AN ECONOMIC ANALYSIS
OF
PROPOSED SCHEDULES
FOR
REMOVAL OF LEAD ADDITIVES FROM GASOLINE
Prepared for the Environmental
Protection Agency under Contract
Number 68-02-0050
Banner & Moore
Associates, Inc.
BOO Jefferson Bldg. | Cullen Center
Houston, Texas 77OO2 (713) 228-O871
Cable: BONMOR
MANAGEMENT SERVICES
OPERATIONS RESEARCH INFORMATION SYSTEMS
PROGRAMMING SYSTEMS TECHNICAL PUBLICATIONS PROCESS CONTROL
-------
ENVIRONMENTAL PROTECTION AGENCY (EPA)'
OFFICE OF AIR PROGRAMS
OFFICE OF TECHNICAL INFORMATION AND PUBLICATIONS
* * *
AIR POLLUTION TECHNICAL INFORMATION CENTER
Research Triangle Park, N. C. 27711
The Office of Technical Information and Publications (OTIP) provides a complete
system of technical information and communication activities. The principal element
of OTIP charged with the responsibility of technical literature communication is
the Air Pollution Technical Information Center (APTIC) . APTIC is responsible for the
collection and dissemination of all domestic and foreign technical literature related
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1. Preparation of a monthly bulletin containing informative abstracts
of approximately 1000 technical articles. Air Pollution Abstracts
has a world-wide distribution of 10,000, with coverage including
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* Individual literature searches are conducted without charge.
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EPA use.
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AN ECONOMIC ANALYSIS
OF
PROPOSED SCHEDULES
FOR
REMOVAL OF LEAD ADDITIVES FROM GASOLINE
Prepared for the Environmental
Protection Agency under Contract
Number 68-02-0050
25 June 1971
Banner & Moore
Associates, Inc.
BOO Jefferson Bldg. ! Cullen Center
Houston, Texas 77OO2 j (713) 228-O871
Cable: BONMOR
MANAGEMENT SERVICES | OPERATIONS RESEARCH INFORMATION SYSTEMS
PROGRAMMING SYSTEMS I TECHNICAL PUBLICATIONS ' PROCESS CONTROL
RGH-015
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TABLE OF CONTENTS
Paragraph Page
SECTION 1
INTRODUCTION
1.1 PURPOSE -- --' 1-1
1.2 STUDY TEAM ORGANIZATION ----- 1-1
1.3 REPORT STRUCTURE 1-1
SECTION 2
STUDY SCOPE AND METHODOLOGY
2.1 SCOPE - - 2-1
2.2 METHODOLOGY OF STUDY - 2-3
SECTION 3
SUMMARY OF CONCLUSIONS
3.1 LEAD REMOVAL STRATEGIES- 3-1
3.2 MAJOR CONCLUSIONS - -- 3-2
3.3 ECONOMIC IMPACT - 3-6
SECTION 4
DETAILED RESULTS AND CONCLUSIONS
4.1 LEAD REMOVAL DISTRIBUTION COSTS - 4-2
4.2 SCHEDULE A 4-6
4.3 SCHEDULE L 4-13
4.4 SCHEDULE G - - 4-21
4.5 SCHEDULE M - -- - 4-28
4.6 REFERENCE SCHEDULE --- - 4-35
4.7 SENSITIVITY ANALYSES 4-38
4.8 EFFECTS ON SMALL REFINERS - - 4-43
4.9 IMPACT ON THE CONSTRUCTION INDUSTRY 4-51
4.10 EFFECT ON PETROCHEMICALS - 4-61
4.11 CALIFORNIA MODEL RESULTS -- 4-63
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TABLE OF CONTENTS (cont.)
Paragraph Page
SECTION 5
DETAILED STUDY METHODOLOGY AND PREMISES
5.1 STUDY METHODS - 5-1
5.2 REFINING AND PETROCHEMICAL INDUSTRY BASIS 5-6
5.3 DEMAND FORECASTS 5-14
5.4 PROCESS .CONSTRUCTION INDUSTRY BASIS 5-34
APPENDICES
A LEAD REMOVAL SCHEDULES - - A-l
B SAMPLE MODEL OUTPUT REPORTS - - B-l
C COMMENTS ON OTHER SCHEDULES OF THE RFP - C-l
D MARKETING CHARACTERISTICS OF OIL COMPANIES - D-l
E CAPITAL RECOVERY FACTOR -- - E-l
F GLOSSARY OF TERMS -- F-l
G BIBLIOGRAPHY - G-l
ADDENDUM
AN ECONOMIC ANALYSIS OF PROPOSED SCHEDULES 0 AND N FOR REMOVAL
OF LEAD ADDITIVES FROM GASOLINE
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LIST OF ILLUSTRATIONS
Figure Page
2-1 Peak Point Effect of Rapid Lead Reduction 2-5
3-1 Cumulative Investment Requirements for Schedules A, G, L and M — 3-4
3-2 Aromatics and Lead Levels for Three-Grade System 3-10
3-3 Aromatics and Lead Levels for Two-Grade System 3-11
4-1 Refinery Size versus Added Capital Investment to Manufacture
Unleaded Motor Gasoline 4-46
4-2 Added Raw Stock versus Pool Octane for Varying Refinery Sizes 4-47
4-3 Annual Investment ($ Billions) for Schedule A 4-55
4-4 Annual Investment ($ Billions) for Schedule G 4-56
4-5 Annual Investment ($ Billions) for Schedule L 4-57
4-6 Annual Investment ($ Billions) for Schedule M 4-58
5-1 Distribution of Research Octane Number Requirements As
Function of Compression Ratio 5-15
5-2 Investment Distribution for Process Construction Sectors 5-37
5-3 Historical Investment 5-38
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LIST OF TABLES
Table Page
1 STUDY RESULT SUMMARY - 3-3
2 COMPARISON OF INVESTMENT TO CAPACITY RATIOS - 3-12
3 INCREASED MANUFACTURING COST VERSUS REFINERY SIZE 3-13
4 RAW STOCK REQUIREMENTS FOR SCHEDULE A 4-6
5 BY-PRODUCT PRODUCTION FOR SCHEDULE A - - 4-7
6 TEL CONTENTS OF SCHEDULE A GASOLINES - 4-8
7 GASOLINE SUMMARY FOR SCHEDULE A (Sheet 1 of 2) 4-9
8 PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE A - 4-11
9 COST EFFECTS OF SCHEDULE A 4-12
10 RAW STOCK REQUIREMENTS FOR SCHEDULE L - 4-14
11 BY-PRODUCT PRODUCTION FOR SCHEDULE L 4-14
12 TEL CONTENTS OF SCHEDULE L GASOLINES 4-15
13 PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE L - 4-16
14 GASOLINE SUMMARY FOR SCHEDULE L (Sheet 1 of 2) 4-17
15 COST EFFECTS OF SCHEDULE L -- 4-20
16 RAW STOCK REQUIREMENTS FOR SCHEDULE G - 4-21
17 BY-PRODUCT PRODUCTION FOR SCHEDULE G 4-22
18 GASOLINE SUMMARY FOR SCHEDULE G (Sheet 1 of 2) 4-23
19 PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE G 4-25
20 COST EFFECTS OF SCHEDULE G 4-26
21 RAW STOCK REQUIREMENTS FOR SCHEDULE M - 4-28
22 BY-PRODUCT PRODUCTION FOR SCHEDULE M 4-29
23 GASOLINE SUMMARY FOR SCHEDULE M (Sheet 1 of 2) 4-30
24 TEL CONTENTS OF SCHEDULE M GASOLINE -- 4-32
25 PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE M - 4-32
26 COST EFFECTS OF SCHEDULE M • 4-34
27 PROCESS CAPACITY REQUIREMENTS FOR REFERENCE SCHEDULE 4-35
28 GASOLINE SUMMARY FOR REFERENCE SCHEDULE (Sheet 1 of 2) 4-36
29 EFFECT ON ADDED COST AND INVESTMENT RESULTS OF VARYING
KEY ASSUMPTIONS - 4-39
30 EFFECT OF GRADE MIX VARIATIONS ON AVERAGE GASOLINE REFINERY
NETBACKS 4-42
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LIST OF TABLES (cont.)
