum-
marizes study results and Section 4 presents detailed results.
Supporting information is presented in Appendices A through
F. Bibliographies are included at the end of the main body
of the report and with each appendix, as appropriate.
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SECTION 2
APPROACH AND METHODOLOGY
An understanding of approach, premises and assump-
tions is important in judging the applicability of results
from any study and in appreciating its inherent strengths and
limitations. This section describes the approach taken by
Bonner & Moore Management Science in estimating the refining
and natural gas liquids (NGL) industry costs associated with
gasoline vapor pressure reduction in the United States.
Descriptions are also provided for the major study premises
and assumpt ions.
2.1 GENERAL APPROACH AND METHODOLOGY
Estimates of the added costs associated with
restricting gasoline vapor pressure were prepared by deter-
mining the increased refining costs in each of four regions
of the U. S. and by bracketing the cost implications of con-
sequent actions within the NGL sector. The four regions
defined for this study are identified in Table 2-1 and mapped
in Fi gure 2-1.
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TABLE 2-1
REGION DEFINITIONS
REGION DESCRIPTION
East Coast, PADD 1
Mid-Continent, Rocky Mountains, Northwest,
PADD 2, PADD 4 and PADD 5 (ex. California)
Gulf Coast, PADD 3
California
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GO
s:
»
i
00
,;-i"t-';''
ro
LO
Figure 2-1. Regions Defined for Modeling Refining Operations
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Mathematical (linear programming) models of the com-
posite refining* capability in these four regions were
constructed using RPMS, a proprietary Bonner & Moore software
and database system. Each regional refining model was
required to meet demand forecasts for 1990 (adjusted for
summer seasonal output variation) using projected crude
supplies for that same future time. Gasoline production was
modeled to recognize three grades: an unleaded premium, an
unleaded regular and a leaded regular** with a maximum TEL
content of 0.1 gram per gallon. Each model was run with
gasoline vapor pressure set to correspond to current limits
and, subsequently, at three levels of reduction from current
limitations. Differences in total refining costs, as deter-
mined from these runs, provided the desired refining cost
estimates for each region modeled.
Results from analyses of these regions were combined
to provide a national estimate. Probable cost implications
of NGL sector actions were added to provide estimates of the
combined refining and NGL costs.
* Olefins production from steam cracking was also repre-
sented in these models since NGL uses and other
feedstocks for olefin production represent close connec-
tions with refining and natural gas processing.
** The probable elimination of leaded gasoline sales and
substitution of a middle-octane unleaded grade is covered
since the clear octane of leaded gasoline is approxi-
mately the same as an 89 (R+M)/2 unleaded gasoline.
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An important simplifying assumption embodied in this
approach is that industry-level results will be adequate for
current and preliminary decision-making with respect to vapor
pressure reductions. This underlying assumption precludes
use of study results for decisions at the sub-regional and
individual refinery levels.
Refining model study premises are summarized in the
following paragraphs.
2.1.1 Product Demands
All product requirements from each refining region,
except for sulfur, butadiene and petroleum coke, were fixed
at forecasted refining demand levels for each region. These
by-products were allowed to vary at prices determined from
current market quotations. Three forecasts based on varying
crude oil costs, were prepared. Forecasts of product demands
and related refinery output are presented in Appendix A.
2.1.2 Crude Availabi1i t ies
Projections of crude supply were developed for 17
quality classes in each region. These classes are defined in
terms of sulfur and gravity ranges. A reasonable swing
crude, selected as representative in terms of supply and
cost, was defined for each region. Arabian light crude oil
was chosen for Regions 1, 2 and 3. Region 4 was assigned
North Slope Crude. Swing crudes were allowed to vary in
volume as required by overall product output and process
volume gains and losses. The data summarized in Section 4
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have the 17 quality classes collapsed into four categories
solely for ease of reporting results. Details of crude oil
supply forecasts for each of the three crude-cost situations
are presented in Appendix B.
2.1.3 Other Raw Materials
In addition to each region's slate of crude oils,
other raw materials included ethane, propane, normal butane,
iso-butane and natural gasoline. Availabilities were fore-
cast for three crude-cost situations. These were based on
indigenous production as well as interregional movements and
foreign source imports. Details are presented in Appendix B.
2.1.4 Refinery Process Configuration
Capacity limits for all major processes were imposed
as configurations for each region. These capacities were
based on public information representing capacities as of 1
January 1986 (Oil <5c Gas Journal, March 24, 1986). Announced
changes (additions and deletions) in major process capacities
were applied to existing regional capacities. Calibration
for 1990 capacities was obtained from model results from cases
representing annual average product demands and raw material
supplies for each region. Auxiliary process capacities were
allowed to take any required level at costs representing
typical equipment construction. All major processes, except
for cat cracking of untreated feeds, were allowed to be built
at costs typical of the sizes installed in recent years.
Preventing the addition of untreated-feed cat cracking capa-
city reflects constraints on atmospheric emissions (parti-
cularily sulfur oxides). Base configuration details are
presented in Appendix E.
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2.1.5 Economics
"All costs and prices were based on first half 1986
values. Arabian crude to Regions 1, 2 and 3 was priced FOB
the Arabian Gulf plus transportation to the East and Gulf
Coasts and to the Great Lakes from the Gulf Coast. Region 4
crude price was set to an equivalent laid-in cost for Alaskan
crude. Natural gas liquids were priced using forecasts pre-
pared by Resource Planning Consultants' Hydrocarbon Pricing
Model using crude oil prices of $17, $22 and $27. Purchased
electrical power was priced according to regional quotations.
No escalation to 1990 was employed, i.e., a constant 1986
dollar value was used. Details are presented in Appendix D.
2.1.6 Product Qualities
Except for gasoline, all products were required to
meet product quality specifications as presented in Appendix
C. Gasoline octanes were forced to meet current quality spe-
cifications. Lead content of leaded regular was limited to
0.1 gram/gallon, maximum.
Current summer gasoline vapor pressure and distilla-
tion limits were determined from the ASTM D 439 schedule for
seasonal and geographic volatility classes for the areas
supplied by refineries in each region. Details on product
specifications are presented in Appendix C.
The several volatility requirements imposed on gaso-
line blends of each regional model represent the volumetric
weighting of volatility requirements for gasolines to each
region supplied from a given refining center. Table 2-2
shows the RVP summer maxima using the current ASTM D 439
schedule, state-level gasoline consumptions and potential
levels of vapor pressure reduction.
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TABLE 2-2
REGIONAL RVP CONTROL LEVELS
Summer Maximum RVP, psi
Region 1
Region 2
Region 3
Region 4
Bases
11.75
11.01
10.92
9.23
1st Reduction
10.73
10.05
9.97
8.43
2nd Reduction
9.71
9.09
9.02
7.63
3rd Reduct ion
8.69
8.14
8.07
6.82
Survey data indicate that gasolines currently being
supplied are generally below the maximum RVP suggested by
ASTM D 439. No credit has been recognized in this study to
reflect that first-increment reductions may be less costly
because of current RVP levels being below ASTM standards.
Table 2-2 limits were applied to each of three
grades of gasoline depicted in each model. Other quality
specifications for gasoline as well as other blended products
are presented in Appendix C.
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2.1.7 Alcohol Usage
' f At EPA's request, gasolines were required to repre-
sent use of methanol-plus-tertiary butyl alcohol in a two-to-
one ratio as a constituent in three percent of all gasolines.
The fixed concentration imposed for this alcohol mixture was
7.5 volume percent. Ethanol was required to be blended into
seven percent of all gasoline. When used with unleaded
regular to produce gasohol, the ratio was fixed at one part
ethanol in ten parts of unleaded regular. In the cases where
ethanol blends were .equired to meet restricted vapor
pressure, the same fixed ratio of alcohol to hydrocarbon was
employed.
Regional use of alcohols was varied to reflect the
same proportion of alcohol used in recent years. The
national uses were, however, fixed to satisfy the three and
seven percent requirements prescribed by EPA.
2.2 STUDY PARAMETERS AND CASES
Certain assumptions and conditions were analyzed to
determine their effects on the cost of reducing gasoline
vapor pressure.
2.2.1 Crude Acquisition Cost
Three crude-cost alternatives were recognized in
product-demand and raw-material-supply forecasting. A low-
cost alternative was characterized by imposing a $17 per
barrel average acquisition cost; a middle-cost alternative
was characterized by imposing a $22 per barrel cost; and, a
high-cost alternative was characterized by imposing a $27 per
barrel cost. As shown by the forecast results in Appendix A
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and B, low-cost crude results in greater demands for products
and reduced domestic crude production. High-cost crude pro-
vides higher domestic crude supply and causes lower demand
for refined products. Low and high crude-cost cases were
evaluated for Region 3 only.
2.2.2 No-Investment Effects
To assess the consequences of imposing vapor-pressure
control without allowing time for planning, engineering and
construction of new or expanded process capacity, a series of
Region 3 cases were run in which no process investment was
allowed. In other words, reduced vapor pressure had to be
accomplished within the processing capability needed for
normal (current) vapor pressure gasoline.
2.2.3 Control of Ethano1-Containing Gasoline
One set of cases for the Region 3 model involved
refinery blending of ethanol into a hydrocarbon base stock to
meet finished unleaded regular gasoline specifications. All
other cases simulated ethanol being splash blended into
finished unleaded regular (to produce gasohol). The purpose
of this set of cases was to assess the cost of controlling
vapor pressure of ethanol blends.
2.2.4 Butane Market Price Effects
An examination of the effects of butane price on
butane use was added to this study after a review of the
results for the cases described above. Three cases were
defined to assess the changes in domestic butane utilization
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as price was decreased toward a fuel value equivalent to
natural gas at $2.41 per IVMBtu. Iso-butane price was also
decreased even though earlier results indicated that domestic
supply would be used at projected market price.
2.2.5 Bunker Sales Volume Effects
Two cases were added to the study to measure the
effects of increasing the demand for bunker fuel (at constant
market price) to reflect the idea that world markets for
high-sulfur fuel oil are not affected by small changes in the
U.S. supply. Bunker demand was increased by 15,000 barrels
per day, or by approximately 14 percent.
2.2.6 Case Run Summary
Table 2-3 identifies the cases examined in terms of
parameter selections, regions and RVP control level. Note that
most, but not all, combinations of conditions were examined
with crude at $22 per barrel. Effects of crude cost, invest-
ment and ethanol blend control were studied only for Region 3.
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I
oo
TABLE 2-3
CASES STUDIED
Annual
Summer Reduction
Average Base RVP
Crude e $17/bbl
Region 3
Crude § $22/bbl
Region 1 X
Region 2 X
Region 3 X
No Investment
Ethanol w/control
Butane price variation
Increased bunker sales
Region 4 X
Crude e $27/bbl
Region 3
* RVP half way between second and third
X
X
X
X
X
X
X
levels
First
X
X
X
X
X
X
X
X
Second
X
X
X
X
X
X
*
X
X
X
Third
X
X
X
X
X
X
*
X
X
to
t-»
to
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2.3 STUDY LIMITATIONS AND AREAS EXCLUDED
Inherent in the industry-level scope and methodology
of this study are certain limitations in the range of appli-
cability of results. For example, costs which may be
experienced at specific refineries could be larger or smaller
than those measured in this study. Changes in supply
logistics caused by regional changes in manufacturing costs
cannot be addressed with regionally separated models as
employed.
Modeling assumptions embodied in the mathematical
depictions of refinery technologies are not discussed in this
report because details are subject to repeated and nearly
continuous scrutiny and improvement derived from previous and
current studies, both private and public, and because the
scope of this study and this document do not call for review
of modeling details.
In addition to the general caution that industry-
level model results do not reflect the extremes of specific
refining situations, there are four other limitations which
should be noted, namely:
1) Changes in behavior of end-use consumers are
assumed to be only those embodied in demand
forecast variations associated with different
crude costs.
2) Reduced evaporative losses and improved miles-
per-gallon effects from reducing gasoline vapor
pressure are independent of regionality (e.g.
not affected by the base summer gasoline vapor
pressure). This also implies that summer
driving habits and regional car population com-
positions are uniform among regions.
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3) Cost assessment does not address how added
costs for RVP control would be borne. If the
pump price for gasoline were increased, for
example, diesel-powered vehicle sales might be
increased as a consequence.
4) While investments for control of summer gaso-
line were required to be amortized in that part
of each year, no credit has been given to the
value of such facilities during other parts of
the year*.
Several areas were excluded from this study which
are related to the issue of reduced gasoline volatility or to
study premises and model assumptions. These exclusions do
not necessarily imply lack of concern on the part of those
involved in this study or lack of importance. These exclu-
s ions are:
1) Deviations from assumed economics, e.g., changes
in labor costs, capital costs, tax rates, etc.
have not been studied.
2) Major changes in crude supply or product dis-
tribution logistics have not been considered.
3) Technology breakthroughs in refinery processes
or in end-use of fuels were not considered.
*Prior study work indicated that such value is small.
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4) Consequential changes in refinery emissions
have not been evaluated.
5) A limit of 0.1 gram/gallon maximum lead alkyl
was imposed on leaded gasoline. No assessment
of effects from introduction of a third unleaded
grade or the elimination of leaded gasoline was
made.
6) This study assumed that enough fuel-grade
alcohol of each type would be available for
inclusion at the prescribed concentrations in
al 1 gasolines. No attempt was made to deter-
mine how such alcohol might be supplied, the
price at which it could be made available, or
the economics of alcohol blending. Methanol
for synthesis of MTBE was treated as a separate
raw material and assumed to be in ample supply.
7) Although it is theoretically possible to
restrict summer vapor pressure of only that
gasoline sold in non-compliance metropolitan
areas, this study does not address the poten-
tially lower manufacturing costs or the higher
segregation and distribution costs of doing so.
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SECTION 3
SUMMARY OF RESULTS
This section summarizes and analyzes study results.
Detailed results from which these summaries have been pre-
pared are presented in Section 4. Supporting material is
provided in appendices.
All results are based on forecasts of product
demands and crude supplies for the year 1990. Economics are
based on prices for the first half of 1986 and constant
(non-inflated) 1986 dollar values. Refinery output to
satisfy projected demands is based largely on historical
distribution patterns. For example, Gulf Coast refineries
are assumed to continue to supply large volumes of products
to East Coast and Midcontinent markets.
3.1 NATIONAL AND REGIONAL ESTIMATED COSTS
Since the regional definitions of this study
comprise all 50 states, national cost estimates are simply
the sums of regional costs for each level of RVP control.
These are presented in Table 3-1. The first sheet of this
table shows daily costs and an annual extension based on a
five-month, i.e., 152-day, summer control period. The second
sheet of Table 3-1 presents results expressed as dollars per
barrel of gasoline. Both sheets show cost components for
direct refining, refining income loss(*) and NGL-Industry
impacts. Of these three, only direct refining costs should
be considered societal since income loss and NGL-Industry
costs would appear as savings to other elements of the
nation's economy.
*' Income loss is explained and detailed in Subsection 4.5
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TABLE 3-1
ESTIMATED COST for CONTROLLING
MAXIMUM RVP of SUMMER GASOLINE
(Average Acquisition Cost of Crude « S22/BBL)
(Sheet 1 of 2)
Reduction Level
REGION 1
Direct Refining Cost(*),
Refining Income Loss,
NGL- Industry Cost,
Subtotal Cost,
REGION 2
Direct Refining CostC*),
Refining Income Loss,
NGL- Industry Cost,
Subtotal Cost,
REGION 3
Direct Refining Cost(*),
Refining Income Loss,
NGL- Industry Cost,
Subtotal Cost,
REGION 4
Direct Refining Cost(*),
Refining Income Loss,
NGL -Industry Cost,
Subtotal Cost,
NATIONAL Costs, M$/D
Direct Refining Cost<*)
Refining Income Loss
NGL -Indus try Cost
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
MS/D
Total Cost, MS/D
NATIONAL Costs, MMS/Year
Direct Refining Cost<*>
Refining Income Loss
NGL -Industry Cost
Total Cost, MMS/Year
(*) Societal Costs
1st
11.0
5.2
18.7
34.9
173.4
18.6
167.2
359.2
370.8
24.9
910.0
1,305.7
32.1
6.8
0.0
38.9
587.3
55.5
1,095.9
1,738.7
89.3
8.4
166.6
264.3
2nd
83.6
4.5
0.0
88.1
491.3
14.4
119.7
625.4
555.6
18.6
198.6
772.8
123.0
5.8
0.0
128.8
1,253.4
43.4
318.4
1,615.2
190.5
6.6
48.4
245.5
1st+2nd
94.6
9.7
18.7
122.9
664.7
33.0
286.9
984.6
926.4
43.6
1,108.6
2,078.6
155.1
12.6
0.0
167.7
1,840.7
98.9
1,414.2
3,353.8
279.8
15.0
215.0
509.8
3rd
164.6
4.5
0.0
169.1
675.0
14.4
2.1
691.5
627.6
18.5
12.4
658.5
177.6
5.8
0.0
183.3
1,644.7
43.3
14.4
1,702.4
250.0
6.6
2.2
258.8
1st+2nd*3rd
259.1
14.1
18.7
292.0
1,339.6
47.5
289.0
1,676.1
1,554.0
62.1
1,121.0
2,737.1
332.6
18.4
0.0
351.1
3,485.4
142.1
1,428.7
5,056.2
529.8
21.6
217.2
768.5
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TABLE 3-1
ESTIMATED COST for CONTROLLING
MAXIMUM RVP of SUMMER GASOLINE
(Average Acquisition Cost of Crude » S22/BBL)
(Sheet 2 of 2)
Reduction Level
REGION 1
Direct Refining CostC*),
Refining Income Loss,
NGL- Industry Cost,
Subtotal Cost,
REGION 2
Direct Refining Cost(*>,
Refining Income Loss,
NGL -Industry Cost,
Subtotal Cost,
REGION 3
Direct Refining Cost(*),
Refining Income Loss,
NGL -Industry Cost,
Subtotal Cost,
REGION 4
Direct Refining Cost(*),
Refining Income Loss,
NGL -Industry Cost,
Subtotal Cost,
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
S/bbl
NATIONAL Costs, S/bbl
Direct Refining Cost(*>
Refining Income Loss
NGL -Industry Cost
Total Cost, $/bbl
(*) Societal Costs
1st
0.017
0.008
0.029
0.054
0.084
0.009
0.081
0.174
0.119
0.008
0.292
0.419
0.033
0.007
0.000
0.040
0.086
0.008
0.161
0.256
2nd
0.130
0.007
0.000
0.137
0.238
0.007
0.058
0.303
0.179
0.006
0.064
0.249
0.127
0.006
0.000
0.133
0.185
0.006
0.047
0.239
1st+2nd
0.147
0.015
0.029
0.191
0.322
0.016
0.139
0.477
0.298
0.014
0.356
0.668
0.160
0.013
0.000
0.173
0.272
0.015
0.208
0.494
3rd
0.257
0.007
0.000
0.264
0.327
0.007
0.001
0.335
0.203
0.006
0.004
0.213
0.184
0.006
0.000
0.190
0.244
0.006
0.002
0.252
1st+2nd*3rd
0.404
0.022
0.029
0.455
0.649
0.023
0.140
0.812
0.501
0.020
0.360
0.881
0.344
0.019
0.000
0.363
0.515
0.021
0.210
0.747
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3.1.1 Refining Costs
-Graphical presentation of refining costs are shown
in Figures 3-1 and 3-2.
Figure 3-1 illustrates refining costs at three per-
centage levels by Region. Refining cost effects, as
illustrated in Figure 3-2, show the strong influence of
regional natural gas prices. Relatively high prices in
Regions 1 and 4 cause RVP-control costs in those regions to
be lower than control costs in Regions 2 and 3. This rela-
tionship results from the alternate disposition of light
hydrocarbons as refinery fuel. These hydrocarbons must be
backed out of gasoline to reduce RVP. At best, refinery fuel
can have no greater value than purchased natural gas cost.
Consequently, in Regions 1 and 4, where natural gas is rela-
tively costly, the alternate value for light hydrocarbons is
greater than in Regions 2 and 3. Thus, the light hydrocar-
bons' loss in value, when not sold as gasoline, is less in
Regions 1 and 4.
Refining results from this study differ from earlier
results1 because of three major differences in study premises.
1) This study recognizes an increase in mile-per-
gallons efficiency with lower-RVP (i.e., higher
density) gasoline as well as a reduction in
evaporative leases.
2) This study requires all process investments for
RVP control to be amortized during the summer
control period, i.e., 152 days.
SWR-8701 Bonner 6 Moore Management Science 3-4
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CO
z:
x
I
CD
-J
O
-------
0.80
0.70'
0.60
CD
ffl
«» 0.50
o
o
Q
UJ
g 0.40
0.30
0.20
77
0.10
10 20
% OF BASE RVP REDUCTION
30
Figure 3-2
Added Cost of Controlled Gasoline
(Crude @ $22/BBL)
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3) Crude cost is treated as a parameter in this
study. The central value of $22 per barrel is
well below the $31 per barrel value used in the
earlier study.
When these changes are taken into account*, the
earlier study results compare reasonably well and any dis-
crepancy is easily explained by several other changes and
refinements in this current study, e.g., revised demand
forecasts.
Refining costs shown in Table 3-1 include an adjust-
ment to recognize that reducing RVP reduces refining industry
revenue and, thus, its margin from gasoline sales because
less gasoline is sold. Value of lost sales has been approxi-
mated by using a refining margin on gasoline of 5.6 percent
applied to the incremental cost of gasoline at each reduced
RVP level times the decrease in gasoline sales. This adjust-
ment ranges from $0.009 per barrel to $0.006 per barrel for
each increment of RVP control.
Results from the earlier study placed the cost of a 2-psia
reduction in RVP at $0.65 to $0.68 per barrel. Adjusting
those results for crude cost changes between the two
studies indicates an equivalent range of $0.46 to $0.48
per barrel for crude at $22 per barrel. Accounting for
gasoline demand decreased by improved mileage and lower
evaporative losses is a reduction of approximately $0.26 per
barrel which adjusts the above-produced range to $0.20 to
$0.22 per barrel. Using a 1990 summer average (uncontrolled
RVP) of 10.78, a 2-psi adjustment amounts to a decrease of
18.6 percent. At this reduction level, the curve for
national costs in Figure 3-2 shows a control cost of approx-
imately $0.32 per barrel. Comparing this latter figure to
the adjusted cost range from the earlier study suggests that
the difference in amortization (restricted to summer period
only) adds $0.10 to $0.12 per barrel to RVP control cost.
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3.1.2 NGL Industry Costs
|The refining cost increases resulting from gasoline
RVP control are only a portion of the costs which will be
experienced by the domestic energy industry. Domestic gas
processors will also be impacted by lower values for a por-
tion of their production and the entire natural gas liquids
(NGL) industry will be strongly affected. A principal
response of the refining industry to reduced gasoline volati-
lity is to reduce purchases of normal-butane for gasoline
blending, which will depress the value of this product.
Results presented in Table 3-2 show reduction in
refinery purchases of normal-butane (excluding volumes con-
tained in North Slope Crude and purchases for ethylene
feedstock use).
TABLE 3-2
REDUCTION IN U.S. REFINERY PURCHASES
OF NORMAL-BUTANE
(MBCD)
RVP
Reduct ion Reduction in Purchases*
(% of Base RVP)
8.7 -119.5
17.4 -203.5
26.1 -205.4
*Reduction in refinery purchases relative to those
for the summer base case with $22 crude cost.
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U.S. gas processors produced 202 MBCD of normal-butane
in 1985; but they are projected to produce only 194 MBCD in
1990. "Phe large reductions in refinery purchases shown in
refining model results indicate that gas processors will have
to seek alternative markets for most of their production.
Possible alternate markets include the following:
Ethylene feedstock
Feedstock foe other chemicals (maleic anhydride,
acetic acid, aerosols, MTBE, etc.)
Boiler fuel
Existing "Other chemical" feedstock and household/commercial
fuel markets are small - less than 15,000 bpd, and are
limited by process and equipment constraints. Thus ethylene
feedstock and boiler fuel uses would have to absorb most of
the butane displaced from refineries.
The alternative of leaving butane in the natural gas
stream at the gas processing plant is considered impractical
since butane has to be recovered in order to extract ethane
and propane from raw natural gas. Ethane is required as an
ethylene feedstock by those ethylene plants without the capa-
city to substitute other feedstocks. A substantial portion
of propane production goes to home heating and agricultural
uses without alternative fuel capability. In addition, rein-
jection of butane into the natural gas stream represents an
economic penalty to the gas processor and is prohibited by
dew point specifications of most gas transmission pipelines.
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Our modeling approach allowed the purchase of
desired volumes of butane for refining and ethylene feedstock
needs. However, refining was not required to purchase all of
the domestic supply since markets exist outside of the
refining sector and a study objective was to determine how
refinery purchases will respond to volatility control.
Natural gas processors will be forced to market
normal-butane released from refineries to boiler fuel and/or
ethylene feedstock markets at values substantially below
historical butane prices. The lower values for normal-butane
and other NGLs represent a cost of volati1ity control which
will be borne by the gas processing industry. The normal-butane
regional fuel value. Our analysis indicates that a signifi-
cant portion of the normal-butane displaced from gasoline
blending will have to be marketed as boiler fuel because of
the saturation of other markets.
Our analysis shows that increased usage of butane as
an ethylene feedstock will be primarily at the expense of
naphtha and gas oil feedstocks. This conclusion is drawn
from analysis of feedstock flexibility of individual olefin
plants. Most U.S. olefin plants were designed for either
light feedstocks (ethane, propane) or heavy feedstocks
(naphtha, gas oil, natural gasoline, etc.). Only one U.S.
olefin plant has been specifically designed to crack butane
and this plant has been substantially modified so that it is
now a light feedstock cracker without butane capability.
Optimum cracking conditions (residence time, steam-to-oil
ratio, heat balance) differ for butane as compared to ethane
SWR-8701 BonnareMoorBManaflBmentSctence 3-10
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or propane so it is usually cracked as a separate feedstock.
Furthermore, cracking butane yields more coproducts than do
light feedstocks, so recovery systems have to be sized accor-
dingly. Because of these considerations, most plants
designed for light feedstocks have little or no butane
feedstock flexibility.
On the other hand, olefin plants designed for
naphtha can usually crack up to 20 percent butane without
design limitations. Most U.S. olefin plants designed for
heavy liquids have been modified to increase their flexibi-
lity for ethane and propane in order to take advantage of the
generally attractive economics of these feedstocks. Our
modeling effort reflects the industry capacity feedstock
1imi tat ions.
Within the physical constraints of the olefin plant
feedstock flexibility, ethylene feedstocks compete with each
other on an economic basis. This raises the question as to
whether a reduction in butane prices to fuel value would
lower other LPG feedstocks to comparable levels. Our answer
is as follows.
Ethane prices in this study are approximately at
fuel value without any adjustment for lower normal-butane
values. Therefore, any further reduction in ethane price
will only reduce ethane supply or shift ethane to boiler fuel
markets at approximately the same price. As a result, no
effect on ethane price is anticipated.
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Refining model results show propane purchases for
ethylene feedstock consistent with needs of plants with mini-
mum feedstock flexibility.* These plants cannot substitute
any appreciable volume of butane within present configuration
so no adjustment was made in propane prices.
The model results show that even at fuel value, nor-
mal butane is still not an economically attractive substitute
for natural gasoline as an ethylene feedstock. Our analysis
indicates that 75 to 85 Mbpd of butanes (including refinery
source butane) can be cracked as an olefin feedstock given
the availability of other products and the existing physical
constraints of the industry. Thus, at least some of the
available domestic supply will have to be marketed as fuel
and this increment will set the market price. While our ana-
lysis of ethylene feedstocks does not show cost impacts
beyond normal-butane, lower normal-butane prices will have an
impact on iso-butane price. Lower iso-butane prices would
result because normal-butane can be isomerized to iso-butane
(at a cost of about six cents per gallon).
The NGL sector costs shown in Table 3-1 are based on
reduced normal and iso-Butane values. These reduced values
will impact all of the domestic supply of butanes (normal
plus iso-Butane) except for west coast production because a
two-tier price system could not exist. Total costs to the
NGL sector at the 3 RVP reduction level are calculated to be
'Approximately 17.4 billion pounds of the ethylene industry's
total annual capacity of 35.0 billion pounds is classified
as LPG capacity. Most of these plants can utilize only
ethane or propane for feedstock. The remaining 17.6
billion pounds of capacity can utilize a full range of
feedstocks from ethane through naphtha (and in some instan-
ces through gas oil).
SWR-8701 BonmrB Moore Management Science 3-12
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$2 million per day during the summer period or $312 million
annually> However, the NGL costs in Table 3-1 reflect only
those sales to uses other than refining and olefin feedstock
applicat ions.
Non-refinery volumes include normal-butane used as a
feedstock for petrochemicals other than olefins (i.e., maleic
anhydride, acetic acid, and aerosols) and normal-butane used
as boiler fuel. Iso-butane totals include volumes consumed
for propylene oxide and for aerosols. Sales to the refining
sector were not included because lower revenue to the NGL
sector would be offset by lower costs to refining.
Regions 2 and 3 show increasing costs to the NGL
sector as RVP is reduced from one to three psia because
increasing amounts of domestic butane are displaced from the
refining sector. In Region 1, non-refinery sales are a
constant volume for all RVP cases and reductions in refinery
purchases from case to case would be accomplished by reducing
transfers from other regions. Since there is no change in
non-refinery purchases over the three levels of RVP reduc-
tio'n, all NGL costs in Region 1 would occur with the first
reduction case.
In Region 4, the refineries are shown purchasing no
normal-butane in the base case. Butane values would there-
fore, be unaffected by volatility reductions and would cause
no impact on the NGL sector in that region.
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Bonner 6 Moore Management Science
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3.2 PARAMETER EFFECTS
^Three parameters were included in the design of this
study. One was crude cost, which was studied at three
levels, namely, $17, $22 and $27 average acquisition cost per
barrel. Another was process investment, which was studied as
a "go" or "no-go" possibility. A third was control or non-
control of ethanol-containing gasolines to meet restricted
vapor pressure.
3.2.1 Effect of Crude Cost on RVP-Control Costs
Usi.ng the refining model for Region 3, cases for
control of summer gasoline RVP were prepared at crude and NGL
costs consistent with $17 and $27 per barrel. These
translate into estimated Gulf Coast landed costs for Arabian
Light Crude of $17.94 and $28.41 per barrel, respectively.
Associated with each crude cost were corresponding forecasts
for refined product output requirements and crude supplies as
well as costs of other raw materials and purchased natural
gas and electrical energy. Capital costs and other operating
costs were not varied.
Refining control costs for Region 3 at the three
levels of crude cost are shown graphically in Figure 3-3.
The interesting aspect of this figure is that refining
control cost is not affected greatly by changes in crude
cost. It also shows that refining costs are at (or near) a
maximum when 1990 crude prices are at $22 per barrel. This
indicates that lower ($17) crude cost is enough to overcome
the modest larger refined product demands forecast at that
low cost. At $27 per barrel, however, decreases in fore-
casted refined product demands overshadow higher raw material
SWR-8701 Bonner B Moore Management Science 3-14
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0.60
O.SO
ffl
0.40
o
o
Q
UJ
Q
Q
0.30
0.20
0.10
10 20
% OF BASE RVP
30
Figure 3-3
Crude Cost Effect on Refining Costs
for RVP-Control (Region 3)
SWR-8701
Bonner B Moore Management Science
3-15
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costs. This phenomenon should be recognized more as a con-
sequence of the relative optimism or pessimism of forecasts
and not /any intrinsic significance of the crude acquisition
w
costs employed.
Total control costs (refining plus NGL costs) for
Region 3 at the three levels of crude oil costs are shown in
Figure 3-4. Inclusion of NGL costs spreads the control cost
curves considerably for the three cases. Most of the NGL
costs occur at the first reduction level because most of the
refinery purchases of normal-butane are displaced by the
first reduction level.
NGL costs increase with increased crude oil and
natural gas costs. This is due to the increasing penalty of
pricing a portion of the NGL supply at fuel value. Refining
costs are however, at (or near) a maximum with $22 crude.
Thus, total cost for both sectors is highest for the $22
crude oi1 case.
3.2.2 Effect of Process Investment Exclusion
Using the Region 3 model, three cases were run in
which process expansion or addition was not permitted. Thus,
reduced RVP had to be achieved by changes in operations and
blending. Such a situation would occur if refiners should be
required to meet RVP restrictions without sufficient advance
notice so that planning, engineering and construction of new
or expanded facilities can take place.
Figure 3-5 presents a graphical comparison of
results with and without process investment. As shown,
refining costs more than double when process investment is
excluded as an alternative.
SWR-8701
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0.90
0.80
0.70
0.60
0.50
00
00
v» 0.40
8
Q
$22.
$27.
$17.
0.30
0.20
0.10
10 20
% OF BASE RVP
30
Figure 3-4,
Crude Cost Effect on Refining Plus NGL
Costs for RVP-Control (Region 3)
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1.40
1.20
1.00
O
CD
a
UJ
o
0.60
0.40
0.20
0.0
10 20
% OF BASE RVP REDUCTION
30
Figure 3-5
No-Investment Effect on RVP-Control
Refining Costs (Region 3)
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3.2.3 Effect of Ethanol Blend Control
-Except for the three cases of this sensitivity ana-
lysis, all other model results include "splash blending" of
ethanol to produce gasohol*. For this set of three cases,
ethanol was blended into a hydrocarbon base blend to meet
unleaded regular specifications. The three cases, using the
model for Region 3, impose the three levels of RVP reduction
on al1 gasolines.
Results for RVP control costs are shown in Table
3-3. For comparison, the corresponding results from the
"gasohol" cases for Region 3 are also presented. No base-RVP
case with controlled ethanol blends was prescribed by the
study work plan. Thus, the cost of the first level of RVP
control is low because of the octane credit achieved with in-
refinery blending of ethanol.
TABLE 3-3
EFFECTS OF CONTROLLING RVP OF ETHANOL BLENDS
(Region 3 with Crude @ $22 per barrel)
Refining Control Cost, $/BBL
First Second Third
Level Level Level
W/O Control (i.e., W/Gasohol) 0.126 0.186 0.209
W/Control 0.048 0.190 0.211
*Gasohol is represented in this study as a post-refinery
blend of ten parts of finished unleaded regular gasoline and
one part denatured ethanol.
SWR-8701 Bonner B MOOT Management Science 3~19
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Table 3-3 clearly shows that RVP control costs (at least for
the second and third levels) are essentially the same whether
ethanol As used to make gasohol downstream of refining or in
1*
on-spec Unleaded fuel. Since no case was run with ethanol
blends required to meet base-case summer RVP, the cost of the
first level of control cannot be determined. It seems reaso-
nable to assume, however, that control costs for the first
increment would be similar to those for gasohol's first
increment.
It should be pointed out that the octane credit for
ethanol, when blended to meet unleaded regular specifications,
more than offsets the RVP debit. These cases show added
values for "in-refinery" blending (ethanol into a sub-octane-
sub-RVP base stock) of 32.7, 30.8 and 30.0 cents per gallon
of ethanol above its value as unleaded gasoline, at each reduced
RVP level, respectively. No attempt to estimate the handling
and distribution cost for this fuel was made and none is
included in the above-stated added values. This analysis
assumes that the cost and availability of ethanol at a refin-
ery would be the same as that at the gasohol blending point.
3.2-. 4 Effect of Domestic Butane Price
An Examination of the effects of butane price on
butane use was added to this study after a review of the
results for the cases described above. Three cases were
defined to assess the changes in domestic butane utilization
as price was decreased toward a fuel value equivalent to
natural gas at $2.41 per MMBtu. These lower prices were one-
fourth, one-half and three-fourths of the way toward fuel
value from projected market price with crude at $22 per
barrel. Resulting prices for normal and iso-Butane are shown
in the following table.
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Bonnw 8 Moore Management Science 3-20
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BUTANE PRICE RANGE
($/bbl)
Full
Ma r k e t
Pr ice
3/4
Ma r k e t
Pr ice
1/2
Ma r k e t
Pr ice
1/4
Ma r k e t
Pr ice
Normal-Butane 17.36 15.44 13.52 11.60
Iso-Butane 18.68 17.24 15.98 14.96
Maximum RVP for these sensitivity cases was set be-
tween the second and third levels of control, i.e., at a
reduction proportional to 2.5 psia from 11.5 psia, or a 21.74
percent reduction in allowable maximum RVP. This reduction
level was not directly represented in the cases originally
defined for study. As a means, therefore, of comparing these
three cases with a case employing full market price for
butane, summary results include a set of averages* of second-
level and third-level results.
Reduction in the market price for butane, which
would accompany a decrease in refinery use of butane, is
shown to cause the expected consequences. Olefin feedstock
mix is changed to include normal-butane. Domestic butanes
from gas processing and from refining are cracked in place of
propane, light naphtha and distillate feedstocks. This hap-
pens with the first decrease in butane price. Further reduc-
tion in butane price has no effect other than decreasing the
cost of raw materials to the combined refining and olefins
sectors in Region 3. Steam cracking facilities in other
regions currently cannot crack any appreciable amount of
* Actual results for a case with full market prices for
butanes and at the intermediate level of RVP control would
not necessarily be the average of results from cases at the
second and third levels of control.
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Bonner 6 Moore Management Science
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butane feedstock. MTBE production did not change because all
i so-buty?lene feedstock was being used in every case and
butane dehydrogenation was not modeled as a route to MTBE.
Table 3-4 presents a summary of pertinent results
from these three cases along with the average values from the
second and third level results with full market price on
butane. Detailed results are presented in Section 4.
TABLE 3-4
SUMMARY OF BUTANE PRICE EFFECTS
Full "3/4" "1/211
Item Market Market Market Market
Prices, S/bbl
n-Butane 17.36 15.44 13.52 11.60
i-Butane 18.86 17.24 15.98 U.96
Raw Materials, Mbpcd
Swing Crude 1.027.560 970.159 970.164 970.164
Propane 86.838 22.113 22.117 22.117
Domestic n-Butane 0.000 127.000 127.000 127.000
Domestic i-Butane 63.000 63.000 63.000 63.000
Imported Butanes 12.609 10.989 10.984 10.985
Cash Flow(*)
,M$pcd (1,242.304) (966.139) (642.957) (334.859)
,$/bbl (0.401) (0.312) (0.208) (0.108)
Process Investment^)
,MM$ 1,037.439 906.937 906.936 906.941
,MS/bbl 0.335 0.293 0.293 0.293
() Relative to b*M ca»e
SWR-8701 Bonnw 6 Moore Management Science 3_22
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Butanes cracked at the lower prices include 127,000
barrels per day of production from domestic NGL operations
and 30,0.00 barrels per day from refining. Current steam
cracker design in Region 3 would not allow this much butane
without loss of overall ethylene production. Engineering
changes as well as operational changes would be required to
produce imposed ethylene and propylene demands with the
feedstock mix selected by the model. Ability to make the
changes needed by 1990 was not pursued in this study, but
three years is viewed as a minimum time for any significant
process modification.
Without facility modification, less butane would be
consumed by the olefins sector than shown by these case
results. This means that butane price would fall toward fuel
value even though some of the domestic production were being
cracked. Longer term, olefin producers would have to be
assured of depressed butane prices before they would commit
to the capital investment required to modify their facili-
ties. We conclude, therefore, that the use of a fuel value
for butane in assessing the cost impact of RVP control on the
NGL sector is correct.
3.2.5 Bunker Fuel Sales Volume Effects
To measure the effect on RVP control costs of an
increase in production of residual fuel, two sensitivity
cases were defined and run in which bunker demand was
increased by 15,000 barrels per day. This increase is
equivalent to a 14.29 percent change in output. One of the
cases imposed base-case RVP's. The other imposed the second
RVP control level.
SWR ft 7 fl1
Borrow B Moore Management faience 3-23
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Control costs from these cases and from the original
cases pair are nearly identical. Daily and per-barrel costs
as well? as other selected results from these (and the
corresponding original) cases are presented in Table 3-5.
Detailed results are presented in Section 4.
TABLE 3-5
SUMVIARY OF BUNKER FUEL VOLUME EFFECTS
Bunker Volume and RVP Level
105,000 105,000 120,000 120,000
Item base -2 base -2
Raw Materials, Mbpcd
Swing Crude 910.616 1,007.363 922.634 1,024.373
Propane 85.000 71.552 105.270 79.535
Domestic n-Butane 82.488 0.000 83.263 0.000
Domestic i- Butane 63.000 63.000 63.000 63 000
Imported Butanes 54.893 44.704 54.320 36.492
Relative Cash Flow
M$Pcd -37.164 -966.117 -275.501 -1189.697
RVP Control Cost
-928.953 -914.196
Vbbl -0.299 -0.295
Process Investment
,MM$ 102.627 896.749 52.590 852.114
RVP Control Invs'mt
»* 794.122 799.524
,«/bbl 0.256 0.258
As shown in RVP control costs are essentially un-
affected by the change in bunker fuel output. Investment
requirements are also unaffected by the change in bunker fuel
output. Thus, the balance between raw material and capital
costs is unaffected.
SWR-8701
Burner B Moore Management Science 3-24
-------
3.3 CONCLUSIONS
-Results from this study show significant variation
in RVP control cost among regions due, primarily, to the
variation in cost of refinery fuel. In Region 1 (East Coast)
and Region 4 (California), refiners are shown to experience
much lower costs of control than refiners in Regions 2 and 3
(Midcontinent* and Gulf Coast). Because of the dominating
gasoline volumes produced by Region 2 and 3 refineries,
national costs, per barrel of gasoline, are similar to costs
for these major supply regions.
When compared to earlier study results, the lower
refining costs developed in this study clearly show the major
influence of the savings from mileage improvement and lower
evaporative losses. From the $22-per-barrel crude cost
results, RVP-control refining costs wi thout these savings
would be approximately $0.25, $0.55 and $0.85 per barrel of
gasoline at first, second and third levels of RVP reduction,
respectively. At the first level of RVP reduction, for
example, gasoline volume savings account for approximately
$0.15 per barrel. Accounting for these fuel savings reduces
costs by 38 percent, 52 percent and 63 percent, respectively.
Thus, the effect of the mileage and evaporative-loss credit
is large. While changes in gasoline density and aromatics
content indicate that EPA-supplied economy factors are pro-
bably conservative, the realization of this saving involves
such a small improvement in overall fuel economy and loss
reduction that confirming the validity of such savings may be
extremely di ff icult.
*Region 2 includes the Rocky Mountain and Northwestern refin-
eries whose output is a relatively small part of the region's
total.
SWR-8701 Bonner 6 Moore Management Science 3-25
-------
The negative impact of gasoline volatility control
will be felt more strongly in the NGL industry than in the
->r
refining?industry. Altogether, volatility control will cost
the NGL industry about 10 percent of its revenues. A part of
this impact is masked by study results because it becomes a
benefit -- in the form of lower raw materials cost -- to the
refining industry. Additionally, the impact on the NGL
industry will be proportionately greater because a larger
share of its total product is involved.
Homer 8 Moore Management Science 3-26
-------
SECTION 4
DETAILED RESULTS
This section contains selected detail for each case
evaluated in this study. As shown earlier in Table 2-1, not
all combinations of region, vapor pressure level and para-
meter situations were included. Presentation order and
grouping of case results are based on region with crude cost
at $22 per barrel. Sensitivity analysis cases for Region 3
are next and are arranged to present alternate crude-cost
cases, followed by no investment cases, followed by "control
ethane" cases. Such ordering is, of course, arbitrary and
should not be taken to imply relative significance.
Results for each case are arranged in row-groups,
namely, input-output detail, gasoline blend detail and
results-differences between reduced-RVP cases and the
appropriate base-RVP case. Results differences are always
grouped with related reduced-RVP cases except for the
"control ethanol" cases, which have no corresponding base
case.
In all cases where ethanol is splash-blended with
unleaded regular, pool qualities are reported without
accounting for the effects of ethanol, i.e., pool qualities
refer to refinery pools. The three "control ethanol" cases
treat ethanol as a gasoline component and show pool qualities
as if the ethanol were blended at the refinery.
SWR-8701 BonnsfB Moore Management Science 4-1
-------
4.1
CASES WITH CRUDE AT $22 PER BARREL
^Selected detail from results of cases for each
region at base (normal RVP) and reduced vapor pressure are
presented in Tables 4-1 through 4-4.