Table Page
31 GROWTH AND DECLINE TRENDS AMONG SMALL U.S. GASOLINE REFINERS
FROM 1950 THROUGH 1970 - 4-44
32 CRUDE CAPACITY TRENDS OF SMALL REFINERIES 4-44
33 EXTRAPOLATION OF REFINERY SIZE EFFECTS ON COST ESTIMATES FOR
SCHEDULE A - 4-48
34 CRUDE OIL IMPORT ALLOCATION FORMULA - 4-49
35 CONSTRUCTION INDUSTRY INVESTMENTS - 4-54
36 CONSTRUCTION COSTS BY SECTOR - 4-59
37 COST RATIOS FOR CALIFORNIA ECONOMIC BEHAVIOR 4-63
38 GASOLINE BLENDING SPECIFICATIONS - 5-13
39 BASIS FOR GRADE DISTRIBUTION - AUTOMOBILES AND LIGHT TRUCKS 5-18
40 NATIONAL DEMAND FORECAST FOR GASOLINE - 5-20
41 MILEAGE VERSUS VEHICLE AGE --- 5-21
42 GASOLINE CONSUMED P.ROFILES - 5-22
43 NAPHTHA JET FUEL PRODUCTION HISTORY 5-23
44 KEROSENE AND KEROSENE JET FUEL PRODUCTION HISTORY 5-24
45 AVIATION GASOLINE PRODUCTION HISTORY - 5-25
46 DISTILLATE PRODUCTION HISTORY 5-26
47 DISTILLATE PRODUCT BLEND 5-27
48 NATIONAL DEMAND FORECAST FOR PETROCHEMICALS 5-28
49 COMBINED PROCESS CONSTRUCTION INDUSTRY MAXIMUM GROWTH
PROJECTION --- 5-41
C-l LEAD REQUIREMENTS - C-3
C-2 AROMATICS BURNED IN PRE-1975 VEHICLES C-3
C-3 REFINING INVESTMENT --- C-4
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SECTION 1
INTRODUCTION
1.1 PURPOSE
This report is in response to RFP No. EHSD 71-Neg 44, which called for
an investigation of the economic Impact of various gasoline lead removal sched-
ules. The schedules varied in rapidity of lead removal and in the number of gas-
oline grades produced. These schedules are shown in Appendix A.
1.2 STUDY TEAM ORGANIZATION
The two-month time limit called for in the RFP necessitated that the
study method be simplified as much as possible and that maximum use be made of
existing data and data-correlations which were developed by Bonner & Moore from
previous studies. Several teams of Bonner & Moore personnel investigated the
impact of the schedules on differing facets of the petroleum industry. Their
investigations were coordinated into the findings presented in this report.
The Bonner & Moore groups worked closely with an EPA-organized project
team composed of Messrs. John O'Conner and Paul Boys from EPA, Michael J. Massey
from Carnegie - Mellon University and Lee H. Solomon, a partner of Turner, Mason
& Solomon. Mr. Solomon represented the EPA as an independent consultant in the
area of petroleum economics.
1.3 REPORT STRUCTURE
Following the brief introductory and background information presented
here and in the next section of this report, a summary of conclusions is pre-
sented (Section 3), then a discussion of the economic findings from each major
schedule studied (Section 4). Following this, Section 5 describes the study
methodology in detail.
For simplicity, the terms "TEL" and."lead" have been used throughout
this report in referring to lead alkyl additives. These terms should be inter-
preted as referring to all lead alkyl additives, including TEL and THL. Other
petroleum and refining terminology is defined in the Glossary, Appendix F.
RGH-015 Bonner & Moore Associates, Inc. '"'
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SECTION 2
STUDY SCOPE AND METHODOLOGY
2.1 SCOPE
1) Schedules Studied
The technical proposal for this study was originally prepared on
November 6, 1970, and specified a number of alternate gasoline lead
removal schedules for investigation. These schedules represented various
rates of lead removal.
Eleven proposal schedules were grouped into two classes, one related
to a two-pump marketing system, the other to a three-pump system. In all
cases one grade of gasoline was required to be lead free by 1974 to sat-
isfy the needs of any 1975 model cars equipped with exhaust reactors
requiring unleaded fuel. The octane level of this grade was originally
set at 91 RON in accordance with statements made by automotive manufac-
turers regarding future automotive requirements. In view of later
information obtained from industry sources, the EPA team shifted the
basic research octane level to 93, and specified that the impact of a 91
RON requirement be analyzed only indirectly through sensitivity analyses
of basic study results. Consequently, the modified contract for EPA
called for a study of the following two and three-grade systems :
n Three-Grade Marketing System
93 RON Low Lead Fuel (Unleaded After 1973)
94 RON Regular Grade (Varies from 0 to 3gm of lead/gallon)
100 RON Premium Grade (Varies from 0 to 3gm of lead/gallon)
a Two-Grade System
94 RON Low Lead Regular Grade (Unleaded After 1973)
100 RON Premium Grade (Varies from 0 to 3gm of lead/gallon)
2) Study Plan
The study plan called for a feasibility analysis of all eleven
schedules and a detailed analysis of those schedules bracketing the fea-.
sible ones. The feasibility analysis examined approximate capital
See Appendix A for a detailed listing of the eleven modified schedules.
RGH-015 Bonner & Moore Associates, Inc. 2-1
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costs, pool octane numbers, aromatics concentrations, prime blending
component requirements, and year-to-year rates of increase in gasoline
volume times octane.
A preliminary selection was made of the slowest and fastest lead
removal schedules for 3-grade cases and for 2-grade cases. Spot year
detailed analysis of all schedules was also determined to be necessary.
Early results showed that construction industry limits necessitated
the definition of two new schedules representing the fastest feasible
lead removal for each marketing system. These new schedules were cal-
culated by limiting year-to-year construction at the construction indus-
try capacity for that year.