TABLE 4-1
EAST COAST MODEL RESULTS
(Page 1 of 4)
REGION 1
RAW MATERIAL PURCHASES, MBPCO
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SWING CRUDE
SUBTOTAL CRUDES
ETHANE & PROPANE
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, S/Bbl
SWING CRUDE
PROPANE
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCO
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
CRUDE: *22
SUMMER
773.000
36.000
99.000
204.000
125.636
1237.636
0.000
0.384
25.212
0.000
0.000
4.292
1267.524
23.170
16.510
19.270
20.630
19.370
15.960
3.600
102.668
304.987
201.180
40.109
643.944
327.119
191.080
122.996
41.756
-64.371
1267.524
ETHANOL: SPLASH INVESTMENT: YES
LEVEL 1
773.000
36.000
99.000
204.000
132.266
1244.266
0.000
0.384
13.124
4.883
0.000
4.277
1266.934
23.170
16.510
19.270
20.630
19.370
15.960
3.600
102.124
303.370
200.114
39.913
645.521
327.119
191.080
123.333
43.681
63.800
1266.934
LEVEL 2
773.000
36.000
99.000
204.000
147.799
1259.799
0.000
0.384
1.577
4.286
0.000
4.262
1270.308
23.170
16.510
19.270
20.630
19.370
15.960
3.600
101.713
302.151
199.309
39.736
642.909
327.119
191.080
124.888
47.961
63.649
1270.308
LEVEL 3
773.000
36.000
99.000
204.000
162.000
1274.000
0.000
0.384
0.000
3.535
0.000
4.249
1282.168
23.170
16.510
19.270
20.630
19.370
15.960
3.600
101.313
300.961
198.525
39.579
640.378
327.119
191.080
126.180
57.368
59.957
1282.168
SWR-8701
Bormer B Moore Management Sctence
4-2
-------
TABLE 4-1
EAST COAST MODEL RESULTS
(Page 2 of 4)
REGION 1
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X 3 160 -LEADED REGULAR
X 3 160 -UNLEADED REGULAR
X a 160 -UNLEADED PREMIUM
X a 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X 8 210 -UNLEADED REGULAR
X 3 210 -UNLEADED PREMIUM
X 3 210 -TOTAL POOL
X a 230 -LEADED REGULAR
X a 230 -UNLEADED REGULAR
X 3 230 -UNLEADED PREMIUM
X 3 230 -TOTAL POOL
X a 330 -LEADED REGULAR
X 8 330 -UNLEADED REGULAR
X 3 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
CRUDE: $22
SUMMER
11.500
11.750
11.750
11.709
123.000
123.000
123.000
123.000
38.498
37.101
41.568
38.761
60.156
59.390
54.134
57.831
65.333
66.975
62.963
65.420
91.659
92.177
97.013
93.643
ETHANOL: SPLASH INVESTMENT: YES
LEVEL 1
10.730
10.730
10.730
10.730
123.000
129.357
128.622
128.081
42.833
33.942
40.096
37.369
62.542
58.044
52.535
57.014
67.452
67.152
60.436
65.048
92.081
93.495
94.628
93.627
LEVEL 2
9.710
9.710
9.710
9.710
123.771
136.142
134.926
133.729
46.500
30.747
37.569
35.511
66.249
55.671
50.508
55.746
70.381
65.354
58.750
64.059
92.291
93.533
94.016
93.484
LEVEL 3
8.690
8.690
8.690
8.690
127.635
141.268
141.512
139.116
46.500
30.204
33.701
33.991
66.993
54.084
49.397
54.693
70.904
63.451
59.075
63.268
92.077
92.300
95.745
93.368
SWR-8701
Homer 6 Moore Management Science
4-3
-------
TABLE 4-1
EAST COAST MODEL RESULTS
(Page 3 of 4)
REGION 1
GASOLINE BLENDING DETAIL, contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY" -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
(R+M5/2 OCTANE -LEAD REGULAR
RESEARCH OCTANE -UNLEADED REG
MOTOR OCTANE -UNLEADED REG
(R+M)/2 OCTANE -UNLEADED REG
RESEARCH OCTANE -PREMIUM
MOTOR OCTANE -PREMIUM
(R+M)/2 OCTANE -PREMIUM
MAJOR UTILITIES PURCHASED
CATALYST/CHEMICALS, M$PCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MMS
RELATIVE CASH FLOW, MIPCD
CRUDE: S22
SUMMER
0.736
0.727
0.750
0.736
29.192
21.981
38.961
28.604
93.685
84.315
89.000
91.960
82.540
87.250
96.292
87.208
91.750
175.270
444.528
186.419
6021.922
0.000
4666.855
ETHANOL:
LEVEL 1
0.730
0.732
0.756
0.739
26.994
23.185
41.418
29.652
93.688
84.312
89.000
92.055
82.445
87.250
96.485
87.015
91.750
176.804
442.260
181.069
6080.883
5.211
4678.020
SPLASH INVESTMENT: YES
LEVEL 2
0.726
0.737
0.762
0.743
23.446
24.366
43.934
30.488
93.500
84.500
89.000
92.128
82.372
87.250
96.957
86.543
91.750
180.029
440.412
162.201
6168.945
41.129
4761.297
LEVEL 3
0.726
0.740
0.768
0.747
22.783
25.665
45.457
31.538
93.500
84.500
89.000
92.220
82.280
87.250
97.250
86.250
91.750
182.883
438.690
109.627
6228.820
164.695
-4925.695
SWR-8701
BomefB Moore Mar
rt Science
4-4
-------
TABLE 4-1
EAST COAST MODEL RESULTS
(Page 4 of 4)
CRUDE: (22
SUMMER
CASE DIFFERENCES
SWING CRUDE, MBPCD
NORMAL BUTANE, MBPCD
ISO BUTANE, MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MM*
RELATIVE CASH FLOW, M$PCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SWING CRUDE, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/8bl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KWH/Bbl
PROCESS INVESTMENTS, M$/Bbl
RELATIVE CASH FLOW, $/Bbl
REGION
1
ETHAHOL: SPLASH INVESTMENT: YES
LEVEL 1
6.630
12.088
4.883
0.015
0.590
0.544
1.617
1.066
0.196
3.423
1.925
1.534
2.268
5.350
58.961
5.211
11.165
0.010
-0.019
0.008
0.003
0.002
0.004 '
0.008
0.091
0.008
0.017
LEVEL 2
15.533
11.547
0.597
0.015
3.374
0.411
-1.219
0.805
0.177
2.612
4.280
3.225
1.848
18.868
88.062
35.918
83.277
0.024
0.018
0.001
0.007
0.005
0.003
-0.029
0.137
0.056
0.130
LEVEL 3
14.201
1.577
0.751
0.013
11.860
0.400
1.190
0.784
0.157
2.531
9.407
2.854
1.722
52.574
59.875
123.566
-164.398
0.022
0.002
-0.001
0.015
0.004
0.003
0.082
0.093
0.193
0.257
SWR-8701
Homer 6 Moore Management Science
4-5
-------
TABLE 4-2
MID-CONTINENT/ROCKIES/NORTHWEST MODEL RESULTS
(Page 1 of 4)
REGION 2
RAW MATERIAL PURCHASES, HBPCD
LOW SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SWING CRUDE
SUBTOTAL CRUDES
ETHANE & PROPANE
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, $/Bbl
SWING CRUDE
PROPANE
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
CRUDE: $22
SUMMER
2266.000
374.000
293.000
752.000
232.374
3917.374
49.000
2.993
64.803
43.773
57.000
29.861
4164.804
23.750
14.070
17.830
21.030
23.400
15.960
2.900
436.718
885.304
427.682
325.468
2075.172
1327.072
350.170
469.914
135.369
192.893
4164.804
ETHANOL: SPLASH INVESTMENT: YES
LEVEL 1
2266.000
374.000
293.000
752.000
272.400
3957.400
49.000
2.993
22.447
34.175
57.000
29.709
4152.724
23.750
14.070
17.830
21.030
23.400
15.960
2.900
434.403
880.612
425.415
323.743
2064.173
1327.072
350.170
472.349
136.881
-197.921
4152.724
LEVEL 2
2266.000
374.000
293.000
752.000
309.705
3994.705
49.000
2.993
0.000
34.900
57.000
29.595
4168.193
23.750
14.070
17.830
21.030
23.400
15.960
2.900
432.656
877.071
423.705
322.442
2055.874
1327.072
350.170
473.474
154.781
193.178
4168.193
LEVEL 3
2266.000
374.000
293.000
752.000
342.994
4027.994
49.000
2.993
0.000
2.655
57.000
29.481
4169.123
23.750
14.070
17.830
21.030
23.400
15.960
2.900
430.953
873.618
422.037
321.172
2047.780
1327.072
350.170
475.237
162.546
193.682
4169.123
SWR-8701
Bonner 6 Moore Management Science
4-6
-------
TABLE 4-2
MID-CONTINENT/ROCKIES/NORTHWEST MODEL RESULTS
(Page 2 of 4)
REGION 2
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, f -TOTAL POOL
X 3 160 -LEADED REGULAR
X a 160 -UNLEADED REGULAR
X 3 160 -UNLEADED PREMIUM
X a 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X a 210 -UNLEADED REGULAR
X 3 210 -UNLEADED PREMIUM
X 3 210 -TOTAL POOL
X 3 230 -LEADED REGULAR
X 3 230 -UNLEADED REGULAR
X a 230 -UNLEADED PREMIUM
X a 230 -TOTAL POOL
X 3 330 -LEADED REGULAR
X a 330 -UNLEADED REGULAR
X 8 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
CRUDE: S22
SUMMER
11.010
11.010
11.010
11.010
127.000
127.000
127.000
127.000
37.479
37.939
40.478
38.384
56.795
56.317
58.322
56.853
61.962
63.272
73.823
65.253
90.749
93.777
97.998
94.020
ETHANOL: SPLASH INVESTMENT: TES
i F '
LEVEL 1
10.050
10.050
10.050
10.050
127.000
131.702
130.787
130.473
41.074
36.555
38.492
37.964
61.782
56.031
55.909
57.267
66.764
63.653
70.858
65.885
91.698
94.711
95.417
94.201
LEVEL 2
9.090
9.090
9.090
9.090
132.185
135.014
141.147
135.711
39.504
37.790
28.825
36.239
60.645
56.000
52.122
56.186
65.901
63.047
69.778
65.121
91.596
93.675
97.634
94.070
LEVEL 3
8.140
8.140
8.140
8.140
140.207
137.872
147.836
140.527
34.056
37.314
30.202
35.070
57.396
59.050
43.978
55.446
63.194
68.678
55.479
64.637
91.050
94.048
96.730
93.966
SWR-8701
Honner 6 Moore Management Science
4-7
-------
TABLE 4-2
.MID-CONTINENT/ROCKIES/NORTHWEST MODEL RESULTS
^ (Page 3 of 4)
REGION 2
GASOLINE BLENDING DETAIL, contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY' -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
(R+M)/2 OCTANE -LEAD REGULAR
RESEARCH OCTANE -UNLEADED REG
MOTOR OCTANE -UNLEADED REG
(R+M)/2 OCTANE -UNLEADED REG
RESEARCH OCTANE -PREMIUM
MOTOR OCTANE -PREMIUM
(R+M)/2 OCTANE -PREMIUM
MAJOR UTILITIES PURCHASED
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MM*
RELATIVE CASH FLOW, M$PCD
CRUDE: S22
SUMMER
0.737
0.749
0.704
0.737
29.207
35.929
10.708
29.031
93.577
84.423
89.000
91.868
82.632
87.250
94.898
88.602
91.750
557.958
1890.924
754.690
18889.008
565.904
13280.836
ETHANOL:
LEVEL 1
0.734
0.754
0.711
0.740
28.112
37.623
13.722
30.396
93.755
84.245
89.000
92.114
82.386
87.250
94.958
88.542
91.750
550.319
1880.928
740.218
18962.625
876.121
13454.437
SPLASH INVESTMENT: YES
LEVEL 2
0.738
0.755
0.721
0.744
29.255
37.856
15.345
31.128
93.868
84.132
89.000
92.118
82.382
87.250
95.448
88.052
91.750
562.211
1873.368
650.830
19214.168
1914.786
13942.988
LEVEL 3
0.748
0.733
0.785
0.747
32.523
23.562
54.026
32.079
94.030
83.970
89.000
91.723
82.777
87.250
96.979
86.521
91.750
577.037
1865.976
634.125
19504.020
1778.390
14613.594
SWR-8701
4-8
Banner 6 Moore Management Science
-------
TABLE 4-2
MID-CONTINENT/ROCKIES/NORTHWEST MODEL RESULTS
(Page 4 of 4)
REGION 2
CASE DIFFERENCES
SUING CRUDE, MBPCD
NORMAL BUTANE, MBPCD
ISO BUTANE, MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KUH PCD
PROCESS INVESTMENTS, MMS
RELATIVE CASH FLOW, MSPCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SUING CRUDE, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/Bbl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KUH/Bbl
PROCESS INVESTMENTS, M$/Bbl
RELATIVE CASH FLOW, S/Bbl
CRUDE: $22 ETHANOL:
SUMMER LEVEL 1
40.026
42.356
9.598
-0.152
12.080
2.315
4.692
-2.267
1.725
10.999
1.512
-7.639
9.996
-14.472
73.617
310.217
173.601
0.019
0.021
-0.005
0.001
0.004
0.005
-0.007
0.036
0.150
0.084
SPLASH INVESTMENT: YES
LEVEL 2
37.305
22.447
0.725
0.114
15.469
1.747
3.541
-1.710
1.301
8.299
17.900
11.892
7.560
89.388
251.543
1038.665
-488.551
0.018
0.011
0.000
0.009
0.006
-0.004
0.043
0.122
0.505
0.238
LEVEL 3
33.289
0.000
32.245
0.114
0.930
1.703
3.453
1.668
1.270
8.094
7.765
14.826
7.392
-16.705
289.852
136.396
670.606
0.016
0.000
0.016
0.004
0.007
-0.004
-0.008
0.142
0.067
0.327
SWR-8701
Homer 6 Moore Management Science
4-9
-------
TABLE 4-3
GULF COAST MODEL RESULTS
(Page 1 of 4)
REGION 3
RAW MATERIAL PURCHASES, MBPCD
LOW SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR' CRUDES
SUING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
MIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, S/Bbl
SUING CRUDE
ETHANE
PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
CRUDE: $22
SUMMER
2736.000
230.000
756.000
1348.000
910.616
5980.616
350.000
85.000
54.893
5.986
82.488
63.000
206.000
39.922
6867.905
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
537.979
1463.125
857.153
274.650
3132.907
2097.277
316.930
1478.790
190.905
348.904
6867.905
ETHANOL: SPLASH INVESTMENT: TES
LEVEL 1
2736.000
230.000
756.000
1348.000
968.494
6038.494
350.000
71.552
44.704
5.986
31.140
63.000
206.000
39.798
6850.674
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
535.128
1455.370
852.609
273.193
3116.300
2097.277
316.930
1478.090
195.528
-353.451
6850.674
LEVEL 2
2736.000
230.000
756.000
1348.000
1007.363
6077.363
350.000
78.268
25.218
5.986
0.000
63.000
206.000
39.703
6845.538
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
532.976
1449.517
849.181
272.095
3103.769
2097.277
316.930
1488.362
199.482
360.282
6845.538
LEVEL 3
2736.000
230.000
756.000
1348.000
1047.757
6117.757
350.000
46.127
0.000
5.986
0.000
63.000
206.000
39.612
6828.482
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
530.878
1443.811
845.838
271.024
3091.551
2097.277
316.930
1492.944
199.297
369.517
6828.482
SWR-870T
Borm B Moore Management Science
4-10
-------
TABLE 4-3
GULF COAST MODEL RESULTS
(Page 2 of 4)
REGION 3
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X 3 160 -LEADED REGULAR
X a 160 -UNLEADED REGULAR
X 3 160 -UNLEADED PREMIUM
X 3 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X 3 210 -UNLEADED REGULAR
X 3 210 -UNLEADED PREMIUM
X 3 210 -TOTAL POOL
X a 230 -LEADED REGULAR
X 3 230 -UNLEADED REGULAR
X a 230 -UNLEADED PREMIUM
X a 230 -TOTAL POOL
X 3 330 -LEADED REGULAR
X a 330 -UNLEADED REGULAR
X 8 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
CRUDE: $22
SUMMER
10.920
10.920
10.920
10.920
127.700
128.194
134.999
130.036
35.034
33.610
30.815
33.071
59.000
59.512
46.789
55.813
64.148
66.020
59.141
63.736
90.792
90.035
97.105
92.175
ET HANOI: SPLASH INVESTMENT: YES
LEVEL 1
9.970
9.970
9.970
9.970
127.700
131.799
145.737
135.022
40.342
32.844
24.095
31.698
61.895
61.070
38.570
54.836
66.726
69.281
48.826
63.026
91.324
91.921
92.929
92.101
LEVEL 2
9.020
9.020
9.020
9.020
133.045
138.173
147.171
139.812
38.548
31.621
23.722
30.614
60.568
56.650
44.772
53.979
65.717
64.686
56.024
62.413
91.233
89.852
96.753
92.054
LEVEL 3
8.070
8.070
8.070
8.070
141.284
140.861
153.663
144.566
32.820
32.958
20.931
29.523
57.062
57.890
41.922
53.214
62.855
65.724
53.895
61.859
90.801
90.054
96.605
92.045
SWR-8701
Homer 6 Moore Management Science
4-11
-------
TABLE 4-3
GULF COAST MODEL RESULTS
(Page 3 of 4)
REGION 3
GASOLINE BLENDING DETAIL.contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
-------
TABLE 4-3
GULF COAST MODEL RESULTS
(Page 4 of 4)
REGION 3
CASE DIFFERENCES
SWING CRUDE, HBPCD
PROPANE, HBPCO
MIXED BUTANES, HBPCO
NORMAL BUTANE, MBPCD
ISO BUTANE, MBPCD-
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
"PROCESS INVESTMENTS, MM$
RELATIVE CASH FLOW, MSPCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SWING CRUDE, Bbl/Bbl
PROPANE, Bbl/Bbl
MIXED BUTANES, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/Bbl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KWH/Bbl
PROCESS INVESTMENTS, M$/Bbl
RELATIVE CASH FLOW, $/8bl
CRUDE: S22 ETHANOL:
SUMMER LEVEL 1
57.878
13.448
10.189
51.348
0.000
0.124
17.231
2.851
7.755
4.544
1.457
16.607
4.623
11.529
12.348
3.999
648.586
376.148
372.109
0.019
0.004
0.003
0.016
0.000
0.001
0.004
0.004
0.001
0.208
0.121
0.119
SPLASH INVESTMENT: YES
LEVEL 2
38.869
6.716
19.486
31.140
0.000
0.095
5.136
2.152
5.853
3.428
1.098
12.531
3.954
10.185
-9.324
10.388
612.438
417.974
556.844
0.013
0.002
0.006
0.010
0.000
0.001
0.003
0.003
0.003
0.197
0.135
0.179
LEVEL 3
40.394
-32.141
25.218
0.000
0.000
0.091
17.056
-2.098
5.706
3.343
1.071
12.218
0.185
13.171
9.072
54.434
828.594
486.634
626.707
0.013
-0.010
-0.008
0.000
0.000
-0.000
0.004
0.003
0.018
0.268
0.157
-0.203
SWR-8701
Homer B Moore Management Science
4-13
-------
TABLE 4-4
CALIFORNIA MODEL RESULTS
(Page 1 of 4)
REGION 4
RAW MATERIAL PURCHASES, MBPCD
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SUING CRUDE
SUBTOTAL CRUDES
ETHANE & PROPANE
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAU MATERIAL COSTS, $/Bbt
SUING CRUDE
PROPANE
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
- METHANOL (for MT8E)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
CRUDE: $22
SUMMER
253.000
213.000
581.000
99.000
713.068
1859.068
0.000
8.305
0.000
0.000
11.000
10.073
1888.446
20.950
16.050
16.090
19.150
24.520
16.380
3.500
154.346
477.005
303.649
42.600
977.600
552.282
220.000
147.994
121.370
130.800
1888.446
ETHANOL: SPLASH INVESTMENT: YES
LEVEL 1
253.000
213.000
581.000
99.000
717.-395
1863.395
0.000
8.355
0.000
0.000
11.000
9.992
1892.742
20.950
16.050
16.090
19.150
24.520
16.380
3.500
153.528
474.476
302.039
42.374
972.417
552.282
220.000
148.561
126.890
127.408
1892.742
LEVEL 2
253.000
213.000
581.000
99.000
732.266
1878.266
0.000
8.528
0.000
0.000
11.000
9.952
1907.746
20.950
16.050
16.090
19.150
24.520
16.380
3.500
152.911
472.568
300.824
42.204
968.507
552.282
220.000
149.761
140.589
123.393
1907.746
LEVEL 3
253.000
213.000
581.000
99.000
736.017
1882.017
0.000
8.571
0.000
0.000
11.000
9.865
1911.453
20.950
16.050
16.090
19.150
24.520
16.380
3.500
152.309
470.708
299.640
42.038
964.695
552.282
220.000
150.047
144.293
119.864
1911.453
SWR-8701
Banner 6 Moore Management Science
4-14
-------
TABLE 4-4
CALIFORNIA MODEL RESULTS
(Page 2 of 4)
< REGION 4
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP,psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, f -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
V/L TEMP, f -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X 3 160 -LEADED REGULAR
X a 160 -UNLEADED REGULAR
X 3 160 -UNLEADED PREMIUM
X 3 160 -TOTAL POOL
X a 210 -LEADED REGULAR
X a 210 -UNLEADED REGULAR
X a 210 -UNLEADED PREMIUM
X a 210 -TOTAL POOL
X a 230 -LEADED REGULAR
X 3 230 -UNLEADED REGULAR
X a 230 -UNLEADED PREMIUM
X a 230 -TOTAL POOL
X 3 330 -LEADED REGULAR
X 3 330 -UNLEADED REGULAR
X 3 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
CRUDE: $22
SUMMER
9.230
8.958
9.230
9.090
138.400
138.400
138.400
138.400
29.045
32.009
32.887
31.807
57.062
56.198
52.542
55.167
63.034
66.102
62.263
64.371
91.161
93.539
97.217
94.331
ETHANOL: SPLASH INVESTMENT: TES
LEVEL 1
8.430
8.430
8.430
8.430
140.419
142.797
138.400
140.999
28.872
29.198
37.471
31.798
60.242
54.263
54.876
55.434
66.571
64.813
64.140
64.884
92.710
93.823
97.363
94.777
LEVEL 2
7.630
7.630
7.630
7.630
143.387
147.851
141.259
145.010
28.183
26.931
38.372
30.803
61.796
52.764
54.816
54.894
68.429
63.781
64.125
64.649
93.646
93.951
97.369
94.997
LEVEL 3
6.820
6.820
6.820
6.820
148.118
144.186
156.443
148.757
24.935
36.916
21.796
30.116
62.211
57.366
46.315
54.613
70.356
65.224
61.142
64.752
94.795
95.423
95.389
95.310
SWR-8701
HomerE Moore Mar
mt Science
4-15
-------
TABLE 4-4
CALIFORNIA MODEL RESULTS
(Page 3 of 4)
REGION 4
GASOLINE BLENDING DETAIL, contd
SP GRAVITY' -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
(R+M)/2 OCTANE -LEAD REGULAR
RESEARCH OCTANE -UNLEADED REG
MOTOR OCTANE -UNLEADED REG
(R+M)/2 OCTANE -UNLEADED REG
RESEARCH OCTANE -PREMIUM
MOTOR OCTANE -PREMIUM
(R+M)/2 OCTANE -PREMIUM
MAJOR UTILITIES PURCHASED
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MM$
RELATIVE CASH FLOW, MJPCO
CRUDE: $22
SUMMER
0.754
0.740
0.775
0.753
34.339
26.233
47.089
34.241
93.986
84. OH
89.000
92.833
83.167
88.000
96.819
86.681
91.750
328.800
668.304
83.580
13093.500
399.015
16486.285
ETHANOL: SPLASH INVESTMENT: YES
LEVEL 1
0.752
1 0.746
0.770
0.754
33.051
28.834
44.343
34.520
94.290
83.710
89.000
92.934
83.066
88.000
96.667
86.833
91.750
333.925
664.776
68.127
13309.211
460.707
16518.051
LEVEL 2
0.752
0.751
0.770
0.757
32.741
30.656
44.068
35.296
94.466
83.534
89.000
93.000
83.000
88.000
96.725
86.775
91.750
339.109
662.088
1.975
13577.742
408.605
16641.480
LEVEL 3
0.751
0.761
0.759
0.759
30.152
38.661
33.852
35.732
94.500
83.500
89.000
93.000
83.000
88.000
96.895
86.605
91.750
349.248
659.484
0.000
13859.000
497.652
16819.441
SWR-8701
Banner B Moore Management Sdencs
4-16
-------
TABLE 4-4
CALIFORNIA MODEL RESULTS
(Page 4 of 4)
REGION 4
CASE DIFFERENCES
SUING CRUDE, MBPCD
NORMAL BUTANE, MBPCD
ISO BUTANE, MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MM$
RELATIVE CASH FLOW, MSPCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SUING CRUDE, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/Bbl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KUH/Bbl
PROCESS INVESTMENTS, M$/Bbl
RELATIVE CASH FLOW, S/Bbl
CRUDE: $22 ETHANOL:
SUMMER ' LEVEL 1
4.327
0.000
0.000
0.081
4.296
-0.818
2.529
1.610
0.226
5.183
5.520
5.125
3.528
15.453
215.711
61.692
31.766
0.004
0.000
0.000
0.006
0.005
0.004
0.016
0.222
0.063
0.033
SPLASH INVESTMENT: YES
LEVEL 2
14.871
0.000
0.000
-0.040
15.004
0.617
1.908
1.215
0.170
3.910
13.699
5.184
-2.688
-66.152
268.531
-52.102
-123.429
0.015
0.000
0.000
0.014
0.005
0.003
0.068
0.277
0.054
0.127
LEVEL 3
3.751
0.000
0.000
0.087
3.707
0.602
1.860
-1.184
0.166
3.812
3.704
10.139
2.604
1.975
281.258
89.047
. -177.961
0.004
0.000
0.000
0.004
0.011
-0.003
-0.002
0.292
0.092
-0.184
SWR-8701
Honner B Moore Management Science
4-17
-------
4.2
ALTERNATE CRUDE-COST CASES
Selected detail from results of Region 3 cases at
$17 per barrel and $27 per barrel are presented in Tables 4-5
and 4-6, respectively.
TABLE 4-5
GULF COAST MODEL RESULTS AT $17 PER BARREL
(Page 1 of 4)
REGION
3
CRUDE: S17 ET HANOI: SPLASH INVESTMENT: YES
RAW MATERIAL PURCHASES, MBPCD
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SUING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
MIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, S/Bbl
SWING CRUDE
ETHANE
PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
SUMMER
2682.000
249.000
728.000
1479.000
1032.773
6170.773
270.000
261.257
29.577
5.357
98.957
63.000
180.000
40.719
7119.640
17.940
6.160
10.650
13.698
13.070
14.640
16.320
12.600
1.790
561.790
1492.882
894.615
283.938
3233.225
2186.185
349.955
1517.235
195.431
-362.391
7119.640
LEVEL 1
2682.000
249.000
728.000
1479.000
1075.619
6213.619
270.000
277.435
0.000
5.357
56.794
63.000
180.000
40.590
7106.795
17.940
6.160
10.650
13.698
13.070
14.640
16.320
12.600
1.790
558.812
1484.969
889.873
282.434
3216.088
2186.185
349.955
1526.862
198.542
-370.837
7106.795
LEVEL 2
2682.000
249.000
728.000
1479.000
1139.788
6277.788
270.000
252.471
0.000
5.357
0.000
63.000
180.000
40.493
7089.109
17.940
6.160
10.650
13.698
13.070
14.640
16.320
12.600
1.790
556.565
1478.998
886.295
281.298
3203.156
2186.185
349.955
1520.829
202.038
-373.054
7089.109
LEVEL 3
2682.000
249.000
728.000
1479.000
1179.350
6317.350
270.000
197.466
0.000
5.357
0.000
63.000
180.000
40.399
7073.572
17.940
6.160
10.650
13.698
13.070
14.640
16.320
12.600
1.790
554.375
1473.175
882.805
280.192
3190.547
2186.185
349.955
1518.113
205.431
-376.659
7073.572
SWR-8701
Barer B Moore Man
4-18
-------
TABLE 4-5
LGULF COAST MODEL RESULTS AT $17 PER BARREL
(Page 2 of 4)
REGION
3
CRUDE: $17 ETHANOL: SPLASH INVESTMENT: YES
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP,psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, f -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X 3 160 -LEADED REGULAR
X 3 160 -UNLEADED REGULAR
X 3 160 -UNLEADED PREMIUM
X 3 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X a 210 -UNLEADED REGULAR
X 3 210 -UNLEADED PREMIUM
X a 210 -TOTAL POOL
X a 230 -LEADED REGULAR
X a 230 -UNLEADED REGULAR
X a 230 -UNLEADED PREMIUM
X a 230 -TOTAL POOL
X 3 330 -LEADED REGULAR
X a 330 -UNLEADED REGULAR
X 8 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
SUMMER
10.920
10.920
10.920
10.920
127.700
130.913
129.647
129.972
35.061
30.226
37.986
33.322
58.968
57.095
50.945
55.669
64.133
65.363
60.125
63.639
90.840
93.479
91.153
92.337
LEVEL 1
9.970
9.970
9.970
9.970
128.055
136.008
137.893
135.116
39.866
28.694
32.556
31.814
61.619
56.048
47.072
54.477
66.490
65.160
55.807
62.717
91.278
93.678
90.221
92.254
LEVEL 2
9.020
9.020
9.020
9.020
133.045
140.005
144.549
140.055
38.548
27.693
30.666
30.500
60.569
56.960
42.772
53.541
65.717
67.083
50.444
62.065
91.233
93.793
89.845
92.200
LEVEL 3
8.070
8.070
8.070
8.070
141.305
142.402
151.791
144.897
32.843
30.976
23.969
29.302
56.985
56.596
42.751
52.695
62.771
65.048
54.111
61.501
90.763
90.669
95.798
92.157
SWR-8701
BormefB Moore Mar
Hyemer
« Science
4-19
-------
TABLE 4-5
GULF COAST MODEL RESULTS AT $17 PER BARREL
(Page 3 of 4)
REGION 3
CRUDE: $17 ETHANOL:
GASOLINE BLENDING DETAIL, contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
(R+M)/2 OCTANE -LEAD REGULAR
RESEARCH OCTANE -UNLEADED REG
MOTOR OCTANE -UNLEADED REG
(R+M)/2 OCTANE -UNLEADED REG
RESEARCH OCTANE -PREMIUM
MOTOR OCTANE -PREMIUM
-------
TABLE 4-5
..GULF COAST MODEL RESULTS AT $ 17 PER BARREL
(Page 4 of 4)
CASE DIFFERENCES
SWING CRUDE, MBPCD
PROPANE, MBPCD
MIXED BUTANES, MBPCD
NORMAL BUTANE, MBPCD
ISO BUTANE, MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MM$
RELATIVE CASH FLOW, MSPCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SWING CRUDE, Bbl/Bbl
PROPANE, Bbl/Bbl
MIXED BUTANES, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, S/Bbt
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KWH/Bbl
PROCESS INVESTMENTS, M$/Bbl
RELATIVE CASH FLOW, S/Bbl
REGION
CRUDE: $17 ETHANOL:
SUMMER LEVEL 1
42.846
16.178
-29.577
-42.163
0.000
-0.129
-12.845
2.978
7.913
-4.742
-1.504
-17.137
3.111
11.493
-12.894
16.047
863.473
48.259
-402.937
0.013
0.005
-0.009
0.013
0.000
0.001
0.004
-0.004
0.005
0.268
0.015
-0.125
3
SPLASH INVESTMENT: YES
LEVEL 2
64.169
-24.964
0.000
-56.794
0.000
0.097
-17.686
-2.247
5.971
3.578
1.136
12.932
3.496
13.282
9.702
11.632
546.817
179.742
-566.581
0.020
-0.008
0.000
-0.018
0.000
0.001
0.004
-0.003
0.004
0.171
0.056
-0.177
LEVEL 3
39.562
-55.005
0.000
0.000
0.000
0.094
-15.537
2.190
5.823
3.490
-1.106
12.609
3.393
14.776
9.492
19.965
595.013
418.541
-608.311
0.012
-0.017
0.000
0.000
0.000
0.001
0.005
0.003
0.006
0.186
0.131
0.191
SWR-8701
Banner B Moore Management Science
4-21
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TABLE 4-6
GULF COAST MODEL RESULTS AT $27 PER BARREL
(Page 1 of 4)
REGION
CRUDE: $27 ETHANOL:
RAW MATERIAL PURCHASES, MBPCD
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SUING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
MIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, $/Bbl
SUING CRUDE
ETHANE
PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
SUMMER
2809.000
213.000
772.000
, 1228.000
835.185
5857.185
377.000
12.896
49.076
6.604
83.439
63.000
223.000
39.447
6711.647
28.410
10.880
17.470
21.282
20.890
21.870
26.000
17.220
2.940
523.623
1448.083
831 .487
269.103
3072.296
2038.117
327.910
1435.422
179.183
-341.281
6711.647
LEVEL 1
2809.000
213.000
772.000
1228.000
881.630
5903.630
377.000
15.087
81.445
6.604
30.236
63.000
223.000
39.325
6739.327
28.410
10.880
17.470
21.282
20.890
21.870
26.000
17.220
2.940
520.848
1440.407
827.080
267.677
3056.012
2038.117
327.910
1470.113
187.186
-340.011
6739.327
3
SPLASH INVESTMENT: YES
LEVEL 2
2809.000
213.000
772.000
1228.000
938.753
5960.753
377.000
10.829
5.798
6.604
0.000
63.000
223.000
39.232
6686.216
28.410
10.880
17.470
21.282
20.890
21.870
26.000
17.220
2.940
518.753
1434.615
823.753
266.601
3043.722
2038.117
327.910
1437.915
190.070
-351.518
6686.216
LEVEL 3
2809.000
213.000
772.000
1228.000
953.508
5975.508
377.000
9.732
0.000
6.604
0.000
63.000
223.000
39.143
6693.987
28.410
10.880
17.470
21.282
20.890
21.870
26.000
17.220
2.940
516.711
1428.968
820.511
265.552
3031.742
2038.117
327.910
1464.234
192.365
-360.381
6693.987
SWR-8701
Banner 8 Moore Management Science
4-22
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TABLE 4-6
GULF COAST MODEL RESULTS AT $27 PER BARREL
(Page 2 of 4)
- REGION
3
CRUDE: $27 ETHANOL: SPLASH INVESTMENT: YES
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
1 V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X a 160 -LEADED REGULAR
X 9 160 -UNLEADED REGULAR
X 3 160 -UNLEADED PREMIUM
X 3 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X 3 210 -UNLEADED REGULAR
X 3 210 -UNLEADED PREMIUM
X a 210 -TOTAL POOL
X a 230 -LEADED REGULAR
X a 230 -UNLEADED REGULAR
X 3 230 -UNLEADED PREMIUM
X a 230 -TOTAL POOL
X 3 330 -LEADED REGULAR
X 8 330 -UNLEADED REGULAR
X 3 330 -UNLEADED PREMIUM
X a 330 -TOTAL POOL
SUMMER
10.920
10.920
10.920
10.920
127.700
131.567
127.700
129.799
35.016
29.817
39.128
33.347
59.021
56.038
54.183
56.045
64.158
64.185
63.144
63.888
90.773
90.126
96.884
92.136
LEVEL 1
9.970
9.970
9.970
9.970
127.700
137.966
134.171
135.088
40.239
26.762
35.508
31.596
62.016
53.716
52.356
54.801
66.866
62.445
61.527
62.968
91 .393
90.065
96.305
92.050
LEVEL 2
9.020
9.020
9.020
9.020
133.014
142.301
139.051
139.749
38.520
26.755
32.966
30.575
60.674
52.663
53.003
54.173
65.825
61.694
61.698
62.425
91.274
90.517
95.189
91.962
LEVEL 3
8.070
8.070
8.070
8.070
141.530
141.161
152.246
144.336
32.215
31.984
23.924
29.764
57.194
58.330
41.734
53.474
63.062
66.362
53.111
62.062
90.950
90.569
95.565
92.038
SWR-8701
Banner B MOOT Management Science
4-23
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TABLE 4-6
GULF COAST MODEL RESULTS AT $27 PER BARREL
(Page 3 of 4)
REGION
CRUDE: S27 ETHANOL:
GASOLINE BLENDING DETAIL, contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
(R+M)/2 OCTANE -LEAD REGULAR
RESEARCH OCTANE -UNLEADED REG
MOTOR OCTANE -UNLEADED REG
SUMMER
0.743
0.733
0.761
0.742
31.107
24.820
42.112
30.781
93.755
84.245
89.000
92.144
82.356
87.250
96.511
86.989
91.750
1190.369
2267.244
2043.274
35833.128
2.572
-45143.646
LEVEL 1
0.735
0.739
0.767
0.746
28.405
26.678
43.749
31.772
93.771
84.229
89.000
92.250
82.250
87.250
96.779
86.721
91.750
1198.918
2255.232
2010.395
36129.486
1.999
45413.502
3
SPLASH INVESTMENT: YES
LEVEL 2
0.739
0.743
0.769
0.750
29.646
28.846
42.229
32.741
93.890
84.110
89.000
92.248
82.252
87.250
97.250
86.250
91.750
1211.564
2246.160
2027.971
36814.399
2.168
-45922.657
LEVEL 3
0.751
0.735
0.790
0.753
33.255
23.449
54.598
33.919
94.092
83.908
89.000
92.250
82.250
87.250
97.250
86.250
91.750
1224.187
2237.298
2069.026
37707.023
0.000
-46590.379
SWR-8701
Banner B Moore Management Science
4-24
-------
TABLE 4-6
GULF COAST MODEL RESULTS AT $27 PER BARREL
-. (Page 4 of 4)
CASE DIFFERENCES
SWING CRUDE, HBPCD
PROPANE, MBPCO
MIXED BUTANES, MBPCD
NORMAL BUTANE, MBPCO
ISO BUTANE, MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MMS
RELATIVE CASH FLOW, M$PCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SWING CRUDE, Bbl/Bbl
PROPANE, Bbl/Bbl
MIXED BUTANES, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/Bbt
TEL, GRAMS/Bbl
FUEL. MM BTU/Bbl
ELEC; UCITY, KWH/Bbl
PROCESS INVESTMENTS, MS/Bbl
RELATIVE CASH FLOW, S/Bbl
REGION
CRUDE: $27 ETHANOL:
SUMMER LEVEL 1
46.445
2.191
32.369
-53.203
0.000
-0.122
27.680
2.775
-7.676
-4.407
-1.426
-16.284
8.003
8.549
-12.012
-32.879
296.358
-0.573
-269.856
0.015
0.001
0.011
-0.017
0.000
0.003
0.003
-0.004
-0.011
0.097
0.000
-0.088
3
SPLASH INVESTMENT: TES
LEVEL 2
57.123
4.258
-75.647
30.236
0.000
0.093
53.111
-2.095
-5.792
-3.327
-1.076
12.290
2.884
12.646
9.072
17.576
684.913
0.169
-509.155
0.019
-0.001
-0.025
-0.010
0.000
0.001
0.004
-0.003
0.006
0.225
0.000
-0.167
LEVEL 3
14.755
1.097
5.798
0.000
0.000
0.089
7.771
2.042
-5.647
3.242
1.049
-11.980
2.295
12.623
-8.862
41.055
892.624
2.168
667.722
0.005
-0.000
0.002
0.000
0.000
0.001
0.004
0.003
0.014
0.294
0.001
0.220
SWR-8701
Homer B Moore Management Science
4-25
-------
4.3
NO-INVESTMENT CASES
^Selected detail from results for Region 3, excluding
process investment, are presented in Table 4-7.
TABLE 4-7
GULF COAST MODEL RESULTS WITHOUT INVESTMENT
(Page 1 of 4)
REGION
3
CRUDE: K2 ETHAMOL: SPLASH INVESTMENT: NO
RAW MA"RIAL PURCHASES, MBPCD
LOW SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SUING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
MIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, $/Bbl
SUING CRUDE
ETHANE
I PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
SUMMER
2736.000
230.000
756.000
1348.000
910.616
5980.616
350.000
85.000
54.893
5.986
82.488
63.000
206.000
39.922
6867.905
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
537.979
1463.125
857.153
274.650
3132.907
2097.277
316.930
1478.790
190.905
348.904
6867.905
LVEL 1
2736.000
230.000
756.000
1348.000
932.024
6002.024
350.000
33.176
87.493
5.986
127.000
63.000
206.000
39.798
6914.477
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
535.128
1455.370
852.609
273.193
3116.300
2097.277
316.930
U84.053
33.542
333.625
6914.477
LEVEL 2
2736.000
230.000
756.000
1348.000
1118.169
6188.169
350.000
0.000
68.311
5.986
126.798
63.000
206.000
39.703
7047.967
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
532.976
1449.517
849.181
272.095
3103.769
2097.277
316.930
1486.847
372.976
329.832
7047.967
LEVEL 3
2736.000
230.000
756.000
1348.000
1296.002
6366.002
350.000
0.000
138.196
5.986
52.350
63.000
206.000
39.612
7221.146
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
530.878
1443.811
845.838
271.024
3091.551
2097.277
316.930
1515.713
506.423
-306.748
7221.146
SWR-8701
Banner 6 Moore Management Science
4-26
-------
TABLE 4-7
GULF COAST MODEL RESULTS WITHOUT INVESTMENT
(Page 2 of 4)
REGION
3
CRUDE: $22 ET HANOI: SPLASH INVESTMENT: NO
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X 3 160 -LEADED REGULAR
X 3 160 -UNLEADED REGULAR
X a 160 -UNLEADED PREMIUM
X 3 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X 3 210 -UNLEADED REGULAR
X 3 210 -UNLEADED PREMIUM
X 3 210 -TOTAL POOL
X
X 3 230 -LEADED REGULAR
X 3 230 -UNLEADED REGULAR
X a 230 -UNLEADED PREMIUM
X a 230 -TOTAL POOL
X a 330 -LEADED REGULAR
X 8 330 -UNLEADED REGULAR
X 9 330 -UNLEADED PREMIUM
X a 330 -TOTAL POOL
SUMMER
10.920
10.920
10.920
10.920
127.700
128. 194
134.999
130.036
35.034
33.610
30.815
33.071
59.000
59.512
46.789
55.813
64.148
66.020
59.141
63.736
90.792
90.035
97.105
92.175
LEVEL 1
9.970
9.970
9.970
9.970
129.483
136.195
137.837
135.466
37.972
28.301
32.165
31.118
60.487
56.071
47.664
54.473
65.535
65.258
56.443
62.807
91.127
93.638
89.744
92.087
LEVEL 2
9.020
9.020
9.020
9.020
134.714
140.138
146.118
140.868
36.323
28.498
26.380
29.290
59.259
55.700
44.124
53.051
64.656
65.023
53.557
61.706
91.150
93.862
89.010
92.004
LEVEL 3
8.070
8.070
8.070
8.070
144.177
142.875
155.367
146.649
29.125
30.035
19.394
26.855
54.601
56.590
39.720
51.452
60.878
65.615
50.863
30.588
90.723
94.034
88.652
91.918
SWR-8701
Bomer B Moore Management Science
4-27
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TABLE 4-7
GULF COAST MODEL RESULTS WITHOUT INVESTMENT
(Page 3 of 4)
REGION 3
CRUDE: K2 ETHANOL:
GASOLINE BLENDING DETAIL.contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
1 RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
! (R+M)/2 OCTANE -LEAD REGULAR
RESEARCH OCTANE -UNLEADED REG
: MOTOR OCTANE -UNLEADED REG
i (R+M)/2 OCTANE -UNLEADED REG
1
RESEARCH OCTANE -PREMIUM
MOTOR OCTANE -PREMIUM
1
-------
TABLE 4-7
JGULF COAST MODEL RESULTS WITHOUT INVESTMENT
* (Page 4 of 4)
CASE DIFFERENCES
SUING CRUDE, MBPCO
PROPANE, MBPCO
MIXED BUTANES, MBPCD
, NORMAL BUTANE, MBPCD
; ISO BUTANE, MBPCD
ALCOHOLS, MBPCD
; TOTAL INPUT
I
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MM$
RELATIVE CASH FLOW, MSPCD
CASE DIFFERENCES NORMALIZED
. PER BARREL OF GASOLINE
SWING CRUDE, Bbl/Bbl
PROPANE, Bbl/Bbl
! MIXED BUTANES, Bbl/Bbl
: NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/Bbl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KWH/Bbl
PROCESS INVESTMENTS, M$/8bl
RELATIVE CASH FLOW, $/Bbl
REGION
CRUDE: $22 ETHANOL:
SUMMER LEVEL 1
21.408
-51.824
32.600
44.512
0.000
-0.124
46.572
-2.851
-7.755
4.544
-1.457
-16.607
42.637
13.716
-12.348
224.629
39.082
0.000
-766.070
0.007
0.017
0.010
0.014
0.000
0.014
0.004
-0.004
-0.072
0.013
0.000
-0.246
3
SPLASH INVESTMENT: NO
LEVEL 2
186.145
33.176
19.182
0.202
0.000
0.095
133.490
-2.152
-5.853
3.428
-1.098
12.531
139.434
6.779
-9.324
-798.525
379.450
0.000
1622.836
0.060
-0.011
-0.006
0.000
0.000
0.045
0.002
0.003
-0.257
0.122
0.000
-0.523
LEVEL 3
177.833
0.000
69.885
-74.448
0.000
0.091
173.179
2.098
-5.706
3.343
1.071
-12.218
133.447
16.498
9.072
755.057
447.609
0.000
1923.375
0.058
0.000
0.023
0.024
0.000
0.043
0.005
-0.003
-0.244
0.145
0.000
0.622
SWR-8701
Hormer 6 Moore Management Science
4-29
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4.4
CONTROLLED ETHANOL BLENDING CASES
^Selected detail from results for Region 3> with
tE
ethanol-oontaining blends required to meet restricted vapor
pressure, are presented in Table 4-8.