The study results are hereafter discussed with reference to data
on four schedules. They are identified as follows:
Schedule Gasoline System Schedule Characteristic
A 3 grade Gradual removal of lead
L 3 grade Rapid removal of lead up to
construction industry limits
G 2 grade Gradual removal of lead
M 2 grade Rapid removal of lead up to
construction industry limits
3) Reference Schedule
During the 1971-1980 period covered by the RFP, there is an
"expected normal growth" in gasoline consumption as well as other prod-
ucts produced by the petroleum industry. Since the industry is presently
close to nominal capacity, this growth will call for substantial invest-
ment. In order to determine the economic effect of lead removal in this
environment, it was necessary to develop a reference schedule. This
reference schedule represents the economic consequences of the projected
growth, while assuming the operating environment prior to the lead issue;
i.e., a basic two-grade gasoline production and distribution system with
maximum lead concentrations of 3gm per gallon. The economic effects of
differing lead removal patterns were determined by comparison with the
reference schedule.
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2.2 METHODOLOGY OF STUDY
1) Study Techniques
The TEL removal schedules supplied by the Environmental Protection
Agency were expressed in terms of maximum allowable TEL content for each
gasoline grade in each calendar year through 1980. Initial work of the
study involved development of forecasts for light ends products, motor
gasoline, jet fuels, petrochemicals, and distillate and heavy fuels.
Demand patterns and TEL limitations were imposed upon mathematical refin-
ery models, along with projected industry capacities. Patterns of new
equipment construction and refinery operations were determined from the
model behavior.
Except for California, refineries of different sizes and geographic
locations react similarly to the reduction of allowable levels of TEL in
gasoline. Therefore, the refining industry (gasoline producing refineries
over 35 thousand barrels per day crude charge) was represented by two
linear programming models: one describing a representative California
refinery, and the other describing a representative refinery for the rest
of the nation. The response of "small" refineries (smaller than 30-35
thousand barrels per day crude charge) differs significantly from the
patterns exhibited by the balance of the industry, and these were handled
separately by techniques of analysis and extrapolation. Finally, that
segment of the refining industry not involved in the manufacture of gas-
oline was excluded from the modeling system. This segment is charac-
terized by refining facilities which do not include catalytic reformers
or catalytic cracking process units.
The basic study technique employed linear programming models because
of their inherent ability to seek out an economic optimum among the myriad
and conflicting choices of equipment selection, operating conditions,
intermediate feedstock allocation, and finished product blending. The
results of these case studies served as a basis for further analysis of
alternate schedules for conversion to unleaded gasoline.
2) Peak tear Phenomenon
Initial study of the various schedules disclosed a disconcerting fact
about their effect upon the process construction industry. Rapid lead
elimination programs require a major buildup of construction activity to
a sharp peak, followed by a shrinkage in construction business. As allow-
able lead levels are reduced, new refinery equipment must be built to replace
RGH-015 Bonner & Moore Associates, Inc. 2-3
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the octane quality formerly supplied by lead additives. At this same
time, the increasing proportion of the automotive population represented
by post-1971 cars (requiring lower octane gasoline) causes a gradual
reduction in the average leaded octane level of the gasoline. If lead
levels are reduced too rapidly, the refining industry must install equip-
ment sufficient to meet the higher average clear octane requirement of
an automotive population while a substantial proportion of pre-1971 cars
are still on the road. As time brings about further attrition of the
older cars, the average octane requirement of the automotive population
will decline, leaving the refining industry with surplus octane-producing
facilities and little incentive to order new process construction. These
factors can result in a significant process construction industry busi-
ness decline following the "peak year" and extending over several years.
Figure 2-1 shows a typical peak point situation occurring in 1974.
Such a peak point was found to exceed the maximum growth ability
forecasted for the process construction industry in all original two-
grade schedules and in the more restrictive three-grade schedules.
Because of this, two new schedules (L and M) were developed to represent
the most rapid lead-reduction programs possible within construction indus-
try capacity.
RGH-015 Bonner & Moore Associates, Inc.
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I Actual and Reported Refinery Construction Investment Thru 1972
Projected Refinery Investment CSchedule G)
Actual Process Construction Industry Capacity Required by
E',"'>'"",-'/;,•;<'-J Actual Process Cons
V>C-;l/}:V/ti.Vl Refining Thru 1972
Potential Process Construction Industry Capacity Available to
Refining
Annual Investment
($ Billions)
Year
*Effect of current depressed business
Figure 2-1. Peak Point Effect of Rapid Lead Reduction
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3) Pfe-Investment Cost Adjustments
When costing the new facilities indicated by the model solutions,
no attempt was made to cost the new investment in the specific unit
sizes indicated by the model solutions. Instead, investment costs were
charged as a pro rata fraction of the cost for average or typical size
refinery units of the types under consideration. For example, the typi-
cal size of a crude distillation unit was determined to be 70,000 bar-
rels per day. If, for a particular case, the model indicated that 7,000
barrels per day of crude distillation capacity was required, the model
refinery would be costed with l/10th of the construction cost of a
70,000 barrels per day crude unit, not with the estimated construction
cost of a 7,000 barrels per day unit. Logically, this might be consid-
ered equivalent to interpreting the solution as implying that, in the
year in question, l/10th of the U.S. refineries built "average" 70,000
barrels per day crude units. The installation of new equipment in an
individual refinery is, of course, a sharply discontinuous step function
when any individual piece of equipment 1s considered. Consideration of
all new construction within the industry tends to smooth this function
considerably, however. The 90% of refineries which presumably did not
build crude capacity in the example year would have contributed their
share to the overall industry construction pattern through the installa-
tion of other needed new equipment.
In practice, refining process capacity is planned and Installed to
recognize and accommodate three-to-five years of growth. Taken as a
whole, the capacity growth of the refining sector would appear to be a
relatively smooth function with time. For a specific refinery, however,
growth would actually occur as discrete changes. For this study, it was
assumed that the industry-wide smoothing (via the technique described in
the preceding paragraph) tends to reflect an industry capacity which
results in an industry excess no greater than that normally Installed.
RGH-015
Bomier & Moore Associates, Inc. 2-6
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SECTION 3
SUMMARY OF CONCLUSIONS
3.1 LEAD REMOVAL STRATEGIES
Inherent in the schedules which this study evaluates are certain strate-
gies for implementing lead removal. In summarizing the conclusions it is useful
to review what these strategies are. The fundamental objective of lead removal is
pollution abatement. Two kinds of automotive pollution are identified. One is
the pollution caused by emitting lead salts that are the oxidation products of
gasoline lead additives. The other is automotive gaseous emissions that create
undesirable levels of carbon monoxide and react photochemically to form smog and
ozone. This study is more directly concerned with the economics of the role of
gasoline in abating gaseous exhaust pollutants.