TABLE 4-8
GULF COAST MODEL RESULTS WITH
CONTROLLED ETHANOL BLENDING
_
REGION 3
CRUDE: $22 INVESTMENT: YES
RAW MATERIAL PURCHASES, MBPCO
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SUING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
MIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, S/Bbl
SWING CRUDE
ETHANE
PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR + ETHANOL
UNLEADED REGULAR + PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
ETHANOL:
LEVEL 1
2736.000
230.000
756.000
1348.000
958.872
6028.872
350.000
79.695
47.242
5.986
27.846
63.000
206.000
41.431
6850.072
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
535.128
179.705
2307.979
93.489
3116.301
2097.277
316.930
1480.758
193.084
354.278
6850.072
SPECIFICATION
LEVEL 2
2736.000
230.000
756.000
1348.000
993.989
6063.989
350.000
91.390
30.136
5.986
0.000
63.000
206.000
41.330
6851.831
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
532.976
178.982
2298.698
93.113
3103.769
2097.277
316.930
1494.873
197.502
358.520
6651.831
CONTROLLED
LEVEL 3
2736.000
230.000
756.000
1348.000
1031.602
6101.602
350.000
69.175
0.000
5.986
0.000
63.000
206.000
41.233
6836.996
23.170
8.780
14.270
17.888
17.360
18.680
21.180
15.120
2.410
530.878
178.277
2289.649
92.747
3091.551
2097.277
316.930
1500.877
198.159
367.798
6836.996
SWR-8701
Banner B Moore Management Science
4-30
-------
TABLE 4-8
GULF COAST MODEL RESULTS WITH
CONTROLLED ETHANOL BLENDING
(Page 2 of 4)
REGION 3
CRUDEj »22 INVESTMENT: YES
ETHANOL: SPECIF I CAT ION CONTROLLED
LEVEL 1 LEVEL 2 LEVEL 3
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REG + ETOH
RVP.psi -UNLEADED REG + PREM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REG+ETOH
V/L TEMP, F -UNLEADED REG+PREM
V/L TEMP, F -TOTAL POOL
X a 160 -LEADED REGULAR
X 3 160 -UNLEADED REG + ETOH
| % 5) 160 -UNLEADED REG + PREM
X 3 160 -TOTAL POOL
X 3 210 -LEADED REGULAR
X a 210 -UNLEADED REG I- ETOH
X a 210 -UNLEADED REG + PREM
X 3 210 -TOTAL POOL
X a 230 -LEADED REGULAR
X a 230 -UNLEADED REG + ETOH
X a 230 -UNLEADED REG + PREM
X 3 230 -TOTAL POOL
X 3 330 -LEADED REGULAR
X 8 330 -UNLEADED REG + ETOH
X 3 330 -UNLEADED REG + PREM
X 8 330 -TOTAL POOL
9.970
9.970
9.970
9.970
127.700
127.700
136.240
134.221
37.009
45.911
30.724
32.740
65.816
51.433
53.117
55.265
70.020
54.899
62.297
63.224
92.294
82.762
92.810
92.122
9.020
9.020
9.020
9.020
139.225
127.700
139.733
138.928
26.987
46.380
31.609
31.669
59.629
59.125
52.994
54.533
64.852
66.629
61.908
62.710
91.382
89.666
92.443
92.090
8.070
8.070
8.070
8.070
145.330
127.700
144.160
143.388
25.208
46.380
31.060
30.934
56.496
67.369
52.364
53.988
62.235
71.603
61.632
62.332
90.719
91.880
92.429
92.093
SWR-8701
Banner B Moore Management Science
4-31
-------
TABLE 4-8
GULF COAST MODEL RESULTS WITH
CONTROLLED ETHANOL BLENDING
(Page 3 of 4)
REGION 3
CHUOE: .$22 INVESTMENT: YES
GASOLINE BLENDING DETAIL, contd
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REG+ETOH
SP GRAVITY -UNLEADED REG+PREM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REG+ETOH
X AROMATICS -UNLEADED REG+PREM
X AROMATICS -TOTAL POOL
RESEARCH OCTANE -LEAD REGULAR
MOTOR OCTANE -LEAD REGULAR
(R+M)/2 OCTANE -LEAD REGULAR
RESEARCH OCT -UNLEADED REG+ETOH
MOTOR OCT-UNLEADED REG+ETOH
(R+MJ/2 OCT-UNLEADED REG+ETOH
RESEARCH OCT-UNLEADED REG+PREM
MOTOR OCT-UNLEADED REG+PREM
(R+M)/2 OCT-UNLEADED REG+PREM
MAJOR UTILITIES PURCHASED ,
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MM8TU PCD
ELECTRICITY, M KUH PCD
PROCESS INVESTMENTS, MM$
tELATIVE CASH FLOW, MSPCD
ETHANOL:
LEVEL 1
0.740
0.755
0.747
0.747
31.552
32.225
31.404
31.479
93.657
84.343
89.000
92.850
82.250
87.550
94.018
83.802
88.910
1213.740
2317.056
1989.213
36965.027
289.073
40162.309
SPECIFICATION
LEVEL 2
0.758
0.738
0.749
0.750
37.378
19.794
32.329
32.477
93.902
84.098
89.000
92.250
82.250
87.250
94.100
83.720
88.910
1222.643
2307.732
1989.125
37425.707
674.284
-40734.855 -
CONTROLLED
LEVEL 3
0.762
0.755
0.752
0.754
37.145
31.052
33.068
33.670
94.130
83.870
89.000
92.956
82.250
87.603
94.100
83.720
88.910
1234.017
2298.660
2036.949
38223.762
1183.611
41367.918
SWR-8701
Banner B Moore Management Science
4-32
-------
TABLE 4-8
GULF COAST MODEL RESULTS WITH
CONTROLLED ETHANOL BLENDING
(Page 4 of 4)
REGION 3
CRUDE: $22 INVESTMENT: YES
CASE DIFFERENCES
SUING CRUDE, MBPCD
PROPANE, MBPCD
MIXED BUTANES, MBPCD
NORMAL BUTANE, HBPCD
TSO BUTANE, MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, M$PCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KUH PCD
PROCESS INVESTMENTS, MMS
RELATIVE CASH FLOW, MSP CD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SWING CRUDE, Bbl/Bbl
PROPANE, Bbl/Bbl
MIXED BUTANES, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/8bl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KWH/Bbl
PROCESS INVESTMENTS, NS/Bbl
RELATIVE CASH FLOW, S/Bbl
ETHANOL:SPECIFICATION
LEVEL 1 LEVEL 2
_
35.117
11.695
-17.106
27.846
0.000
-0.101
1.759
-2.152
-0.723
-9.281
-0.376
12.532
4. 418
8.903
-9.324
-0.088
460.680
385.211
572.546
0.011
0.004
-0.006
-0.009
0.000
0.001
0.003
0.003
0.000
0.148
0.124
0.184
CONTROLLED
LEVEL 3
37.613
22.215
-30.136
0.000
0.000
0.097
14.835
2.098
0.705
9.049
-0.366
-12.218
0.657
11.374
-9.072
47.824
798.055
509.327
-633.063
0.012
-0.007
-0.010
0.000
0.000
0.000
0.004
0.003
0.015
0.258
0.165
0.205
SWR-8701
Bam 6 Moore Management Science
4-33
-------
4.5
BUTANE PRICE CASES
Selected detail from three cases with varying butane
prices are presented in Table 4-9. It should be remembered,
in reviewing these results, that the RVP control employed is
intermediate between the second and third levels defined for
this study.
TABLE 4-9
GULF COAST MODEL RESULTS AT
VARYING
BUTANE PRICES
(Pape 1 of 3)
CRUDE: (22
: RAW MATERIAL PURCHASES, M8PCD
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SWING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
NIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, S/Bbl
SWING CRUDE
ETHANE
PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
SELECTED PRODUCT SALES, MBPCD
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS & ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
ETHANOL: SPLASH
75/25
2736.000
230.000
756.000
1348.000
970.159
6040.159
332.000
22.113
10.989
5.986
127.000
63.000
206.000
40.419
6847.666
23.170
8.780
14.270
17.888
15.440
17.240
21.180
14.064
2.410
532.062
1447.030
847.724
271 .628
3098.444
2097.277
316.930
1497.465
200.704
-363.154
6847.666
INVESTMENT:
SO/SO
2736.000
230.000
756.000
1348.000
970.164
6040.164
332.000
22.117
10.984
5.986
127.000
63.000
206.000
40.426
6847.677
23.170
8.780
14.270
17.888
13.520
15.980
21.180
14.064
2.410
532.062
1447.030
847.724
271.628
3098.444
2097.277
316.930
1497.484
200.704
363.162
6847.677
YES
25/75
2736.000
230.000
756.000
1348.000
970.164
6040.164
332.000
22.117
10.985
5.986
127.000
63.000
206.000
40.426
6847.678
23.170
8.780
14.270
17.888
11.600
14.960
21.180
15.088
2.410
532.062
1447.030
847.724
271.628
3098.444
2097.277
316.930
1497.487
200.703
363.163
6847.678
SWR-8701
Bonner 6 Moore Management Science
4-33
-------
TABLE 4-9
GULF COAST MODEL RESULTS AT
VARYING BUTANE PRICES
(Page 2 of 3)
CRUDE: $22
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
RVP.psi -UNLEADED PREMIUM
RVP.psi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, f -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X a 160 -LEADED REGULAR
X 9 160 -UNLEADED REGULAR
X 8 160 -UNLEADED PREMIUM
X 8 160 -TOTAL POOL
X 8 210 -LEADED REGULAR
X 8 210 -UNLEADED REGULAR
X 8 210 -UNLEADED PREMIUM
X 8 210 -TOTAL POOL
X 8 230 -LEADED REGULAR
X 8 230 -UNLEADED REGULAR
X 3 230 -UNLEADED PREMIUM
X 3 230 -TOTAL POOL
X 8 330 -LEADED REGULAR
X 8 330 -UNLEADED REGULAR
X 8 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
SP GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SP GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X AROMATICS -UNLEADED PREMIUM
X AROMATICS -TOTAL POOL
ETHANOL: SPLASH
75/25
8.566
8.546
8.546
8.546
118.225
114.591
106.962
113.074
35.695
31.112
24.102
29.940
58.776
55.618
45.916
53.429
64.244
63.758
57.338
62.024
90.998
89.969
96.579
92.026
0.745
0.736
0.786
0.752
31.421
24.789
51.060
33.418
INVESTMENT
50/50
8.546
8.546
8.546
8.546
118.225
114.588
106.967
113.075
35.695
31.110
24.105
29.940
58.777
55.614
45.924
53.429
64.244
63.754
57.346
62.024
90.998
89.969
96.579
92.026
0.745
0.736
0.786
0.752
31.419
24.797
51.045
33.418
: YES
25/75
8.546
8.546
8.546
8.546
118.225
114.588
106.967
113.075
35.695
31.110
24.105
29.940
58.777
55.614
45.924
53.429
64.244
63.754
57.346
62.024
90.998
89.969
96.579
92.026
0.745
0.736
0.786
0.752
31.419
24.797
51.045
33.418
SWR-8701
Bonrar B Moore Management Bctenra
4-34
-------
TABLE 4-9
GULF COAST MODEL RESULTS AT
VARYING BUTANE PRICES
(Page 3 of 3)
CRUDE: $22
GASOLINE BLENDING DETAIL (cont.)
RESEARCH OCTANE-LEADED REGULAR
MOTOR OCTANE-LEADED REGULAR
/2 OCTANE-LEADED REGULAR
RESEARCH OCT-UNLEADED REGULAR
MOTOR OCT-UNLEADED REGULAR
-------
4.6
INCREASED BUNKER FUEL SALES CASES
Selected results from two cases with increased
bunker fuel demand are presented in Table 4-10. Except for
higher bunker fuel output, these two employ the same premises
and conditions imposed on the corresponding Base Case and
Second-RVP-Control-Level case reported in Section 4.1, Table
4-3.
TABLE 4-10
GULF COAST MODEL WITH
INCREASED BUNKER FUEL SALES
CRUDE: $22 ETNANOL: SPLASH INVESTMENT: YES
RAW MATERIAL PURCHASES, MBPCO
LOU SULFUR CRUDES
MEDIUM SULFUR CRUDES
INTERMEDIATE SULFUR CRUDES
HIGH SULFUR CRUDES
SWING CRUDE
SUBTOTAL CRUDES
ETHANE
PROPANE
MIXED BUTANES
NORTH SLOPE BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
ALCOHOLS
TOTAL INPUT
RAW MATERIAL COSTS, $/Bbl
SWING CRUDE
ETHANE
PROPANE
MIXED BUTANES
NORMAL BUTANE
ISO BUTANE
NATURAL GASOLINE
METHANOL (for MTBE)
REFINERY FUEL, S/MMBTU
BASE +
msasssss
2736.000
230.000
756.000
1348.000
922.634
5992.634
332.000
105.270
54.320
5.986
83.263
63.000
206.000
39.922
6882.395
23.170
8.780
14.270
17.888
17.360
18.680
21.180
14.852
2.410
LEVEL 2+
sam««a*
2736.000
230.000
756.000
1348.000
1024.373
6094.373
332.000
79.535
36.492
5.986
0.000
63.000
206.000
39.703
6857.089
23.170
8.780
14.270
17.888
17.360
18.680
21.180
14.787
2.410
SWR-8701
Bonner g Moore Management Bctenca
4-36
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TABLE 4-10
GULF COAST MODEL WITH
INCREASED BUNKER FUEL SALES
(Page 2 of 4)
OWE: S22 ETHANOL: SPLASH INVESTMENT: TtS
SELECTED PRODUCT SALES, M8PCO
LEADED REGULAR
UNLEADED REGULAR
UNLEADED PREMIUM
ALCOHOL BLENDS
SUBTOTAL GASOLINES
DISTILLATES
FUEL OILS t ASPHALT
OTHER SALEABLE PRODUCTS
REFINERY FUEL
VOLUME LOSS
TOTAL OUTPUT
GASOLINE BLENDING DETAIL
RVP.psi -LEADED REGULAR
RVP.psi -UNLEADED REGULAR
VP.psi -UNLEADED PREMIUM
IVP.pSi -TOTAL POOL
V/L TEMP, F -LEADED REGULAR
V/L TEMP, F -UNLEADED REGULAR
V/L TEMP, F -UNLEADED PREMIUM
V/L TEMP, F -TOTAL POOL
X a 160 -LEADED REGULAR
% » 160 -UNLEADED REGULAR
X a 160 -UNLEADED PREMIUM
X a 160 -TOTAL POOL
X 8 210 -LEADED REGULAR
X 3 210 -UNLEADED REGULAR
X 8 210 -UNLEADED PREMIUM
X a 210 -TOTAL POOL
X 8 230 -LEADED REGULAR
X a 230 -UNLEADED REGULAR
X 8 230 -UNLEADED PREMIUM
X 3 230 -TOTAL POOL
X 8 330 -LEADED REGULAR
X 8 330 -UNLEADED REGULAR
X 8 330 -UNLEADED PREMIUM
X 8 330 -TOTAL POOL
» GRAVITY -LEADED REGULAR
SP GRAVITY -UNLEADED REGULAR
SP GRAVITY -UNLEADED PREMIUM
SF GRAVITY -TOTAL POOL
X AROMATICS -LEADED REGULAR
X AROMATICS -UNLEADED REGULAR
X ARONATICS -UNLEADED MEDIUM
X AROMATICS -TOTAL POOL
537.979
1463.125
857.153
274.650
3132.907
2097.277
331 .930
U77.177
189.710
346.606
6882.395
10.919
10.919
10.919
10.919
127.700
126.355
121.939
125.342
35.034
34.380
29.326
33.063
59.000
56.604
52.161
55.771
64.148
62.532
65.620
63.695
90.791
89.887
97.387
92.174
0.743
0.741
0.748
0.743
31.103
30.597
31.641
30.983
532.976
1449.517
849.181
272.095
3103.769
2097.277
331.930
1479.500
199.654
355.041
6857.089
9.020
9.020
9.020
9.020
122.355
117.021
108.260
115.489
38.548
31.536
23.409
30.480
60.568
56.267
45.233
53.904
65.717
64.482
56.225
62.361
91. 233
90.005
96.391
92.035
0.739
0.733
0.789
0.750
29.699
23.678
S2.829
33.015
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TABLE 4-10
GULF COAST MODEL WITH
INCREASED BUNKER FUEL SALES
(Page 3 of 4)
CRUDE: $22 ETHANOL: SPLASH INVESTMENT: YES
GASOLINE BLENDING DETAIL (cont.)
RESEARCH OCTANE -LEADED REGULAR
MOTOR OCTANE -LEADED REGULAR
(R+M)/2 OCTANE-LEADED REGULAR
RESEARCH OCT-UNLEADED REGULAR
MOTOR OCT-UNLEADED REGULAR
-------
TABLE 4-10
GULF COAST MODEL WITH
INCREASED BUNKER FUEL SALES
(Page 4 of 4)
CRUDE: $22 ETHANOL: SPLASH
CASE DIFFERENCES
SWING CRUDE, MBPCD
PROPANE, MBPCD
MIXED BUTANES, MBPCD
NORMAL BUTANE, MBPCD
ISO BUTANE. MBPCD
ALCOHOLS, MBPCD
TOTAL INPUT
LEADED REGULAR, MBPCD
UNLEADED REGULAR, MBPCD
UNLEADED PREMIUM, MBPCD
ALCOHOL BLENDS, MBPCD
SUBTOTAL GASOLINES
REFINERY FUEL, MBPCD
CATALYST/CHEMICALS, MSPCD
TEL, M GRAMS PCD
FUEL, M MMBTU PCD
ELECTRICITY, M KWH PCD
PROCESS INVESTMENTS, MMS
RELATIVE CASH FLOW, MSPCD
CASE DIFFERENCES NORMALIZED
PER BARREL OF GASOLINE
SUING CRUDE, Bbl/Bbl
PROPANE, Bbl/Bbl
MIXED BUTANES, Bbl/Bbl
NORMAL BUTANE, Bbl/Bbl
ISO BUTANE, Bbl/Bbl
REFINERY FUEL, Bbl/Bbl
CATALYST/CHEMICALS, $/Bbl
TEL, GRAMS/Bbl
FUEL, MM BTU/Bbl
ELECTRICITY, KUH/Bbl
PROCESS INVESTMENTS, MS/Bbl
RELATIVE CASH FLOW, S/Bbl
INVESTMENT: YES
101.739
25.735
-17.828
83.263
0.000
-0.219
25.306
5.003
13.608
7.972
2.555
29.138
9.944
21.945
-21.672
-12.021
1113.785
799.524
-914.196
0.033
-0.008
0.006
-0.027
0.000
0.003
0.007
-0.007
0.004
0.359
0.258
0.295
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4.7 VARIABLE-VOLUME GASOLINE ADJUSTMENTS
^Classical methods of evaluating product quality
changes In refinery economics analyses avoid the problem of
variable product volume by taking any necessary steps to hold
the subject product's volume constant while varying its
quality. This was done in the prior study by fixing gasoline
output at a constant volume for all RVP levels. This study,
in recognizing mileage and evaporative loss effects of RVP
changes, involves changes in gasoline output from RVP level
to RVP level.
Assessing the effect of this variation in refinery
output requires placing a value on the changes in gasoline
sales (at the refinery gate). Decreased gasoline output at
reduced RVP, thus, represents a loss in sales revenue to the
refining industry. Cash flow changes between cases account
for the reduction in raw material allowed by decreased gaso-
line output and for operating cost changes, but not for
losses in revenue*. Therefore, some estimate of net income
loss must be added to control cost estimates. Furthermore,
no attempt has been made in this study to determine or define
how RVP-control costs would be borne. Results show only how
they would be incurred.
To resolve this matter, an estimate of net income
loss was made by applying an estimated refinery margin for
gasoline to the pool-average incremental gasoline cost times
the volume change associated with each reduction in RVP.
Gasoline margin used for this purpose is 5.6 percent. Pool-
average incremental gasoline cost, volume changes and esti-
mated net income losses for all subject cases are summarized
in Table 4-11.
*AH fixed-demand products were modeled without net-back
prices (none is required). Only by-products, with variable
were given net-back prices.
SWR-8701 Bonnet 6 Moore Management Science 4-39
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TABLE 4-11
NET INCOME-LOSS ESTIMATES
CRUDE
COST.I/BBL
22
22
22
22
22
22
22
22
22
22
22
22
17
17
17
27
27
-27
22
22
22
22
22
REGION
1
1
1
2
2
2
3
3
3
4
4
4
3
3
3
3
3
3
3*
3
3
3"
3
RVP
LEVEL
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
1
2
3
2
3
TOTAL GASO.
MBPCD
645.521
642.909
640.378
2064.172
2055.871
2047.778
3116.298
3103.765
3091.547
972.417
968.507
964.695
3216.084
3203.153
3190.543
3056.008
3043.718
3031.736
3116.298
3103.765
3091.547
3103.765
3091.547
POOL-AVE.
INC. COST
I/BBL
26.97
29.69
30.88
29.48
29.87
30.46
27.67
28.24
28.28
25.05
25.26
25.72
21.60
22.29
22.88
30.27
31.08
30.59
37.30
11.93
43.22
27.69
28.05
GASOLINE
CHANGE
MBPCD
3.123
2.612
2.531
10.999
8.301
8.093
16.604
12.533
.12.218
5.183
3.910
3.812
17.138
12.931
12.610
16.285
12.290
11.982
16.604
12.533
12.218
12.533
12.217
INCOME
M$PD
5.170
4.311
1.377
18.158
13.885
13.805
25.728
19.280
19.319
7.271
5.531
5.191
20.731
16.141
16.157
27.61
21.390
20.526
31.682
29.128
29.571
19.131
19.191
LOSS
$/BBL
0.008
0.007
0.007
0.009
0.007
0.007
0.008
0.006
0.006
0.007
0.006
0.006
0.006
0.005
0.005
0.009
0.007
0.007
0.011
0.009
0.010
0.006
0.006
Without process investment
With ethanol-containing
blends controlled
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4 . 8 NGL SECTOR COST IMPACT
suppliers will be forced to find alternative
markets for butane displaced from refinery purchases by vola-
tility reduction. Analysis indicates that the volumes of
normal butane released by the refining sector are so large
that at least a portion of the sales will be into fuel
markets in competition with natural gas. This will effec-
tively set the price of all normal butane at fuel value since
a two-tiered pricing system cannot exist. Iso-butane prices
will also be impacted since iso-butane and normal butane pri-
ces are related through i somer izat ion economics.
4.8.1 Butane Markets
Butanes are used in several applications other than
refinery gasoline production and ethylene feedstocks. These
applications include:
Feedstock for maleic anhydride and acetic acid,
Aerosol propellent, and
Fuel competitive with LPG or Natural Gas
Butane can be also dehydrogenated to butylene and
used in a number of chemical applications. Iso-butane is
used as a feedstock for propylene oxide and as an aerosol
propellant.
Our forecast does not require that model results
meet a fuel demand for butanes. The model is not, however,
required to purchase all of the projected available domestic
production. The model may also utilize butane as a
refinery/petrochemical fuel. For 1990, we project the non-
olefin-feedstock petrochemical/aerosol demands for butanes as
shown in Table 4-12.
SWR-8701 Burner 8 Moore Management Science 4-41
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TABLE 4-12
BUTANES REQUIRED AS PETROCHEMICAL
FEEDSTOCKS IN 1990
(Other than olefin feedstocks)
Normal-Butane Demands BPD
Acet ic Acid 5,000
Maleic Anhydride 7,100
Aerosol/Other 900
Subtotal 13,000
Iso-butane Demands
Propylene Oxide 22,000
Aerosol/Other 1,OOP
23,000
Acetic acid and a variety of coproducts can be produced by
the liquid phase oxidation of butane. Celanese, currently
has the only butane-based acetic acid plant, a 550MVI pounds
per year unit at Pampa, Tex. Union Carbide also has a
butane-based unit at Brownsville, Tx. but this facility has
been shutdown for several years and is believed to be
in operable.
The Celanese plant represents about 1896 of U.S. ace-
tic acid capacity. The remainder of the industry uses a
methanol-based process that is economically superior to
butane oxidation. Furthermore, the methanol route is more
selective so it avoids the problems of marketing the large
amount of coproducts produced with butane oxidation.
Inexpensive butane may prolong the life of the Celanese faci-
SWR-8701 Bonner B Moore Management Science 4.42
-------
lity, but it is unlikely to generate any new butane-based
faci1i t ies.
In contrast to acetic acid, normal-butane-based
maleic anhydride processes have completely supplanted benzene
technology in recent years. Currently, maleic anhydride is
produced at the following locations:
U.S. MALEIC ANHYDRIDE
FACILITIES
Producer
Amoco, Juliet, 111.
Ashland, Neal, W. Va.
Denka, Houston, Tx.
Monsanto, Pensacola, Fla,
Monsanto, St. Louis, Mo.
USS, Neville Island, Pa.
Capaci ty
(MM Ibs/Yr)
60
60
65
170
110
55
505
This capacity should be sufficient through the
mid-1990s, so normal-butane consumption is expected to grow
in line with maleic anhydride demand.
ARCO Chemical produces propylene oxide and tertiary
butyl alcohol by oxidation of iso-butane followed by reaction
with propylene. The only other propylene oxide producer is
Dow via a chlorohydrin-based process. Dow's process is
believed to be economically inferior to ARCO's, so new plants
SWR-8701
Bonner B Moore Management Science
4-43
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will employ ARCO's technology. However, new plants will not
be required until sometime after 1990 and Dow seems unlikely
to shutdown their existing, fully depreciated plants, in the
near future regardless of iso-butane prices.
Because of chemical inertness and high vapor
pressure, high purity butanes are used as aerosol pro-
pellants. Iso-butane is the predominant product although
normal-butane and propane are also used. Small volumes of
butanes are also used as a solvent in polymer processing.
In addition to these current uses, butanes can be
dehydrogenated to butylenes or to butadiene in the case of
normal-butane. These olefins can be used for derivatives
such as methyl ethyl ketone, secondary butanol, MTBE and
polybutenes. Of these products, only MTBE has the potential
for growth under RVP restrictions, because of its use as a
gasoline octane enhancer. These potential applications might
consume a few thousand barrels per day of butane but they
cannot absorb all of the product displaced from refineries.
In summary, the chemical markets for butanes, out-
side of olefin feedstocks, are limited. Lower prices are not
likely to result in any major increase in these markets by
1990, although longer term growth would be positively
impacted. Even so, these demand growths would have a small
effect on butane surpluses.
4.8.2 Butane Storage
Our analysis of the impact of reduced gasoline vapor
pressure impacts on the NGL industry assumes that a signifi-
cant portion of the normal-butane displaced from the refining
SWR-8701 4-44
Bonner B Moore Management Science
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industry will be burned as boiler fuel at a distressed price.
An alternative to boiler fuel use is to store the normal-butane
during the summer period and use the stored material during
the winter. Underground storage capacity for normal-butane
is summarized in Table 4-13.
TABLE 4-13
NORMAL-BUTANE UNDERGROUND STORAGE CAPACITY
(M bbls)
REGION
U.
1
2
3
4
S.
TOTAL
825
15,644
47,448
0
63,917
MERCHANT
0
12,648
38,225
0
50,873
Source: "North American Storage Capacity for Light
Hydrocarbons and U.S. LP-Gas Import Terminals,
1985", Gas Processors Assoc. and Resource Planning
Consultants
Of the total capacity of 63.9 million barrels, 50.9
million barrels is primarily for merchant use and 13.0
million barrels is devoted primarily to servicing internal
requirements - usually for an adjacent refinery.
SWR-8701
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RVP reduction in the range studied would add 18 to
31 million barrels to normal-butane inventories which have a
current summer peak of 20 to 30 million barrels. This indi-
cates that RVP control could roughly double "normal" inven-
tories. By historical standards, "full" storage is only
50-60% of capacity because of well-pressure buildup, lack of
storage for displaced brine, logistical problems, and other
factors. Physical limitations and market risks associated
with storage of such large volumes make it unlikely that
storage will be adopted as the industry solution for the
displaced butane.
Nevertheless, NGL producers and refiners that have
access to storage and are willing to assume the market risks
might choose summer-to-winter storage. The analysis pre-
sented here is still valid so long as an incremental portion
of the domestic supply moves into fuel, since this latter
action will set the market price. If large volumes of butane
are stored, it will negatively impact the winter price of
butane and further increase the NGL-industry cost effects of
RVP control.
4.8.3 Natural Gas Processing Economics
Lower butane prices resulting from RVP control will
adversely impact the economics of gas processing. Economics
for a 50 MMcfpd cryogenic expander plant located in West
Texas are presented in Table 4-14. These economics show the
plant to approximately break even (margin - 0.2$/gal) with
summertime prices and to realize an annual margin of
2.08$/gal. This annual margin is not likely to support rein-
vestment. Furthermore, margins could be lower for older,
less efficient plants, those in remote areas, and those pro-
cessing dry gas.
Bonner B Moore Management Science 4-46
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TABLE 4-14
GAS PROCESSING ECONOMICS
(Sheet 1 of 3)
BASES
West Texas Location
50 MM cfpd Cryogenic Turbo expander Plant
2.13 Gal/M Gas Processed
Operating Rate = 90% of Capacity
Plant Investment = $12.91 MM (1985$)
Product Mix:
Liquid Volume Percent
Ethane
Propane
N Butane
Isobutane
N. Gasoline
44.6
21.8
8.9
7.3
17.4
100.0
Crude Oi1 = $22/bbl
COST OF PRODUCTION
Uni ts/gal
Product
Cost/Uni t
Product Cost
(*/gal)
Raw Ma t e r i a 1s
Gas Shrinkage
Other
86.8 MBtu $2.00/MMBtu
17.36
0.09
UTILITIES
Extraction Fuel
Electr ici ty
Cool ing Water
8.16 MBtu
0.072 kwh
10.01 gal
2.00/MMBtu
0.05/kwh
0.168/M gal
1.63
0.36
0.17
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TABLE 4-14
GAS PROCESSING ECONOMICS
(Sheet 2 of 3)
Units/gal
Product
Cost/Unit
Product Cost
(*/gal)
TRANSPORTATION & FRACTIONATION
Subtotal Variable Cost
3.50
23.11
Labor
Operat ing
Direct Overhead
2 Men/Shi ft
50% of Labor
$14.16/hr
0.71
0.36
Other Costs
Maintenance 2.5% of Inv,
Taxes <5c Insurance 1.5% of Inv,
General Overhead 65% of L&M
0.93
0.55
1.06
Total Cost
26.72
ECONOMIC ANALYSIS
Composite Product Price - Summer
Gross Profit Margin - Summer
26.50
(0.20)
Composite Product Price - Annual
Gross Profit Margin - Annual
28.80
2.08
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TABLE 4-14
GAS PROCESSING ECONOMICS
(Sheet 3 of 3)
Composite Product Prices
Prices, */gal
Composite Price
«/gal
Component
Ethane
Propane
n-Butane
i -Butane
Nat. Gasoline
Compos i te
Gal/gal
0.446
0.218
0.089
0.073
0.174
1.000
Sunnier
15.3
34.0
24.8
30.8
45.4
Winter
15.3
34.0
41.3
55.3
48.7
Annual
15.3
34.0
34.4
45.1
47.3
Sunnier
6.8
7.4
2.2
2.2
7.9
26.5
Annual
6.8
7.4
3.1
3.3
8.2
28.8
4.8.4
Industry Cost Impact
Table 4-15 presents an example calculation of the
NGL costs. In these cases n-butane prices are at the
regional fuel value which varies as follows:
Re g i o n
Fuel Value w/ $22 Crude
$/MMBtu
1
2
3
4
3.60
2.90
2.41
3.50
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Iso-butane price was set at 6
-------
Cfl
3
00
TABLE 4-15
NGL SECTOR COSTS
($22 Crude - 1st Reduction)
(Page 1 of 2)
i
en
PRODUCT
Region 1
Ethane
Propane
N-Butane
Iso-Butane
Natural Gasoline
Region 2
Ethane
Propane
N-Butane
Iso-Butane
Natural Gasoline
(a) Negative numbers
(b) Negative numbers
BASE
9.62
12.76
19.27
20.63
20.45
7.75
10.28
17.83
21.03
17.09
Indicate
Indicate
PRICES ($/Bbl)
1ST RED
9.62
12.76
15.56
20.63
20.88
7.75
10.28
12.54
15.06
19.99
DIFF
_
3.71 /
-
(0.43)
Subtotal
_
5.29
5.97
(2.90)
Subtotal
a cost decrease, I.e.
cost decreases
GAS PLANT
PRODUCTION
(BPD)
12,000
13,000
5,000
3,000
8,000
Region 1
129,000
157,000
54,000
26,000
76,000
Region 2
NGL NGL
INDUSTRY REFINING
COSTS (a) COSTS (b)
U/DAY) (t/DAY)
_
-
18,550
-
(3.440) 3.440
15,110 3, MO
« »
- -
285,660 (118,745)
155,220 (155,220)
(220,400) 220.400
220,480 (53,565)
NET
NGL
COSTS
($/D AYi
_
-
18,550
-
-
18,550
_
166,915
-
-
166,915
revenue Increase.
, positive numbers are
cost increases.
-------
I
oo
TABLE 4-15
NGL SECTOR COSTS
($22 Crude - 1st Reduction)
(Page 2 of 2)
I
en
to
PRICES ($/Bbl)
PRODUCT
Region 3
Ethane
Propane
N-Butane
lao-Butane
Natural Gasoline
Region 4
Ethane
Propane
N-Butane
Iso-Butane
Natural Gasoline
(a) Negative numbers
(b) Negative numbers
BASE
9.62
12.76
19.27
23.22
20.4U
9.36
12.40
15.13
16.27
17.72
Indicate
Indicate
1ST RED
9.62
12.76
10.42
12.94
19.89
9.36
12.40
15.13
15.69
18.01
DIFF
8.85
10.28
0.55
Subtotal
_
-
_
0.58
(0.29)
Subtotal
NGL NGL
GAS PLANT INDUSTRY REFINING
PRODUCTION COSTS (a) COSTS (b)
(BPD) U/DAY) O/DAY)
332,000
315,000
127,000 1
63,000
179,000
Region 3 1
1,000
19,000
8,000
4,000
11,000
Region 4
a cost decrease, I.e. revenue Increase.
cost decreases, positive numbers are cost
_ -
,123,950 (391J736)
647,640 (470,770)
98,450 (98,450)
,870,040 (960,956)
_
~
2,320 (2,320)
(3.190) 3.190
(870) 870
Increases.
NET
NOL
COSTS
U/DAY)
-
732,211
176,870
909,084
-
-
-
-------
REPORT BIBLIOGRAPHY
1Bonner & Moore Associates, Inc., "Estimated Refining Cost
Impact of Reduced Gasoline Vapor Pressure," Final Report,
Prepared for the U.S. EPA under Work Assignments 23 and 28
of Contract No. 68-03-3162, 10 July 1985.
2Bonner <5c Moore Associates, Inc., "Estimated Refining Cost
Impact of Reduced Gasoline Vapor Pressure," Supplemental
Report, Prepared for the U.S. EPA under Work Assignments 5
and 6 of Contract 68-03-3244 and Work Assignment 13 of
Contract No. 68-03-3192, 25 February 1986.
3Jack Faucett Associates, "The Butane Industry: An Overview
and Analysis of the Effects of Gasoline Volatility Control
on Prices and Demand," Draft Report, Submitted to the U.S.
EPA under Work Assignment 5 Contract No. 68-03-3244, 30 May
1985.
^National Petroleum Council, U.S. Petroleum Refining, October
1986.
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APPENDIX A
PRODUCT DEMAND FORECASTS
SWR-8701 Bonner B Moore Maragarram Sctenca A-l
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APPENDIX A
PRODUCT DEMAND FORECASTS
A.I GENERAL ASSUMPTIONS
Appendix A presents three forecasts for petroleum
demand used in this study. These forecasts were developed
using prior forecasts from the U.S. DOE Department of Energy
and Chase Econometrics1^. Three forecasts were developed to
cover a range of crude oil prices for the 1990 time frame.
Forecast generations were based upon two assump-
tions as follows:
U. S. refiners' average acquisition cost for
crude was assumed to be: $27/bbl in the high-
cost case, $22/bbl in the medium-cost case, and
$17/bbl in the low-cost case. All prices are
in 1985 constant dollars.
Petroleum demand is sensitive to fuels prices
due to the impact prices have on inter-fuel
competition and on total demand for oil-derived
products.
SWR- 8701 Borrow 6 Moore Management Science A- 2
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A.2
METHODOLOGY
To forecast petroleum product demands in the U. S.,
detailed forecasts for total energy consumption by end-use
sector and fuel type were developed. These forecasts were
based on prior forecasts from the above-mentioned sources and
by applying implied growth rates to historical data on energy
consumption by end-use sector available through the State
Energy Data Base3. in some cases, the demand forecasts were
adjusted when judgment indicated that the resulting forecast
was unrea1i s t i c.
Resulting forecasts for growth in energy demand in
each consuming sector for each crude oil cost case are shown
in Figure A-l. As illustrated in this figure, the response
of demands to different price scenarios varies, due largely
to the relative importance of oil as a primary fuel in
meeting each demand.
I
a
CD
a
M
O
f-
f,
M
u
«
w
ft.
p
Figure A-l
U.S. Sector Energy Demand Growth Rates
Impact of Oil Price on Demand
SWR-8701
Bonner B Moore Management Science
A-3
-------
The satisfaction of projected energy demand by fuel
type was assigned by balancing available supplies for each
fuel with total demand. This process of allocating fuel
supplies was done by using data on current supply patterns
and a variety of forecasts for each energy supply component.
The forecast for U. S. petroleum demand generated by this
process is shown in Figure A-2. As illustrated by this
figure, the demand for petroleum is strongly influenced by
the cost of crude oil.
w
1
or
20
1070 1072 1074 1076 1078 1080 1082 1084 1086 1088
a f27/BB + f22/BBL o |17XBBL
1000
Figure A-2. U.S. Petroleum Demand
SWR-8701
Banner B Moore Management Science
A-4
-------
A.3 MAJOR PRODUCT PETROLEUM DEMAND
V
Each forecast for total petroleum demand was broken
into the major products identified in the refining models
utilized in this study. The forecasts for individual products
were prepared using a methodology similar to the one described
earlier. Within each consuming sector, petroleum products
supply a fraction of energy demand. Historical data for
refined products consumption within each sector, as well as
forecasts on the growth of product demands, were used to
forecast demand for each product.
The forecast for refined product demand required
examination of the key factors influencing demand in each oil
price scenario. Key factors in each sector are:
Residential Sector - focus in this sector is
home heating energy demand and penetration of
natural gas into this market.
Commercial Sector - focus is on regional dis-
tribution of office space and the corresponding
air conditioning and heating demands.
Industrial Sector - focus is on inter-fuel com-
petition, and the fuel-switching capability
within each region.
Transportation Sector - focus is on relative
growth among competing refined products, (i.e.,
diesel pent trat ion).
SWR-8701
-------
Once each sector's energy demands had been satisfied, like
refined product demands were summed across sectors to provide
total refined product demands. Table A-l presents the
resulting forecasts for refined product demand.
A.4 REGIONAL DEMAND FORECASTS
The methodology for generating regional energy fore-
casts required predicting, by end-use sector, each region's
share of the U.S. forecast. This prediction employs rela-
tionships which equate each region's energy share to each
region's share of key economic activity. Predictions of eco-
nomic activity are taken from Chase Econometrics' Regional
Forecast Data Service.
Once the demand for energy for each end-use sector
was forecast, the satisfaction of this energy demand by fuel
type was forecast using the same methodology used for the
U.S. forecast. Once each regional energy forecast was
complete, regional demands were aggregated and compared with
the U.S. forecast. If aggregated demands did not match the
U.S. forecast, regional demands were adjusted to attain
agreement.
The resulting forecasts for demands of major petro-
leum product are presented in Table A-2.
SWR-8701 Banner B Moore Management Science A-6
-------
TABLE A-1
U.S. REFINED PRODUCT DEMAND FORECAST
(MB/CD)
1990 DEMANDS
DEMAND $17/bbl 122/bbl »27/bbl
LPG 1,570 1,766 1,766 1,720
Citollne 6,735 7,288 7,122 6,886
JP-4 223 194 19* 194
J«t-A 956 1,233 1.145 1,054
Kerosene 116 136 136 126
Distillate 2,853 3,258 3,203 3,101
Resid 1,373 1,293 1.095 1,077
Coke 248 271 271 264
Other:
Still Cat 529 530 520 511
Asphalt I Road Oil 410 448 448 448
Lube* t Waxes 172 195 189 188
Pet. Chen. Naphtha 401 392 391 382
Other 175 135 135 122
Total 15,760 17,133 16.614 16.073
ANNUAL PERCENT GROWTH
S17/bbl $22/bbt S27/bbl
2-OX 2. OX 1.5X
1.3X 0.9X 0.4X
2.3X -2.3X -2.3X
4.3X 3. IX 1.6X
2.7X 2.7X 1.4X
2.2X 1.9X 1.4X
1.0X -3.7X -4. OX
1.5X 1.5X 1.0X
O.OX -0.3X -0.6X
1.5X 1.5X 1.5X
2.1X 1.5X 1.5X
0.4X -0.4X 0.8X
4.2X -4.2X -5.8X
1.4X 0.9X 0.3X
SWR-8701
Banner B Moore Management Science
A-7
-------
TABLE A-2
REGIONAL REFINED PRODUCT DEMAND FORECAST
(MB/CD)
(Page 1 of 2)
PAOO 1
1990 DEMANDS
LPG
Gasoline
JP-4
Jet-A
Kerosene
Distillate
Res Id
Coke
Other:
Still Gas
Asphalt I Road Oil
Lubes ( Waxes
Pet. Cheat. Naphtha
Other
Total
ivo*
DEMAND
160
2,339
69
367
26
1,043
728
37
SO
133
51
18
52
5,074
»17/bbl
168
2,458
60
459
34
1,203
761
40
50
145
57
16
40
5,493
S22/bbl
168
2,401
60
427
34
1,183
657
40
49
145
56
15
40
5,276
....
S27/bbl
165
2,331
60
394
32
1,141
619
39
49
145
56
15
36
5,082
PADD 3 -
1990 DEMANDS
LPG
Gasoline
JP-4
Jet-A
Kerosene
Distillate
Res id
Coke
Other:
Still Gas
Asphalt t Road Oil
Lubes I Waxes
Pet. Chen. Naphtha
Other
Total
ITW«»
DEMAND
844
999
39
105
61
493
290
100
241
62
70
336
49
3,689
S17/bbl
989
1,153
34
154
55
566
182
109
241
68
73
332
38
3,995
$22/bbl
989
1,128
34
143
55
559
176
109
237
68
72
333
M
3,942
S27/bbl
958
1,081
34
130
49
539
180
107
233
68
72
325
34
3,810
ANNUAL
S17/btal
O.SX
0.8X
2.3X
3.8X
4.2X
2.4X
0.8X
1.5X
O.OX
1.5X
1.9X
2.2X
4.2X
1.3X
ANNUAL
S17/bbl
2.7X
2.4X
-2.3X
6. A
1.5X
2.4X
7.5X
1.5X
O.OX
1.5X
O.SX
-0.2X
-4.2X
1.3X
PERCENT GMUTH
S22/bfal S27/bbl
0.8X O.SX
0.4X -0.1X
2.3X -2.3X
2.5X 1.2X
4.2X 3.5X
2. IX 1.5X
1.7X -2.7X
1.SX 1.0X
0.4X -0.6X
1.5X 1.5X
1.5X 1.3X
2.8X -3. OX
4.2X -5.8X
0.7X O.OX
PERCENT GROWTH
$22/bbl *27/bbl
2.7X 2.1X
2. OX 1.3X
-2.3X -2.3X
5.3X 3.7X
1.SX -3.4X
2. IX 1.SX
-8. OX -7.7X
1.5X 1.0X
-0.3X -0.6X
1.SX 1.SX
O.SX O.SX
-0.1X -O.SX
4.2X -S.8X
1.1X O.SX
SWR-8701
Homer 6 Moore Management Science
A-8
-------
TABLE A-2
REGIONAL REFINED PRODUCT DEMAND FORECAST
(MB/CD)
(Page 2 of 2)
CALIFORNIA
1990 DEMANDS
LPG
Gasoline
JP-4
Jet-A
Kerosene
Distillate
Resid
Coke
Other:
Still Gas
Asphalt I Road Oil
Lubes t Waxes
Pet. Chem. Naphtha
Other
Total
LPG
Gasoline
JP-4
Jet-A
Kerosene
Distillate
Resid
Coke
Other:
Still Gas
Asphalt I Road Oil
Lubes t Waxes
Pet. Chen. Naphtha
Other
Total
iyo*»
DEMAND
55
729
38
137
1
209
195
20
81
42
14
19
16
1,557
1OAA
iyo*»
DEMAND
510
2,667
77
346
28
1,108
160
91
157
173
37
29
58
5,440
S17/bbl
60
837
33
189
1
239
173
21
81
46
17
19
13
1,727
S22/bbl
60
830
33
180
1
236
162
21
79
46
16
18
13
1,695
....
S27/bbl
59
792
33
164
1
226
156
21
78
46
16
18
11
1,619
OTHER
1990 DEMANDS
$17/bbl
549
2,840
66
431
45
1,250
178
99
157
190
48
26
45
5,923
S22/bbl
549
2,763
66
395
45
1,225
100
99
155
190
45
25
45
5,702
»27/bbl
539
2,682
66
366
43
1,194
123
97
152
190
45
24
40
5,562
ANNUAL PERCENT GROWTH
S17/bbl 122/bbl S27/bbl
1.3X 1.3X 0.9X
2.3X 2.2X 1.4X
-2.3X -2.3X -2.3X
5.4X 4.6X 3. OX
7.2X 7.2X 6. OX
2.3X 2. OX 1.3X
-2. OX -3. OX -3.7X
1.5X 1.5X 1.0X
O.OX -0.3X -0.6X
1.5X 1.5X 1.5X
2.5X 1.9X 1.9X
0.5X -1.1X -1.4X
4.2X -4.2X -5.8X
1.7X 1.4X 0.7X
ANNUAL PERCENT GROWTH
$17/bbl S22/bbl S27/bbl
1.2X 1.2X 0.9X
1.1X 0.6X 0.1X
2.3X -2.3X -2.3X
3.7X 2.2X 0.9X
8.4X 8.4X 7.5X
2. OX 1.7X 1.3X
1.7X -7.6X -4.3X
1.5X 1.5X 1.0X
O.OX -0.2X -0.6X
1.5X 1.5X 1.5X
4.6X 3.4X 3.4X
-1.7X -2.2X -2. 51
4.2X -4.2X -S.tt
1.4X 0.8X 0.4X
SWR-8701
Bomer 6 Moore Management Science
A-9
-------
A.5 ANNUAL REFINING DEMANDS
This section covers the methodology for generating
refinery demands for each crude-cost case. These required
forecasting imports, exports and movements of refined pro-
ducts among regions.