The main strategy for lead removal Is to create a "new grade" of gaso-
line. This new grade would have a lower octane rating and would be used in 1971
and later cars that would be designed for it. This new grade would provide the
principal medium for facilitating lead removal. Its lower octane makes lead
removal substantially less costly than removing lead from today's "conventional
grades", namely 94 octane regular and 100 octane premium.
A second strategy is to regulate the lead content of the new grade so
that it will be lead free by 1975. In this year it is expected that automobiles
equipped with emission abatement devices will be marketed. Current information
indicates these devices would be harmed by the presence of lead in gasoline.
Thus, the study premises provide that all automobiles manufactured in 1975 and
later will use the new grade of gasoline and that this new grade will be produced
without lead. It is further premised that owners of cars built between 1971 and
1974 would buy the new grade and conventional regular gasoline in a 50/50
ratio.
These first two strategies insure that all lead emissions will be elimi-
nated from automotive exhausts when the last 1974 automobile has been retired from
service. This is the slowest rate of lead elimination that was studied.
A third strategy is employed to further accelerate the rate of lead
removal after the first two strategies have been implemented. This strategy
involves regulation of the lead content of conventional grades of gasoline. If
the maximum lead content of these conventional grades is successively reduced by
regulation, then the date at which complete lead removal can be achieved will be
earlier than if attrition of pre-1975 automobiles were the only removal mechanism.
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3.2 MAJOR CONCLUSIONS
The important data which support study conclusions are summarized in
Table 1. Reference is made to comparisons between various numbers in this table
throughout the following discussion. The time reference for this table is nomi-
nally January 1, 1971. Conclusions about capital expenditures depend on a hypoth-
esis about when a formal lead removal program would be initiated. If it were on
January 1, 1972, for example, then the entire expenditure pattern would be shifted
by one year.
3.2.1 The Added Per-Gallon Cost of Lead Removal Is Not Large, But
The Added Total Cost is Significant
The added cost of removing lead from gasoline was calculated year-by-year
for each of the four schedules studied in detail. These added costs are expressed
in cents per gallon of total gasoline. Since the kinds of gasoline produced vary
from year to year, these costs also vary. However, the range of the highest
single-year-added-cost for the four schedules is between 0.234 per gallon for
Schedule A and 0.904 per gallon for Schedule L. This increase is in the order of
5% over present gasoline manufacturing costs. The total cost of lead removal is
substantially increased by the necessity to refine more gasoline because cars
designed to meet the 1975 air standards will have lower fuel economy. In this
study it has been assumed that a 12% loss in fuel economy would characterize cars
built in 1975 and later, assuming they are fully equipped with emission abatement
devi ces.
3.2.2 Rapid Lead Removal Requires Substantially More Capital Investment
Than Slow Lead Removal (See Figure 3-1)
The third strategy mentioned above, regulating the lead levels of conven-
tional gasoline grades, determines how much faster lead can be removed than if
attrition of older cars were the only removal mechanism. Schedules L and M repre-
sent the most rapid removal of lead possible within the limits of construction
capacity. Schedule A represents the slowest lead removal. Schedule L requires
approximately 140% more refinery capital investment than does Schedule A. It
should be noted, however, that the lead removal cycle is not totally complete in
1980 for Schedule A. Therefore, study conclusions tend to make A appear to be
slightly more economical than it would be when carried through to complete lead
removal. In order to assess whether this difference in capital requirement is
significant on an industry scale, it is necessary to make some judgment about cap-
ital availability for refinery investment. It is beyond the scope of this study
to examine this question in detail, but certain observations can be made that pro-
vide some perspective to these differences in investment requirements. The slow
removal of lead as typified in Schedule A does not produce a peak year effect.
Rapid removal of lead, as in Schedule L, produces a marked peak year effect. In
Schedule A the average added investment for the refining sector of the oil industry
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TABLE 1
STUDY RESULT SUMMARY
CHARACTERISTIC
1 . Added Invest-
ment (MM$
Above Refer-
ence) l »2
2. Total Added Cost
U per Gallon
Above Reference)
3. Percent Lead
Reduc t i on
(From 1970 Base)
4. Percent Crude
Increase (Above
Reference)
5. Process Industry
Construction
Activity (*
Increase over
Prior Year)
6. Clear Pool
Octane (RON)
7. Percent
Aromati cs
ULES
A
G
L
M
A
G
L
M
A
G
L
M
Ref
A
G
L
M
A
G
L
M
A
G
L
M
Ref
Pool A
G
L
M
Ref
93 A
L
94 A
G
L
M
Ref
100 A
G
L
M
Ref
SCHEDULE YEAR
1971
15
745
_
-
0.16
0.19
.
-
4
45
-
.
(3)
0.34
0.55
-
-
(4)
(2)
1
1
88.5
91 .8
-
.
88.4
22
28
-
-
23
18
-
19
33
-
-
23
32
18
-
-
22
72
„_
187
7983
7983
0.20
0.24
0.48
0.20
4
.
62
61
(18)
0.67
1.77
1.37
16
45
28
28
87.7
-
91.7
91.8
87.9
_
.
27
27
22
_
21
_
_
24
23
22
_
-
39
38
24
73
42
130
344
344
0.23
0.22
0.56
0.24
4
.
71
70
(26)
1 .37
-
-
12
37
18
18
87.5
-
-
_
-
_
.
.
-
-
_
-
_.
_
_
_
-
_
.
_
.
-
74
187
1348
412
412
0.22
0.56
0.62
0.31
4
75
80
78
(29)
1.80
3.80
2.76
3.25
4
(23)
14
17
87.7
93.6
92.9
93.0
87.6
_
37
32
31
21
_
28
_
42
29
30
21
_
11
45
37
22
75
122
145
825
825
0.22
0.53
0.85
0.51
7
.
92
89
(33)
1 .65
-
-
-
8
(2)
(1)
2
88.3
-
-
-
-
.
-
-
-
-
_
-
_
.
-
.
-
.
-
-
-
-
76
172
183
844
1073
0.21
0.51
0.90
0.68
11
_
100
99
(35)
2.42
-
5.03
5.91
9
4
(12)
(14)
88.5
-
94.4
94.7
88.6
24
38
39
22
32
39
20
.
35
40
21
12
-
53
37
22
80
1462
3226
3456
3728
0.21
0.36
0.60
0.43
44
95
100
100
(41)
3.16
3.93
3.29
3.98
7
7
7
7
90.4
93.9
93.5
94.2
87.9
29
38
36
38
22
34
42
18
39
21
39
21
13
11
33
33
24
'Excluding cost for Distribution.
21980 figures are Cumulative.
3Includes 1971 Investment.
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4.0
3.0
US
Refining
Cumulati ve
Investment
Above
Reference
($ Billions)
2.0
1.0
Figure 3-1. Cumulative Investment Requirements
for Schedules A, G, L and M
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is approximately $150 million dollars annually. For Schedule L the average annual
added investment for the critical first four years averages approximately $650
million dollars. It should be emphasized that these are not total annual invest-
ments but added annual investments to produce unleaded gasoline.
Refinery construction expenditures have historically exhibited a marked
cyclical pattern. For this reason it is difficult to say what represents an aver-
age annual expenditure. However, if expenditures for the years 1960 through 1972
(projected) were smoothed, an average expenditure rate for 1971 would be in the
order of $800 million dollars. During this same time period, refinery expendi-
tures have jumped as much as $300 million dollars in a single year. From this it
could be deduced that a $150 million dollar increase in annual refinery expendi-
tures could be accommodated within budget variations which oil companies have
employed in the past and therefore be considered within the limits of normal capi-
tal resource allocation. On the other hand, an annual expenditure jump of $650
million dollars sustained for 4 years is more than twice as great as previous
increases in refining expenditures. It therefore appears that a real capital
availability problem could exist.
3.2.3 Lead Removal Will Most Likely Be Accomplished Through Marketing
Three Gasolines
A study objective was to determine whether lead removal economics should
be based on the assumption of a three-grade or a two-grade gasoline marketing
pattern. Results show that slow lead removal as in Schedule A is more economical
if accomplished in a three-grade marketing pattern. On the other hand, rapid lead
removal is more economically accomplished in a two-grade marketing pattern.
The differences in added gasoline cost between three-grade and two-grade
schedules is small enough that other factors might dictate the actual marketing
practice. Approximately 65% of the total industry effort required to convert
fully to three-grade gasoline marketing has already been made or is committed.
A trend back toward two-grade marketing with unleaded gasoline will probably
require strong evidence that a consumer preference for this new grade is develop-
ing. For purposes of determining the cost consequences of lead elimination, the
use of three-grade economic results may be the more realistic.
3.2.4 Construction Industry Capacity Limits The Rate of Lead Removal
The original EPA schedules included several that cannot be met because
the construction industry cannot expand rapidly enough to accommodate the added
demand for new plants. Detailed examination of required investment patterns also
shows that rapid lead removal creates a major business cycle in this industry.
The downside of this cycle, occurring after thi peak year, would cause unemploy-
ment among engineers, technicians, and craftsmen. Schedule G shows the greatest
drop in activity, amounting to a business reduction of 23*. Translated into
employment figures this would amount to a decrease of about 10,000 jobs.
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3.3 ECONOMIC IMPACT
3.3.1 The Consumer
The consumer of motor gasoline will be directly affected in at least two
ways by a program to eliminate lead. These are the increased cost of a gallon of
unleaded gasoline and the additional volumes of unleaded gasoline required to
operate a car which is fully equipped with emission abatement devices. Of these
two effects,the loss in fuel economy is by far the greater. This loss in effi-
ciency is not attributed to the unleaded fuel, per se, but to the presence of the
emission abatement devices which in turn require the unleaded fuels.
Added costs for unleaded gasoline have been calculated by dividing the
total added manufacturing cost by the total quantity of gasoline produced. This
does not mean that this added cost would apply only to those motorists purchasing
unleaded gasoline. If the total added cost were divided by the unleaded gasoline
produced, then these added per-gallon costs would be substantially higher. Also,
the assumption is made that the pool of refined gasoline would continue to bring
the same average price, so no penalty is calculated due to eliminating the present
premium grade. The distribution of added costs might fall on consumers unequally
however, depending on how competitive pressures affect the actual pump pricing
patterns for premium, regular, and the new grade.
From Table 1 it can be seen that, although added costs vary as much as
two-fold, on a year-to-year basis the greatest added cost is only 0.90$ per gal-
lon. Therefore, the added consumer costs for making unleaded gasoline available
would represent an increase in his per-gallon cost at the pump of less than 3%.
At the same time it should be recognized that an opportunity for a gasoline price
increase, made possible by announcing regulations requiring the sale of unleaded
gasolines, might also result in additional price increases being announced at the
same time to cover other added refinery costs which, as of this date, have not
been passed on to the consumer.
If the consumer pays no more than 3% extra for gasoline produced without
lead, then clearly the most significant effect which the consumer will feel is the
loss in gasoline efficiency for the post-1975 cars. In this study a representa-
tive figure of 12% is used for this loss in efficiency. Therefore, the consumer
impact would be the need to buy 12% more gasoline costing as much as 3% more per
gallon. This amounts to an overall increase in gasoline cost to the consumer of
15% to 16%.
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3.3.2 Impact on the Domestic Petroleum Industry
The most significant impact of a lead removal program on the domestic
petroleum industry is the requirement that more capital be spent on refineries
over the next 10 years than would be required if the past pattern of expansion and
quality change were to continue. It should also be recognized that all refineries
built after 1980 to produce unleaded gasoline will continue to be more expensive
since they will be producing gasoline of a higher clear octane quality than that
produced by today's refineries. In addition, more raw materials must be supplied
if future cars meeting the clean air standards sustain the expected fuel effi-
ciency 1 oss .
It is perhaps as important to understand how uncertain the predictions of
refinery investment effects are as to note the effects themselves. The flexibil-
ity of a modern oil refinery to control the yield of various products makes it
virtually impossible to isolate economic effects of quite separate events. All
such events tend to have strong interactions. Currently, the planning for future
refineries is complicated by three major uncertainties. One of these is the ques-
tion of unleaded gasoline requirements, the subject of this study. Another is the
potential requirement to produce very low sulphur content fuels. The third
uncertainty derives from future changes in both the crude oil import regulations
and the regulations regarding importation of heavy fuel oils. The outcome of
deliberations on each of these points can affect the refining industry. It should
be particularly noted that each of these programs may require large capital expend-
itures when capital availability in the oil industry is of critical concern.
From an operating standpoint,refineries will need to modify their pro-
cesses to produce more aromatics. The technology to do this is widely used and
will simply be more extensively employed.
In addition to the refining sector, that part of the oil industry con-
cerned with di s-tributi on and sale of gasoline would also be affected by an
unleaded gasoline program. In calculating these effects, an important assumption
has been made that the regulation of lead content for unleaded gasolines would not
require a completely different mode of operation in distribution than exists at
present. This would not be possible if, for example, unleaded gasoline were
required to be absolutely free of contamination from leaded fuels. If this were
the case, then segregated systems for handling unleaded fuels would be required
and these costs would substantially exceed those that have been calculated in this
study. This qualification would obviously no longer apply after the transition
period had been completed and the only gasoline grades being sold were unleaded.
The impact of an unleaded gasoline program on gasoline distribution is
significant only when it is required to sell an extra grade of gasoline. In this
study two marketing plans have been examined. One is a conventional two-grade
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marketing system in which the new grade would be produced at regular gasoline
octane and the normal regular grade would be dropped. The other involves adding
the new grade to an existing two-grade structure.
The cost for converting the entire U.S. gasoline distribution and market-
ing system to three grades 1s estimated at $1.294 billion dollarst. This invest-
ment is required for Schedules A and L. In fact, however, many of the major U.S.
marketers either market three grades or have scheduled the construction of facil-
ities to permit nation-wide three-grade marketing.