Developing regional refinery output requirements for
meeting a forecast of demand for refined products depends on
assumptions concerning product imports, exports and inter-
regional movements as well as consideration of refinery
throughput and product slate for each region. In the absence
of a model for optimizing refined product supply, the task is
one of trial balancing, judgmental adjustments and rebal-
ancing. Historical import, export and inter-regional move-
ments are used as a basis for initial distributions.
A U.S. supply/demand balance is obtained by assuming
that historical import and export relationships will apply in
1990. Regional imports and exports are similarily defined as
a first approximation. Using assumed refinery output for all
regions except PADD 3, inter-regional product movements are
assigned to satisfy regional demand (overall). Historical
distribution patterns and expected (existing) transportation
facilities are used in this allocation. From this alloca-
tion, PADD 3 refining output is determined by difference and
judged reasonable or used to provide adjustments to refinery
output and/or product movements. Repeating this procedure
leads to overall refinery output predictions.
SWR-8701 Bonrier B Moore Management Sdence A-10
-------
Individual major product balances are prepared in an
analogous manner, with the added requirement that the total
production of products from each refining region match the
overall output derived as described earlier. Comparison of
product slates derived in this manner to historical product
liftings is another necessary consideration. If required,
adjustments to import and inter-regional transfers are made
to bring product yields into reasonable ranges.
Grade distributions for motor gasoline, distillate
and residual fuel were developed as follows. For motor gaso-
line, the grade distribution was based on projected national
vehicle population, scrappage rate, annual miles driven per
vehicle, and CAFE mileage*. These projections indicated a
continued decrease in leaded regular and an increase in
unleaded premium. National trends were then adjusted for
regional demands based on historical grade consumption in
each region. In PADD 1 and California, the demand for leaded
regular becomes quite small such that it probably would be
uneconomical to maintain the segregated distribution channels
requi red.
Grade distribution between heating oil and diesel
fuel was based on the energy-consuming sector demands by
region. Diesel is, thus, the demand in the industrial sector
for stationary engine and agricultural equipment fuel and, in
the transportation sector, for automotive and military use.
All other distillate demands were represented as heating oil
grade. The refinery distillate grade demands were then
calculated on the following assumptions:
*Relaxation of CAFE requirements through 1986 were considered
in making these determinations.
SWR-8701 A-ll
Burner B Moore Management Science
-------
Distillate imports and exports will be heating
oil only.
Inter-PAOD movements were assumed in proportion
to the demands in the receiving PADD after
adjusting for imports and exports.
Residual fuel oil grades were based on the demands
of each energy-consuming sector in each region. Grade splits
of imports, exports and inter-regional movements of residual
fuel were based on historical trends. Regional demand splits
and movement grade splits were combined to develop the
regional refining grade splits.
This process, when completed for each region,
resulted in detailed forecast balances for each product.
Table A-3 presents the forecast for total product imports
resulting from these balances. Imports for the low-cost
crude oil case are substantially higher due to the higher
level of demand and the required higher levels of refinery
ope rat ions.
Table A-4 presents the forecast of refining demands
for the total U.S. Table A-5 presents the regional refining
demand forecas t.
S WR 8 7 01
Bonnet 6 Moore Management Science A-12
-------
TABLE A-3
U.S. PRODUCT IMPORTS
(MB/CD)
1990 IMPORTS
IMPORTS S17/bbl $22/bbl S27/bbl
LPG 276 345 300 275
Gasoline 518 623 563 515
JP-4 13 16 14 13
Jet -A 45 56 49 45
Kerosene 11 14 12 11
Diet) I lite 259 299 292 258
Res id 567 659 552 514
Coke
Other:
Stilt Gas
Asphalt I Road Oil 49 61 53 49
Lubes t Uaxes 19 24 21 19
Pet. Chen. Naphtha 32 40 35 32
Other 50 62 54 49
Total 1,839 1.855 1,645 1,505
ANNUAL PERCENT GROWTH
$17/bbl *22/bbl *27/bbl
4.6X .7X -O.U
3.8X .TX, -O.U
4.5X .7X -0.1X
4.6X .7X -0.1X
4.6X .n -0.1X
2.9X 2.4X -0.1X
3.1X -0.6X -1.9X
4.5X 1.6X -0.2X
5. OX 2. IX 0.3X
4.8X 1.9X 0.1X
4.4X 1.5X -0.3X
0.2X -2.2X -3.9X
SWR-8701
Bonner 6 Moore Management Science
A-13
-------
TABLE A-4
U.S. REFINING DEMANDS
(MB/CD)
Gasoline
Leaded
Unleaded Regular
Unleaded Premium
JP-4
Jet-A
Kerosene
Distillate:
No. 2 Fuel Oil
Diesel
Residual Fuel Oil:
Low Fulfur
High Sulfur
Bunkers
Coke
Other Products:
Still Gas
Asphalt & Road Oil
Lubes I Waxes
Pet. Chem. Naphtha
Other
Total
DEMAND $17/bbl
6,441 6.674
1,248
3,612
1,814
206 17V
983 1,188
94 121
2,686 3,021
1,557
1,464
882 816
270
273
273
455 442
584 530
401 388
161 186
356 369
110 187
13,359 14,100
1990 OCNAND
«2/bbl
6,567
1,220
3,575
1,773
181
1,107
123
2,973
1,551
1,422
725
221
245
260
442
520
396
183
374
195
13,786
S27/bbl
6,379
1,179
3,486
1,714
182
1,020
115
2,905
1,511
1,394
744
244
253
247
436
511
400
184
368
175
13,419
ANNUAL HKCTT drovm
*17/bbl «2/bbl S27/tabl
0.7X 0.4X -0.2X
2.8X -2.6X -2.4X
3.9X 2.4X 0.7X
5.3X 5.6X 4. IX
2.4X 2. IX 1.6X
1.5X -3.9X -3.3X
0.6X -0.6X -0.9X
1.9X -2.3X -2.6X
0.7X -0.3X -O.OX
2.9X 2.6X 2.7X
0.7X 1.0X 0.6X
11. 2X 12. 1X 9.7X
1.1X 0.6X 0.1X
SWR-8701
Homer B Moore Management Science
A-14
-------
TABLE A-5
REGIONAL REFINING DEMANDS
(MB/CD)
(Page 1 of 2)
Gasoline
Leaded
Unleaded Regular
Unleaded Premium
JP-4
JefA
Kerosene
Distillate:
No. 2 Fuel Oil
Diesel
Residual Fuel Oil:
Low Fulfur
High Sulfur
Bunkers
Coke
Other Products:
Still Gas
Asphalt I Road Oil
Lubes I Waxes
Pet. Chem. Naphtha
Other
Total
Gasoline
Leaded
Unleaded Regular
Unleaded Premium
JP-4
Jet-A
Kerosene
Distillate:
No. 2 Fuel Oil
Diesel
Residual Fuel Oil:
Low Fulfur
High Sulfur
Bunkers
Coke
Other Products:
Still Gas
Asphalt ( Road Oil
Lubes & Waxes
Pet. Chem. Naphtha
Other
Total
1985 «
DEMAND
616
22
43
7
296
127
36
58
80
23
5
14
1,327
4QOC -
1VO3 *
DEMAND
2932
93
509
58
1245
311
193
273
104
98
300
67
6,183
Aoo'i
1990 DEMAND
S17/bbl
604
100
308
196
32
38
4
298
167
131
107
68
39
48
50
94
18
10
32
1,335
$17/bbl
3,113
556
1,672
886
62
644
75
1,430
749
681
243
66
66
111
191
241
83
113
308
91
6,595
S22/bbl
606
99
314
194
34
37
4
299
169
130
99
63
36
46
49
100
19
11
34
1,338
.... PADD
1990 DEMAND
S22/bbl
3,018
534
1,632
852
61
595
76
1,389
736
653
248
67
75
105
191
237
82
111
314
94
6,417
$27/bbl
608
98
318
192
35
37
5
291
165
126
93
59
33
47
49
103
20
11
30
1,328
3 --
*27/bbl
2,960
521
1,610
829
61
557
70
1,372
726
647
254
69
85
100
189
233
82
111
309
86
6,283 _
ANNUAL PERCENT GROWTH
$17/bbl
0.4X
7.8X
2.4X
-12. 4X
0.1X
3.4X
5.7X
2.8X
3.3X
-4.5X
16. OX
17.9X
0.1X
ANNUAL
$17/bbl
1.2X
7.9X
4.8X
5.4X
2.8X
4.8X
0.2X
2.4X
-4.5X
-5.8X
0.6X
6.3X
1.2X
$22/bbl
0.3X.
6.8X
-2.7X
-8.8X
O.ZX
4.9X
5.7X
3.3X
4.5X
4.2X
16. 2*
19. 8X
0.2X
(27/bbl
0.3X
9.9X
2.7X
8. OX
0.4X
6. IX
5.3X
3.5X
5.3X
2.6X
16. 4X
16. 3X
O.OX
PERCENT GROWTH
S22/bbl
0.6X
8. IX
3.2X
5.6X
2.2X
4.4X
-0.2X
2.8X
4.7X
6.3X
0.9X
7. OX
o.6x
S27/bbl
0.2X
8.2X
1.8X
3.8X
2. OX
4. OX
0.4X
3.1X
4.6X
-6.3X
0.6X
5.1X
P.-?*
SWR-8701
Banner B Moore Management Science
A-15
-------
TABLE A-5
REGIONAL REFINING DEMANDS
(MB/CD)
(Page 2 of 2)
- CALIFORNIA "'
Gasoline
Leaded
Unleaded Regular
Unleaded Premium
JP-4
Jet-A
Kerosene
Distillate:
No. 2 Fuel Oil
Diesel
Residual Fuel Oil:
Low Fulfur
High Sulfur
Bunkers
Coke
Other Products:
Still GAS
Asphalt I Road Oil
Lubes t Waxes
Pet. Chetn. Naphtha
Other
Total
1985
DEMAND
842
40
180
2
243
173
78
81
43
13
30
1.725
1990 DEMAND
S17/bbl
948
156
483
308
33
232
1
302
153
149
187
41
3
143
60
81
46
17
19
1,924
$22/bbl
940
153
486
301
33
222
1
298
151
148
176
36
4
136
60
79
46
16
18
1,888
S27/bbl
896
144
469
283
33
202
1
285
144
142
169
36
4
129
58
78
46
16
18
1,802
ANNUAL PERCENT GROWTH
$17/bbl
2.4X
3.9X
5.2X
7.1X
4.4X
1.6X
5.2X
0.5X
1.3X
5. OX
9.1X
ERR
2.4X
S22/bbl
2.2X
-3.9X
4.3X
-7.1X
4.2X
0.3X
5.2X
0.1X
1.3X
4.2X
9.7X
ERR
2. OX
S27/bbl
1.3X
3.9X
2.3X
6.4X
3.3X
-O.SX
5.7X
-0.2X
1.3X
4.2X
10. OX
ERR
1.0X
OTHER
Gasoline
Leaded
Unleaded Regular
Unleaded Premium
JP-4
Jet-A
Kerosene
Distillate:
No. 2 Fuel Oil
Diesel
Residual Fuel Oil:
Low Fulfur
High Sulfur
Bunkers
Coke
Other Products:
Still Gas
Asphalt & Road Oil
Lubes t Waxes
Pet. Chem. Naphtha
Other
Total
4AQC
iyo3
DEMAND
2051
52
252
28
901
271
148
147
174
27
32
29
4,112
$17/bbl
2,008
435
1,149
424
52
273
41
991
489
501
279
95
164
20
144
157
165
38
32
64
4,245
1990 DEMAND
S22/bbl
2,004
435
1,144-
426
54
253
41
988
496
492
203
55
130
19
144
155
168
37
31
66
4,144
$27/bbl
1,915
416
1,089
410
53
224
39
956
477
480
229
80
131
18
142
152
169
37
31
59
4,006
ANNUAL
$17/bbl
-0.4X
0.1X
1.6X
7.9X
1.9X
0.6X
0.6X
15. 3X
-1.0X
23. 7X
0.3X
17.1X
O.OX
PERCENT GROWTH.
$22/bbl
-0.5X
0.6X
0.1X
8.1X
1.9X
-5.6X
-0.6X
-15. 5X
0.7X
23. 4X
-0.7X
18. OX
O.SX
$27/bbl
1.4X
O.SX
2.3X
6.9X
1.2X
3.3X
O.SX
15. 9X
-0.6X
23. 3X
0.9X
15. 4X
1.2X
SWR-8701
Homer £ Moore Management Science
A-16
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A.6 SUMMER REFINING DEMANDS
Seasonal variations in manufacturing rates were
recognized by imposing the ratio of daily summer refined
product output to annual average daily output to each major
product for each crude-cost forecast. These factors are
shown in Table A-6.
TABLE A-6
SUMMER DEMAND FACTORS
MAJOR PRODUCT
Region Gasoline No. 2-D No. 2 No. 6
1 1.035 1.0 0.953 0.920
2 1.035 1.0 0.982 0.882
3 1.045 1.0 0.916 0.915
4 1.040 1.0 0.982 0.950
SWR-8701 BonnerB Moore Managemert Science A-1?
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A. 7 GASOLINE SAVINGS
Because reducing RVP reduces the butane content of
motor gasoline, low-RVP fuels are more dense than those with
higher RVPs. This means that gasoline powered vehicles would
show improved mileage per gallon because the increase in
volumetric heat of combustion would improve miles per gallon.
Furthermore, lower RVP would lower evaporative losses in the
distribution and dispensing of gasoline. These two factors
have been recognized in the gasoline demands imposed in this
study. Although the base RVP of summer gasoline varies among
regions, adjustments to gasoline demands were applied uni-
formly to all four regions.
Table A-7 lists the mileage and reduced evaporation
factors applied for each vapor pressure reduction level.
TABLE A-7
EFFECT OF REDUCED RVP ON GASOLINE DEMANDS
(Per Cent Decrease)
RVP LEVEL
Base 1 2 3_
Higher Density - 0.23 0.46 0.75
Less Evap. Loss - 0.30 0.47 0.57
Total - 0.53 0.93 1-32
SWR-8701 A-18
Banner B Moore Management Science
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A. 8 PETROCHEMICAL DEMANDS
The refining and gas processing sectors compete as
feedstock suppliers to the basic petrochemical industry.
Basic petrochemical production was forecast for this study
because changes in gasoline volatility will affect feedstock
selection and economics and, therefore, the overall costs of
volatility control.
Three forecasts were developed to correspond to the
three crude-cost scenarios. These three forecasts are pre-
sented by region in Table A-8. The ethylene production fore-
cast for the $17 crude-cost scenario was taken from a
Resource Planning Consultants forecast prepared in March of
1986 under a similar crude cost outlook.
This projection was made by forecasting ethylene
consumption from derivative growth rates. Ethylene produc-
tion for other crude-cost scenarios was made by adjusting the
projected rate of growth by the following formula:
Growth U/yr> *17 Crude] x [
°*
Ethylene Growth (%/yr) New Crude Cost
Petrochemical demands for propylene, butylenes, and
BTX were based on forecasts reported in the literature.
Adjustments for the various crude-cost scenarios were made in
the same fashion as for ethylene.
Regionalization of the national petrochemical pro-
duction forecasts was made according to the location of pro-
duction capacity as of early 1986.
SWR-870T BomerB Moore Manageronttoenra
-------
TABLE A-8
1990 PETROCHEMICAL PRODUCTION
$17 Crude Oil
Product
Ethylene
Propylene
Butylenes
BTX
Units
MMlbs
MMlbs
MMlbs
MMGals
1
203
989
253
159
2
2196
1407
160
507
Regions
3
31401
13119
2073
2073
$22 Crude Oil
Product
Ethylene
Propylene
Butylenes
BTX
Units
MMlbs
MMlbs
MMlbs
MMGals
1
200
980
253
150
2
2165
1394
160
503
Regions
3
30964
13011
2073-
2054
$27 Crude Oil
Product
Ethylene
Propylene
Butylenes
BTX
Units
MMlbs
MMlbs
MMlbs
MMGals
1
199
975
253
157
2
2148
1387
163
500
Regions
3
30713
12935
2073
2044
Price
4
0
285
15
61
Price
4
0
285
15
60
Price
4
0
281
15
60
National
33800
15800
2501
2800
National
33330
15670
2501
2776
National
33060
15578
2504
2761
SWR-8701
Homier 6 Moore Management Science
A-20
-------
APPENDIX A BIBLIOGRAPHY
1Energy Information Administration, Annual Energy Outlook,
1985, DOE/EIA-0383(85).
^Chase Econometics, Energy Analysis Quarterly, Second Quarter,
1986.
^Chase Econometrics, Regional Forecast Data Base, Second
Quarter 1986.
4Dewitt <5c Co., 1986 Petrochemical Review, Vol 1 & 2, April
1986
5Dewitt <5c Co., Petrochemicals in North America, 1985
SWR-8701 Bonner B Moore Management Science A-21
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APPENDIX B
RAW MATERIAL SUPPLY FORECAST
SWR-8701 BonnerBMoorBManaoumertSdencB B-l
-------
APPENDIX B
RAW MATERIAL SUPPLY FORECAST
B.I DOMESTIC CRUDE OIL PRODUCTION
This subsection presents forecasts for domestic
crude oil production used in this study. To account for the
three crude-oil-cost alternatives used, three separate fore-
casts for domestic crude oil production were generated.
Qualities associated with each production area are also pre-
sented.
The production of domestic crude was forecast using
Bonner <5c Moore's crude oil production model. This model
forecasts regional crude oil production based on historical
statistics and a forecast of crude oil prices. Using a
correlation between crude oil prices and reserves additions,
the impact of price changes was analyzed. Reserves additions
within each region were based upon the depletion of remaining
unrecovered resource in the region and the historical amount
of -reserves additions made each year. Reserves additions are
related to price of oil and the degree to which the remaining
resources are depleted.
The ratio of reserves to production (R/P) was fore-
cast using historical relationships of the R/P ratio to the
degree of depletion of the resource. Using forecast reserves
additions and the R/P ratio, production and ending reserves
were calculated. Forecasts for total domestic crude oil pro-
duction for each crude-cost case are shown in Figure B-l. As
expected, the lower the price, the lower the production.
Table B-l presents crude oil production by major producing
region and the mapping of this production into each of the
refining regions defined in this study.
SWR-8701 Bonner B MOOT Management Science B-2
-------
A
A
Z
o
e.io
1086 1088
117/BBL
1000
Figure B-1. Crude Oil Production
SWR-8701
Homer 6 Moore Management Science
B-3
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TABLE B-1
1990 DOMESTIC CRUDE PRODUCTION
PRODUCING
REGION
ss»«cas
AL,FL,HISS
TX & LA COAST
ARK.NLA.TR6
TR7&8.NM ,
TR5,9,10;KS,OK
CALIF
ALASKA
ROCKY MTN.
I NO, ILL, OHIO, MID
OTHER
TOTAL
AL.FL.MISS
TX & LA COAST
ARK,NLA,TR6
TR7&8.NM
TR5,9,10;KS,OK
CALIF
ALASKA
ROCKY MTN.
INO, ILL, OHIO, MID
OTHER
TOTAL
AL.FL.MISS
TX & LA COAST
ARK.NLA.TR6
TR7&8.NM
TR5,9.10;KS,OK
CALIF
ALASKA
ROCKY MTN.
I NO, ILL, OHIO, MID
.OTHER
TOTAL
ITS/ML (
CBVICf III
RerlHIW
PADD 1 PAOO 3
47 109
1,635
82
972
102
200
28 461
48
123 3,561
--- 22$/BBL
48 113
1,688
84
990
105
200
29 514
50
127 3,694
--- 27S/BBL
50 116
1,732
85
1,005
108
200
29 567
51
130 3.813
ASE --
OTHER CALFIFORNIA
211
596
626
948
255 810
625
370
2,682 1,758
CASE -
215
607
646
969
257 771
644
382
2,751 1,740
CASE
218
616
664
986
259 731
659
392
2.808 1,717
TOTAL
156
1.635
293
1.568
727
1,148
1.554
625
370
48
8,124
161
1,688
298
1,597
751
1.169
1,571
644
382
50
8.312
166
1,732
303
1,621
772
1.186
1,586
659
392
51
8,467
SWR-8701
Banner B Moore Management Science
B-4
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B.2 CRUDE OIL IMPORTS
Given each forecast for domestic production, a fore-
cast of crude imports was generated. Within each refining
region, one crude was identified as the "swing" crude. It
was used to balance raw material requirements within each
region. The source of swing crude for each region is:
REGION SOURCE OF SWING CRUDE
PADD 1 - Middle East - Arabian Light
PADD 3 - Middle East - Arabian Light
Other - Middle East - Arabian Light
California - Alaskan North Slope
To forecast crude imports, an estimate of the demand
for crude in each refining region was made. The required
volume of imports was calculated by subtracting the available
domestic production assigned to each region from the refining
demand estimate. This volume of imports was allocated to
each supply source using historical and forecast supply
ava.i labi 1 i ty. Table B-2 presents the resulting forecast for
crude oil imports by country of origin.
Qualities for each of these imports were also fore-
cast, using a method similar to the approach described for
domestic production. Import qualities were assigned using
the historical distribution of crude qualities received from
each exporting regions.
SWR-8701 BonnerB Moore Management Science B-5
-------
TABLE B-2
REGIONAL CRUDE OIL AVAILABILITY
VOLUME: (MB/CO)
Domestic
Imports
Total
GRAVITY: (API)
Domestic
Imports
Average
SULFUR: (Xwt)
Domestic
Imports
Average
VOLUME: (MB/CD)
Domestic
Imports
Total
GRAVITY: (API)
Domestic
Imports
Average
SULFUR: (Xwt)
Domestic
Imports
Average
VOLUME: (MB/CO)
Domestic
Imports
Total
GRAVITY: (API)
Domestic
Imports
Average
SULFUR: (Xwt)
Domestic
Imports
Average
PADO 1
123
1.037
1,160
34.74
33.34
33.49
0.84
0.77
0.79
127
1,027
1,154
34.72
33.37
33.53
0.84
0.67
0.77
130
1,023
1.153
34.72
33.38
33.53
0.84
0.76
0.77
PADO 3 OTHER CALIFORNIA
-- *17/bbl
3,561
2,188
6,749
31.38
29.85
30.80
0.74
1.39
0.99
$22/bbl
3.694
1,899
5,593
31.32
29.91
30.84
0.75
1.33
0.95
-- S27/bbl
3,813
1,662
5,475
31.27
30.18
30.94
0.76
1.28
0.92
...