3.3.3 Impact on the Process Construction Industry
The U.S. capability to build new refinery units poses a hard limit to the
rate at which lead can be removed from gasoline. The lead removal program will
increase construction business during the 10-year period covered in this study.
Accelerating the rate of lead removal potentially creates a business cycle in this
industry sector, however. This occurs for the same reasons that give rise to the
peak year phenomenon discussed earlier. This peak year phenomenon affects the
construction industry by requiring an over-building of octane production facili-
ties prior to the peak year. After the peak year, new construction is virtually
limited to increasing crude oil capacity to meet growing demand. Capacity of the
more expensive refinery process units, mainly those concerned with conversion and
octane upgrading, will exceed requirements for several years as pool octanes
decline after the peak year.
The process construction industry obtains business from three major
sources. One is refinery construction. Another is chemical plant construction.
The third is foreign engineering and construction of both refineries and chemical
plants. If construction work from the chemical and foreign sectors follows a
predictable pattern of growth and the refinery construction load is added to this
base, lead removal according to Schedule L would result in a business cycle of
approximately 4-years duration amounting to a business loss of 20% in the first
year of the cycle. The slowest rate of lead removal, represented by Schedule A,
does not show a peak year effect nor does it show a tendency toward generating a
business cycle.
Due to the inherent lag time in building process capacity, i.e., accepted
bid to accepted plant, it was assumed in the construction analysis that (a) the
1971 and 1972 capacities could not be significantly altered by decisions made in
late 1971, and that (b) the projected refinery investments as reported in the Oil
and Gas Journal26 would serve as a base. Therefore, differences in investment
requirements for the schedules studied were assumed to be zero .in years 1971 and
Lower estimates of this figure have been published but appear not to include all
the cost components determined in this study.
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1972. Actually, construction wiich will permit increasing gasoline octane has
been announced for 1970 and 1971 in excess of $100 million. The added costs for
1971 and 1972 reflect an estimate of the cost of capacity being presently built
which, in total or in part, has been justified for the production of unleaded
gasoline.
3.3.4 Impact on Petrochemical Costs
The removal of lead additives from gasoline, according to virtually any
of the schedules studied, should no.t have any significant long-term effect on
petrochemical costs. Calculated incremental costs for producing aromatics varied
erratically from schedule to schedule without showing any definite pattern. The
size of variations was in the +_ 10% range. The relatively low octane of the
unleaded grade and the expected percentage decline of refinery gasoline yields
alleviate the potential problem of rising aromatics cost.
The impact of unleaded gasoline on aromatics costs is very sensitive to
pool octane number. If unleaded gasoline octanes were to rise above the 93 level
used in this study, a rapid aromatics cost increase would follow.
During the early years of a schedule such as L or M, the aromatics market
might become unsettled. During these years aromatics production capacity would be
substantially increased. This could result in large spot imbalances between this
capacity and aromatics demand. Similar situations have historically led to price
instabi lities.
The impact of an unleaded gasoline program on the cost of light olefins,
such as ethylene and propylene, can be expected to be insignificant for two rea-
sons. The most important reason is that investment costs can be expected to pre-
dominate in setting price trends. During the 10-year period encompassed by this
study, the traditional olefin feed stocks in the U.S. will be insufficient to meet
new demands. Consequently, heavier feeds must be employed in new olefin units,
and it is most likely that these heavy feeds will come predominately from gas
oils. The value of by-product gas oils from the refinery is not as sensitive to
the refinery pool octane as are streams which blend directly into gasoline.
3.3.5 Impact on Leaded Gasoline Composition (See Figures 3-2 and 3-3)
Rapid lead removal schedules require the production and blending into
gasoline of more aromatics. Increasing aromatics concentration in gasoline to be
used in cars without exhaust reactors (pre-1975 cars) may increase exhaust gas
reactivity. Further research on this matter is under way. If the findings of
Eccleston and Hum31 are confirmed, then the higher aromatics content gasoline
will aggravate the photochemical smog problem.
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Lead Aromatics
(Thousands (Millions
of Tons ) of Barrels}
200 -i 800 -
150 -
100 -
50 -
600
400
200
0-1 0
SCHEDULE A
71 72 73 74 75
Year
O— Lead
D — Aromatics
76 77 78 79 80
SCHEDULE L
200 -i 800
150 -
100 -
50 -
600
400
200
0-1 0
71 72 73
74 75
Year
76 77 78 79 80
Figure 3-2. Aromatics and Lead Levels for Three-Grade System
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Lead Aromatics
(Thousands (Mi 1li ons
of Tons ) of Barrels;
SCHEDULE G
200 -) 800-
150 _
100 -
50 _
0 J
600.
400-
200-
71 72 73
i
74
75
Year
O
D
Lead
Aromat i cs
76 77 78 79 80
SCHEDULE M
200 -.
150-
100-
50-
0-1
800-
600.
400-
200-
71 72 73 74
75
Year
76 77 78 79 80
Figure 3-3. Aromatics and Lead Levels for Two-Grade System
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3.3.6
Impact on the Small Refiner
Small refiners have an inherent disadvantage in competing with large
refiners. This tends to be more pronounced than in other types of manufacturing,
Petroleum refining is very capital intensive and economies of scale in building
large units substantially affect total manufacturing costs. Table 2 shows how
typical Investment economics affect refiners of smaller size than the nominal
100,000 barrel refinery used as an example 1n the study.
TABLE 2
COMPARISON OF INVESTMENT TO CAPACITY RATIOS
(Relative to 100,000 Bbl/Day Refinery)
REFINERY THROUGHPUT
BBLS/DAY
100,000
50,000
30,000
10,000
RELATIVE
CAPACITY
1.000
1.32
1.63
2.5
UNIT
COST
Small refineries have operated at a cost disadvantage for many years.
During the past twenty years the number of such refineries has dwindled from 155
to 74. The trend of increasing gasoline octane has accentuated this disadvantage,
and further octane increases that would be characteristic of a lead removal pro-
gram would accentuate the differences still further. Certain financial assistance
is presently provided the small refiner by the sliding scale feature of the crude
oil import quotas and by the provisions that guarantee small refiners access to
government petroleum procurements.
A lead removal program will place small refiners in a precarious compet-
itive position as illustrated by data in Table 3. This table shows how added
costs for small refiners compared to added costs for the example 100,000 barrel a
day refinery in one year of each of the four schedules. If the viability of
small refinery operation is to be preserved, further financial assistance will
have to be granted to this industry segment.
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TABLE 3
INCREASED MANUFACTURING COST VERSUS REFINERY SIZE
(Cents Per Gal 1 on)
THROUGHPUT
BBL/DAY
100,000
50,000
30,000
10,000
THREE GRADES
A
0.21
0.24
0.26
0.33
(1976)
L
0.90
1.05
1.13
1 .40
TWO GRADES
G
0.51
0.59
0.64
0.79
(1974)
M
0.68
0.79
1 .18
1 .78
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SECTION 4
DETAILED STUDY RESULTS AND CONCLUSIONS
The four schedules selected for Intensive study (see Section 2) are dis-
cussed in detail in this section of the report. An analysis of the impact upon
distribution costs is first presented in paragraph 4.1. Each of the schedules,
A, L, G, and M, is described in paragraphs 4.2 through 4..5 in terms of the result-
ing process conditions, capacity changes and gasoline blending situations for the
selected periods.
Paragraph 4.7 presents the results of a series of sensitivity analyses
performed on these results. The effect of these schedules upon the small
refiner's costs is described in paragraph 4.8 with other implications of lead
removal for the small refiner. Paragraph 4.9 describes the impact upon engineer-
ing and construction activities. Implications and conclusions about the effects
of lead reduction on petrochemicals are presented in paragraph 4.10, and finally,
selected results from the California model extrapolations are presented in para-
graph 4.11.
In presenting these results, it is convenient to use refinery terminology
and to talk about effects in terms of the single refinery model that was employed.
Many of the simplifying assumptions employed in modeling are not valid for unique
situations, however. Although most of the effects have been extrapolated to rep-
resent national quantities, it would be incorrect to extend certain detail and a
serious mistake to extend other results. Because the study procedure was designed
to measure "industry" effects, it 1s recommended that the reader neither attempt
to draw additional conclusions nor apply these results to specific refining
si tuati ons.
In order to simplify the description of the gasoline blends for the
selected years of each selected schedule, the components have been grouped into
stocks that would be produced by a particular kind of process and have thus
arrived at 6 categories of gasoline blending stocks. These are cracked stocks
(coming from catalytic cracking), alkylate products including propylene, butylene,
and pentylene alkylates, aromatic stocks such as reformates and extracted aromat-
ics , light iso-paraffins , (particularly iso-butane, iso-pentane and iso-hexane),
paraffinic stocks (made up primarily of virgin gasolines and raffinates) and
finally a miscellaneous category including such things as thermally cracked gaso-
lines and visbreaker gasoline. In addition to this stream type composition, the
hydrocarbon type analysis of each blend has also been shown.
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4.1 LEAD REMOVAL DISTRIBUTION COSTS
This analysis developed cost projections for the gasoline distribution
facilities changes which would be required by the various proposed lead removal
schedules.
Three-grade lead removal schedules affect the gasoline distribution sys-
tem because marketing a third grade requires additional tanks and pumps in sta-
tions which previously marketed only two grades. Service stations, including
other retail businesses which sell gasoline, are the most critical element in the
distribution system because of the large number of these installations that may be
involved. Other important elements are the bulk stations and terminals and the
transportation fac11ities--pipelines , barges, tankers and tank trucks.
4.1.1 Input Data Description - Sources, Premises1'2
There are over 356,000 branded outlets in the United States, of which
222,000 are service stations. A service station receives over half of its sales
revenues from petroleum products—other outlets receive less than half. For this
analysis the term "service station", or "station", refers to branded outlets in
general unless specifically stated otherwise.
A number of companies have already gone to three-grade marketing or have
announced their commitment to go to three grades by the end of 1971. Their deci-
sion to go to three grades may have been totally independent of lead-removal dis-
cussions or may have been made on the assumption that three grades would ultimately
be requi red .
To aid in the projection of costs to accomplish the different lead-
removal schedules, petroleum companies have been classified into four groups1':
n Historical three-grade marketers who added a third grade of gasoline
before lead removal became an item of concern.
n Three-grade marketers converting primarily in 1970-71 by adding
a third, no-lead or low-leaded grade of gasoline.
a Two-grade marketers who will convert to three grades if government
regulations favor a three-grade schedule. Marketers who stock two
grades and blend the third are in this group.
n Two-grade marketers who will continue to market only two grades,
choosing the best two out of three grades if a three-grade schedule
is favored.
'Appendix 0 lists the companies in each of these groups.
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1 ) Service Station Conversion Cost
The cost to convert a station to three-grade service is based upon
the installation of a new tank and two dispensers with pumps, and the
modification of two islands plus associated piping, structural and elec-
trical work. The cost is a weighted average cost per station that con-
siders the number of stations by region and the building cost index for
that region. Using these factors, a typical conversion cost for a Gulf
Coast marketer, $7,350, becomes $8,030 for the United States as a whole.
These figures are derived in the following manner:
Cost of tank (assumed 10,000 gal fiberglass $1,500
or coated steel)
Excavation and backfill 1,400*
Dispensers with suction pumps - 2 per station 1,050
Piping and trenching 1,400*
Conversion of 2 islands 2,000
Total investment per station (Gulf Coast) $7,350
*$4800 subtotal adjusted for construction cost
variations over U.S. (avg. 1 4.183! increase) 680
*
Average investment per station (U.S.) $8,030
2) Distribution Terminal Conversion Cost
The cost to convert a terminal is the cost of a new tank plus asso-
ciated pumps and piping. These are estimated to require $150,000 per
terminal. In general, bulk stations will not need additional tankage.
When converting from leaded to lead-free gasoline, special cleaning
of tanks is not considered necessary. Routine and regular cleaning for
other purposes, plus a transition period when lead-free fuel will mix
with any leaded fuel that may still be in the tanks, are assumed to
prevent any unacceptable lead levels in the gasoline after the transition
period.
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4.1.2 Methods of Analysis and Extrapolation
Group 1 companies are those marketing or having facilities to market
three grades of gasoline prior to 1970. These include Gulf, Humble, Standard of
California, Standard of Kentucky and a part of Phillips. Group 2 companies have
made public announcements about their intentions to market three gasoline grades
in 1970-71. The remaining majors are in group 3, and it is assumed that they
also will go to three grades if a three-grade schedule is chosen. The remaining
independents are in group 4, and it is assumed that they will remain two-grade
marketers regardless of the two-grade vs. three-grade decision.
The historical terminal growth data of 1963 through 1967 were projected
to 1971, resulting in an estimated 1902 terminals. This number is proportioned
to the four groups in the same proportion as the current number of stations in
each group. An estimated 40% of the terminals will need additional tankage.
The relation of announced station conversions to the total number of
stations for the same companies results in a conversion rate of 65.8% of total
stations. This percentage is used to estimate the number of station conversions
i n groups 1, 2 and 3.
Some two-grade stations may have sufficient dispensers and/or tanks to
permit their conversion to three-grade stations at less than the $8,030 per sta-
tion used in this study. Because an extensive survey would be required to deter-
mine the number of such stations, estimated conversion costs may be overstated.
New station construction is assumed to be 4,000 per year. Assuming
65.8% are three-grade facilities, and applying an incremental cost of $8.030
more than two-grade facilities, the additional cost per year is estimated to be
more than $21 million. New, three-grade stations are assumed only for four years
(1972-75) because after 1975 the projected demand for 100 octane gasoline will
fall below 10% of total demand, which should reduce incentive to build additional
three-grade stations after this time.