2,682
1,207
3,889
34.69
34.17
34.53
0.82
0.89
0.84
...
2,751
1,046
3.797
34.71
34.08
34.45
0.82
0.92
0.84
...
2,808
863
3,671
34.73
34.34
34.63
0.82
0.84
0.82
1.749
153
3,498
25.20
36.59
26.11
1.30
0.28
1.21
1,713
153
1,866
25.16
36.59
26.08
1.29
0.28
1.21
1,630
153
1,783
25.06
36.59
26.05
1.28
0.28
1.19
TOTAL
8,115
4,585
12,700
31.19
32.00
31.48
0.89
1.08
0.96
8,284
4,125
12,409
31.22
32.08
31.15
0.89
1.05
0.94
8,380
3,702
12,082
31.27
32.30
31.59
0.88
0.99
0.91
SWR-8701
Hornier B Moore Management Science
B-6
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B.3 NATURAL GAS LIQUIDS SUPPLY
The forecast of natural gas liquids production from
domestic gas processing is based on Resource Planning
Consultants* (RPC) forecasts under crude oil price assumptions
identical to those used in this study.
The natural gas liquids production method started
with a projection of natural gas production by Petroleum
Administration for Defense District (PADD). Associated
natural gas production in each PADD was forecast from analy-
sis of historical gas-to-oil ratios. The forecast of non-
associated gas production was based on gas reserves,
projected reserve additions and projected reserves-to-
product ion rat ios.
Once regional natural gas production was developed,
production of individual natural gas liquids (ethane, pro-
pane, butanes, natural gasoline) were forecast from gas-to-
processing and historical liquid-recovery factors per million
cubic feet of gas processed. The resulting forecasts of
natural gas liquids production for the three crude-cost
levels are presented in Table B-3.
*RPC was acquired by Conner <5c Moore Associates, Inc. in
October of 1986 and carried out the NGL impact assessment
task of this project.
SWR-8701 Borrow B Moore Management Science B_7
-------
TABLE B-3
t990 DOMESTIC NATURAL GAS LIQUIDS PRODUCTION
": (MBCD)
$17 Crude Oil
Product/Region
Ethane
Propane
n-Butane
Isobutane
Natural Gasoline
Total
Product/Region
Ethane
Propane
n-Butane
Isobutane
Natural Gasoline
Total
Product/Region
Ethane
Propane
n-Butane
Isobutane
Natural Gasoline
Total
1
6
9
3
2
5
25
1
12
13
5
3
8
41
1
13
14
5
3
8
43
2
95
135
42
21
61
354
$22
2
129
157
54
26
76
442
$27
2
138
164
57
26
81
466
3
288
304
117
59
171
' 939
Crude Oil
3
332
315
127
63
179
1016
Crude Oil
3
355
328
134
65
191
1073
Price
4
1
16
8
3
11
39
Price
4
1
19
8
4
11
43
Price
4
1
20
8
4
12
45
Total
USA
390
464
170
85
248
1357
Total
USA
474
504
194
96
274
1542
Total
USA
507
526
204
98
292
1627
SWR-8701
BomerB Moore Management Science
B-8
-------
B.4 DEMANDS FOR NATURAL GAS LIQUIDS OUTSIDE OF
REFINING AND ETHYLENE FEEDSTOCKS
The modeling effort in this study explicitly covers
the refining and ethylene production sectors. While a large
portion of natural gas liquids supply is consumed by these
industries, there are also other consumers.
To properly reflect the availability of natural gas
liquids for refining and ethylene feedstocks, the projected
demands in other applications were included in the forecasting
effort. These "other applications" include NGLs used as fuel
in transportation, industrial, residential, commercial and
utility gas applications. Also included are NGLs used as
feedstock for petrochemicals other than ethylene and for
synthetic natural gas. U.S. demands for these applications
were taken from forecasts prepared by RFC in proprietary
study reports prepared for clients in 1985 and 1986l»2i3t
End-use fuel demands were regionalized for this study using
the 1984 and preliminary 1985 sales reported by the American
Petroleum Instituted Regionalization of NGL used as feed-
stocks for synthetic natural gas and petrochemicals other
than ethylene were based on existing plant locations.
Table B-4 summarizes the regional demands for NGLs
as fuels and feedstocks (excluding ethylene) for each of the
crude-cost levels used in the study.
SWR-8701 BonnerBMooreManagement Science B-9
-------
TABLE B-4
1990 FUEL AND FEEDSTOCK DEMAND FOR
NATURAL GAS LIQUIDS*
(MBCD)
$17 Crude Oil
Product/Region
Ethane
Propane
n-Butane
Isobutane
Total
Product/Region
Ethane
Propane
n-Butane
Isobutane
Total
Product/Region
Ethane
Propane
n-Butane
Isobutane
Total
Excludes ethylene
1
6
108
5
0
119
1
12
108
5
0
125
1
13
101
5
0
119
feedstocks
2
29
244
6
0
279
$22
2
29
244
6
0
279
$27
2
33
228
6
0
267
3
33
207
2
23
265
Crude Oil
3
33
207
2
23
265
Crude Oil
3
34
194
2
21
251
Price
4
1
42
0
0
43
Price
4
1
42
0
0
43
Price
4
1
39
0
0
40
Total
USA
69
601
13
23
706
Total
USA
75
601
13
23
712
Total
USA
81
562
13
21
677
SWR-8701
Banner B Moore Management Science
B-10
-------
APPENDIX B BIBLIOGRAPHY
1Resource Planning Consultants (RPC), Outlook for Supply,
Demand and Pricing, March, 1986 (Proprietary Study).
2Resource Planning Consultants (RPC), Outlook for Supply,
Demand and Pricing, March, 1985 (Proprietary Study).
3Resource Planning Consultants (RPC), West Coast Natural Gas
Liquids Markets, May, 1986 (Proprietary Study).
^American Petroleum Institute, Sales of Natural Gas Liquids
and Liquefied Refinery Gases, 1984 (Annual Publication).
SWR-8701 BonnBrBMooreManagBTOrttoenca B-ll
-------
APPENDIX C
PRODUCT SPECIFICATIONS
SWR-8701 Bonner 8 Moore Management Science C-l
-------
APPENDIX C
PRODUCT SPECIFICATIONS
Specifications for those products modeled to satisfy
quality restrictions are shown in Table C-l. In addition,
LPG was modeled to compositional specification of 5 volume-
percent maximum olefins content and 80 percent maximum
butanes. All other products, such as lubes, asphalts, and
specialty naphthas were modeled as recipe blends.
Product specifications, with the exception of those
enumerated below are those in Bonner
-------
Go
TABLE C-1
i
00
PRODUCT SPECIFICATIONS
(Sheet 1 of 2)
GASOLINES:
REGION
SEASON
Distillation
Pet § 160°F (Max)
Pet § 210°F (Min)
Pet 0 230°F (Min)
Pet 6 330°F (Min)
20 V/L Temp. 1°F (Min)
Reid Vapor Pressure,
psi (Max)
1st Reduction
2nd Reduction
3rd Reduction
Octane, Minimum
Leaded Regular, (R+M)/2
Leaded Regular, Motor
Unleaded Regular, (R+M)/2
Unleaded Regular, Motor
Unleaded Premium, (R+M)/2
Unleaded Premium, Motor
1
Annual
46
41
48
79
115
13
89
83
87
82
91
86
.73
.47
.27
.50
.0
33
.0
.5
.25
.25
.75
.25
2
Summer
46.
39.
46.
79.
123.
11 .
10.
9.
8.
89.
83.
87.
82.
91.
86.
50
70
70
10
0
75
73
71
69
0
5
25
25
75
25
Annual
46
40
47
79
117
12
89
83
87
82
91
86
.65
.81
.67
.33
.8
.79
.0
.5
.25
.25
.75
.25
Summer
46.40
38.76
45.83
78.83
127.0
11 .01
10.05
9.09
8.11
89.0
83.5
87.25
82.25
91.75
86.25
3
Annual
46.50
39.80
46.80
79.10
122.6
12.00
89.0
83.5
87.25
82.25
91.75
86.25
Summer
46.38
38.57
45.66
78.79
127.7
10.92
9.97
9.02
8.07
89.0
83.5
87.25
82.25
91.75
86.25
4
Annual
46.36
38.37
45.50
78.76
127.8
11.12
89-0
83-5
88.0
83-0
91.75
86.25
Summer
46.05
35.53
42.96
78.12
138.4
9.23
8.43
7.63
6.82
89.0
83.5
88.0
83.0
91.75
86.25
o
Co
-------
GO
SC
so
co
~~J
o
TABLE C-1
PRODUCT SPECIFICATIONS
(Sheet 2 of 2)
Med. S High S Bunker
JP-4 Jet-A No. 2 Diesel F.O. F.O. F.O.
Pet Dist. @ MOO°F, (Min)
Aromatics, Vol. Pet, (Max)
Smoke Point, MM
Specific Gravity, (Min)
Specific Gravity, (Max)
Flash Point, °F (Min)
Sulfur Content, Wgt. Pet (Max
Cetane Index (Min)**
Viscosity, SSF § 122°F (Max)
60.0 10.0 -
25.0 25.0 -
20.0 18.0 -
0.75 0.77 -
0.80 0.8U 0.876 - - 0.995
100 125 125 150 150
) 0.30 0.30 0.25 0.25* 1.00* 3-00
45.5
300 300
-
-
-
-
1.000
150
5.00
-
250
* Maximum sulfur contents for Region 4 were 0.15 for No. 2 diesel fuel and 0.5 for
medium sulfur No. 6.
Average of regional survey quality from "Diesel Fuel Oils, 1985", Ella Mae Shelton
and Cheryl L. Dickson, National Institute for Petroleum and Energy Research,
October 1985
o
i
-------
ASTM D 439 schedules for various volatility classes describe
distillation controls in terms of minimum and maximum tem-
peratures at specified percents distilled. Representing such
limits in mathematical models is usually done by transposing
temperature limits at specified distillation points to
distillation limits at specified temperatures.
RVP, being the subject specification of this study
was varied by applying proportional reductions in regional
refinery base requirements according to the following:
A first level of reduction was proportional to
a 1.0 psi reduction from an 11.5 psi base,
i.e., 8.7 percent of each base summer RVP
maximum.
A second level was proportional to a 2.0-psi
reduction from an 11.5 psi base, i.e., 17.4
percent of each base summer RVP maximum.
A third level was proportional to a 3.0 psi
reduction from an 11.5 psi base, i.e., 26.1
percent of each base summer RVP maximum.
Weight-percent-sulfur specifications for No. 6 Fuel
Oils were set to represent the fuel oil production grouping
in the DOE "Petroleum Annual Statement." Low-sulfur fuel oil
(with a specification of 0.3 weight percent sulfur) was not
represented as such because its production depends on segre-
gated low-sulfur crudes. Medium-sulfur fuel oil, with a
weight percent sulfur of 1.0 represents both low- and medium-
sulfur fuel. High-sulfur fuel oil was given a specification
of 3.0 weight-percent sulfur. Bunker fuels were given a
maximum sulfur-content of 5.0 weight-percent.
SWR-8701 Bonner B Moore Management Science C-5
-------
APPENDIX C BIBLIOGRAPHY
IDickson, C. L. and P. W. Woodward, National Institute for
Petroleum and Energy Research, Motor Gasolines, Winter,
1985-86, August 1986.
Bonnet B Moore Management Science c" 6
-------
APPENDIX D
ECONOMIC AND FINANCIAL FACTORS
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APPENDIX D
ECONOMIC AND FINANCIAL FACTORS
All costs and prices employed in this study were
based on 1986 values. No inflation to 1990 was employed,
i.e., a constant 1986 dollar value was assumed.
Prices for major products and costs for the base
crude slate were not needed since demands for major products
and input of non-swing crudes were fixed at forecast levels.
Costs for swing crudes, natural gas liquids (namely, ethane,
propane, normal and iso-butane), and prices for by-products
(namely, butadiene, petroleum, coke and sulfur) were,
however, required. The refinery costs and net-back prices
for these are displayed in Table D-l.
Swing crude costs are based on current posted prices,
FOB Ras Tanura, plus transportation costs to New York, Chicago
and Houston representing costs to Regions 1, 2 and 3, respec-
tively. Normal butane, iso-butane and natural gasoline costs
for Regions 2 and 3 were based on results from the Resource
Planning Consultants Hydrocarbon Pricing Model using crude
oil prices of $17, $22 and $27. Prices for Region 1 were
determined using transportation cost estimates to Philadelphia.
Prices for Region 4 were determined by historical analysis of
differentials to Region 3. Coke prices were based on export
fuel values for each r ;ion. Sulfur prices were set to the
same value for all regions.
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TABLE D-1
RAW MATERIAL AND UTILITY COSTS AND
BY-PRODUCT WETBACK PRICES
Region
Ave. Acquisition Cost, $/BBL
Raw Mat 'Is, $/BBL
Swing Crude
Ethane
Propane
Iso-Butane
N-Butane
Methanol (for MTBE)*
By-Products
Coke, $/FOEB
Sulfur, $/TON
Butadiene, $/TON
Utilities
Tetraethyl Lead, $/42 gm
Fuel, $/MMBTU
Electrical Power, 0/KWh
Oxygenates for gasoline blendi
zero costs.
1
22
23.17
_
16.51
20.63
19.27
15. or
8.85
50.0
420.0
3.60
5.54
ng, being
2
22
23.75
8.09
14.07
21.03
17.83
15.96
8.85
50.0
420.0
2.90
6.78
fixed in
3
17
17.94
6.16
10.65
14.64
13-07
12.60
7.45
50.0
360.0
1.79
4.74
concentration
3
22
23.17
8.78
14.27
18.68
17.36
15.12
8.85
50.0
420.0
2.41
4.96
, were
3
27
28.41
10.88
17.47
21.87
20.89
17.22
8.85
50.0
500.0
2.94
4.97
modeled with
4
22
20.95
16.05
20.66
16.09
16.38
8.85
50.0
420.0
3.50
5.32
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The Refinery and Petrochemical Modeling System
(RPMS), a proprietary Bonner & Moore system, generates pro-
cess operating costs from utility consumption factors
multiplied by applicable utility costs. Fuel and steam costs
to all processes are based on natural gas or plant fuel costs
plus investment and operating costs for utility supply facil-
ities. Cooling water costs are based on zero-cost raw water
plus the investment and operating costs of cooling and pumping
facilities. Electric power was assumed to be purchased in
all cases rather than internally generated. Power costs were
obtained from Electric Power Monthly using quotations repre-
senting each region.
RPMS process data include 1982 catalyst and chemical
costs for each process. These 1982 costs were converted to
1986 values using a cost index of 1.026.
Capital requirements for new and expanded capacity
were derived from investment-versus-capacity relationships*
for each process using equipment sizes consistent with recent
industry activities. Thus, capacity costs are based on
typical process capacities. Those process investments
required for summertime RVP compliance were required to be
amortized during a summer period of 152 days. This effec-
tively increases capital-related costs by a factor of 365/152
or 2.4.
The cost of supporting required investments was
determined by applying a capital recovery factor derived from
the factors shown in Table D-2.
*Part of RPMS proprietary data.
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TABLE D-2
FINANCIAL AND CAPITAL-RELATED FACTORS
FACTOR
Economic Life, yrs. 13
Depreciation Life, yrs. 13
Federal Income Tax Rate, percent 34
After tax Cost of Capital, percent 15
Capital Recovery Factor* 0.226
Local Taxes, Insurance and Overhead, { per year 2
Maintenance, % per year 4
*Using double-declining-balance depreciation tax credit.
Adding maintenance, local taxes, insurance and
overhead cost factors to capital recovery, the total cost of
supporting one dollar of investment becomes 0.286 dollars per
year. When adjusted for summertime amortization, the total
cost supporting one dollar of investment becomes 0.687
dollars per summer period.
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APPENDIX E
BASE CONFIGURATION
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APPENDIX E
BASE CONFIGURATION
The capacities of major processes used in regional
models are displayed in Table E-l. These data are based on
the Oi1 & Gas Journal "Annual Refining Survey" (March 24,
1986) and represent reported capacities as of January 1,
1986. To these capacities, adjustments based on announce-
ments in trade journals and other industry publications were
made as shown in Table E-2. Base capacities in each model
were allowed to be expanded, as required, to meet 1990 annual
average product and raw material situations, at cost typical
of the sizes installed in recent years. Capacity additions
indicated necessary (or justified) to meet 1990 annual average
conditions are shown in Table E-3. Included in Table E-3 are
capacity requirements for auxiliary processes not reported in
conf igurat ion data.
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TABLE E-1
REFINING PROCESS CAPACITIES AS OF 1/1/85
(Thousands of Barrels per Calendar Day)
PROCESS
Atmospheric Crude Dist.
Vacuum Distillation
Naphtha Hydrotreating
Reforming
Cat Cracking (Total Feed)
Heavy-Oil Cracking
Hydrocracking
Alkylation
Catalytic Polymerization
Coking
Visbreaking
Light Oil Hydrotreating
Gasoil Hydrotreating
Resid Hydrocracking
Residual Desulfurization
Butane Isomerization
C5 - C6 Isomerization
MTBE Production
H2 Production (MMCFD)
REGION 1
1387.9
650.2
389.2
336.3
566.6
0.0
69.6
67.8
'16.6
74.3
12.2
354.2
118.4
0.0
0.0
0.0
23.5
2.8
89.9
REGION 2
4533.8
1631.5
1106.6
1052.5
1403-0
37.6
214.8
295.0
22.8
344.0
8.5
630.6
322.3
8.5
0.0
22.9
73.0
3.7
388.0
REGION 3
6993.5
2768.7
1703.2
1569.9
2246.7
106.2
344.7
415.9
33-3
515.9
92.6
1423.1
554.5
89.3
325.2
26.4
93-2
37.0
937.5
REGION 4
2385.7
1244.9
512.8
504.1
559.8
0.0
315.7
98.8
2.3
401.7
61.9
361.1
316.7
28.2
22.6
9.8
0.0
0.0
893.7
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TABLE E-2
ANNOUNCED CAPACITY CHANGES (ABOVE 1/1/85)
(Thousands of B. ~rels per Calendar Day)
PROCESS
Atmospheric Crude Dist.
Vacuum Distillation
Naphtha Hydrotreating
Reforming
Cat Cracking (Total Feed)
Hydrocracking
Alkylation
Catalytic Polymerization
Coking
Light Oil Hydrotreating
Gasoil Hydrotreating
C5 - C6 Isoraerization
REGION 1 REGION 2
31 .0
60.0
2.0 29.0
2.2 15.7
-16.0
-6.0
1.7
10.0
0.8
2.7 55.4
REGION 3
116.0
14.0
27.5
48.5
20.0
23-5
6.6
25.0
4.0
18.0
26.8
REGION 4
-26.0
-6.0
2.7
20.Q
2.2
7.0
70.0
138.0
7.4
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TABLE E-3
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CAPACITY ADDITIONS FOR 1990
(Thousands of Barrels per Calendar Day)
PROCESS
Butane Splitting
Cat Gasoline Splitting
Cat Polymerization
C5C6 Isoraerization
Debutanization
Delayed Coking
Depentanization
Pentane Splitting
Depropanization
Gas Oil Desulferization
H2 Production
High-Severity Reforming
Kerosene-Severity Hydrocrk.
MTBE Production
Visbreaking
REGION 1
11 .6
_
_
39.3
23.2
_
11 .6
10.6
10.0
_
13.2
_
REGION 2
83.0
14.6
_
88.4
98. 1
42. 1
83.0
33.1
119.3
_
_
_
3.7
REGION 3
0.9
0.9
-
-
211.8
4.2
0.9
0.4
2.6
6.5
_
52.1
11.2
REGION 4
61.7
2.2
29.3
-
-
61.7
2.0
14.3
-
102.2
47.8
19.6
TOTALS
157.2
15.5
2.2
157.0
381.1
46.3
157.2
46.1
146.2
6.5
13.2
154.3
47.8
30.8
3.7
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APPENDIX F
OXYGENATE BLENDING VALUES
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APPENDIX F
OXYGENATE BLENDING VALUES
Three kinds of oxygenates were included as gasoline
blendstocks in the models employed in this study. These are
ethanol, methanol-TBA (Tertiary-butyl-alcohol) and MTBE
(methyl-tertiary-butyl-ether). Non-linearities associated
with the azeotropic behavior of alcohol-hydrocarbon blends
were resolved by imposing fixed concentrations of alcohols
and by determining the RVP blending values of alcohols con-
sistent with that concentration and the RVP specification
being imposed. Other blending values were treated as
constant properties and are shown in Table F-1 along with
blending values for MTBE.
TABLE F-1
BLENDING VALUES FOR ALCOHOLS
"
Fixed Concentration,
Volume percent
Property
Percent Distilled at:
160°F
210°F
230°F
330°F
Research Octane (Clear)
Motor Octane (Clear)
(R+M)/2 (Clear)
Specific Gravity
MTBE
(none)
60.0
100.0
100.0
100.0
114.5
97.5
106.0
0.74
2/1
METHANOL-TBA
7.5
175.0
105.0
100.0
100.0
124.7
97.3
111.0
0.8
ETHANOL
10.0
220.0
137.0
108.0
100.0
133.4
101.8
117.6
0.8
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Effect ive-RVP-blending values for alcohols were
determined by employing the assumption of a constant (psi)
increase; in the RVP of a hydrocarbon-alcohol mixture
(regardless of concentration of alcohol) and back calculating
the blending-RVP for a given RVP specification and alcohol
concentration. The equation used for this calculation is
developed as follows:
RHVu
+ EA =
< RVPS
where: RJJ = RVP of hydrocarbon portion
VH = Volume fraction of hydrocarbon portion
EA = Constant RVP-effect of alcohol
RVPB = RVP of final blend
RVPg = RVP (maximum) specification
It is safe to assume that RVPg = RVPg.
Let RA and VA be the RVP-blending value and volume fraction
of alcohol, respectively, Then,
RHvH +
VA
(2)
Solving equation (1) for RHVfj and substituting in equation
(2) gives
(RVPS - EA)VH
VH + VA
= Rvps
(3)
Solving equation (3) for RA and recognizing that VH + VA = 1.0
gi ves
RA = RVPS + 1-VA EA
VA
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Values for ethanol and 2/1 methanol-TBA used in this
study are shown in Table F-2.
TABLE F-2
DATA FOR RVP EFFECTS AT ALCOHOL BLENDING
E
A VA
Ethanol 1.5 0.100
Methanol-TBA (2/1) 2.6 0.075
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