In summary, the estimated investments are as follows:
1) Group 1 investments (prior to 1970) $510 million
(not included in schedules)
2) Group 2 investments (already committed) $746 million
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3) Group 3 costs (applies to three-grade schedules) $463 million
4) New construction (applies to three-grade $ 85 million
s chedules)
Previously Committed Investment
to go to Three-Grade (Group 2) -- -- $746 million
Future Investment Required for
Group 3 Companies and New
Construction for Three-Grade
Over Two-Grade Systems $548 million
Distribution Facilities
Investment Required for
Marketing Third Grade of
Unleaded Gasoline $1294 million
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4.2
SCHEDULE A
4.2. 1
Description of Schedule
Lead removal Schedule A is for a three-grade marketer in which the lowest
octane grade (93.0 RON) is permitted to have 0.5 gm of lead additive per gallon
until 1974, at which time all lead is removed from it. The grades corresponding
to current regular and premium gasolines are permitted to contain lead throughout
the schedule.
4.2.2
Reason for Selecting Schedule A for Study
Schedule A was selected for study because, of all the schedules offered,
it obviously had the smallest impact on the refining industry. It represents the
minimum cost route (to the refiner) for providing lead-free gasolines for automo-
biles manufactured post-1974.
4.2.3
Raw Stock Effects
The mildness of this schedule is illustrated by the small difference in
total raw material usage compared to the reference schedule. However, this dif-
ference increases in the later years of the schedule as the unleaded grade becomes
the dominant grade. Table 4 shows the raw stock usage of Schedule A and the ref-
erence schedule in terms of crude oil natural gasoline and butanes.
TABLE 4
RAW STOCK REQUIREMENTS FOR SCHEDULE A
(Millions of Barrels/Year)
Normal Butane
Iso-Butane
Natural Gasoline
Sub-Total
Crude Oi 1
Total
SIncrease in Crude
1971
A
68.5
49.4
192.9
310.8
4384.9
4695.7
Reference
66.6
48.0
192.9
307.5
4369.7
4677.2
1976
A
80.0
57.7
192.9
330.6
5548.2
5878.8
Reference
79.8
57.3
192.9
330.0
5417.3
5747.3
1980
A
92.7
66.7
192.9
352.3
6764.0
7116.3
Reference
79.8
57.4
192.9
330. 1
6557.1
6887.2
0.34 2.42 3.16
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There are two factors causing the increased need for raw stocks. One,
the need for replacement of material converted to low valued fuels, is caused by
the more severe processing needed to raise unleaded pool octane. The other is the
increased volume of gasoline required to compensate for inefficiencies of low
compression ratio engines and for mileage penalties resulting from exhaust gas
recycling required to control oxides of nitrogen emissions
30
Without a complete
exploration of the volume-quality effects, it 1s impossible to identify how these
two factors contribute to the total Increase in raw stock requirements.
A partial answer to the increased severity contribution can be obtained
by, comparing the fuel gas and coke productions for Schedule A and the Reference
Schedule. These are presented in the next section. The volume increase contri-
bution is reviewed in the volume sensitivity discussion of paragraph 4.7.
4.2.4
Dy-Product Effects
The increased severity of processing, mentioned above, is further illus-
trated by the increased production of fuel gas and coke (both variable products).
These are shown in Table 5 along with the reference figures.
TABLE 5
BY-PRODUCT PRODUCTION FOR SCHEDULE A
Coke, Thousand Tons/Year
Fuel Gas Trillion BTU/Year
1971
A
14.3
1220
Reference
14.1
1195
1976
A
24.8
1584
Reference
23.8
1528
1980
A
37.5
2066
Reference
36.1
2070
The lower production of fuel gas (Schedule A versus Reference Schedule)
in 1980 is a consequence of the relatively mild demand for quality imposed and
the volume expansion achieved with hydrocracking. As shown in Tables 8 and 27,
the 1980 hydrocracking capacity Is an estimated 1.6 million barrels per day com-
pared to 900 thousand barrels per day for the reference schedule case.
8GH-015
Bonner Ac Moore Associates, Inc.
4-7
-------
4.2.5
Motor Gasoline Blending
Table 7 shows the characteristics and composition of each of the three
gasoline grades as well as pertinent pool (composite) properties. It is inter-
esting to note that forcing the 93 grade to be unleaded in 1974 did not require
the maximum of 3.0 gm/gal in the remaining grades until 1975. Table 6 presents
the TEL levels for each grade for each year.
TABLE 6
TEL CONTENTS OF SCHEDULE A GASOLINES
(gm/gal)
Grade
93
94
100
Pool
1971
0.5
2.1
2.3
2.0
1972
0.5
2.2
2.5
2.0
1973
0.5
2.3
2.7
1.9
1974
0
2.5
2.8
1.8
1975
0
2.6
3.0
1 .7
1976
0
2.7
3.0
1.6
1977
0
2.7
3.0
1 .3
1978
0
2.7
3.0
1 .1
1979
0
2.8
3.0
1.0
1980
0
2.8
3.0
0.9
The 1971 pool lead content for Schedule A is in part caused by 6.5% of
the pool being the 93 grade. However, both the 94 and 100 grades, neither of
which was restricted in lead content, were also low relative to the Reference
Schedule (see Table 29). This stems from the lower pool clear octane of Schedule
A in 1971 because of the adherence to car population octane requirement for
Schedule A and overbuying exhibited by present premium-to-regular ratios (see
paragraph 5.3) imposed in the Reference Schedule.
4.2.6
Process Capacity Changes
Table 8 shows the in-plant capacities for major processes for selected
years. No overbuilding of capacity was allowed. The added capacities for Sched-
ule A are only slightly greater than those in the reference case (see Table 28).
The capacity under 1971, 1976 and 1980 represents the required capacity for that
year. For example, crude distillation capacity increased by 3,200,000 B/D to
reach the 15,200,000 B/D shown for 1976. This increase for 1972 through 1976 is
about 600 B/D per year. It should be noted that the capacities shown do not rep-
resent any surplus capacity (except the usual service factor, assumed in this
study to be 93%).
RGH-015
Bon tier Ac Moore Associates, Inc.
4-8
-------
TABLE 7
GASOLINE SUMMARY FOR SCHEDULED
(Sheet 1 of 2)
93 Octane Blend:
Volume, 109 Gals/Year
TEL, Gm/Gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf f i ns
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, %
Paraffi ns
Olefins
Naphthenes
Aromati cs
94 Octane Blend:
Volume, 109 Gals/Year
TEL, Gm/Gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi seel 1 aneous
Hydrocarbon Composition, %
Paraffi ns
Olefins
Naphthenes
Aromati cs
1971
6.2
0.50
93.0
85.0
89.9
81 .0
48
19
14
1
11
7
49
22
11
18
55.8
2.10
94.0
86.0
85.6
77.8
48
5
17
-
27
3
46
22
13
19
1976
47.4
0
-
-
93.0
85.0
9
18
50
9
14
-
58
5
5
32
50.9
2.68
94.0
86.0
84.3
76.8
45
-
18
-
32
5
46
20
14
20
1980
88.4
0
-
-
93.0
85.0
11
16
48
7
17
1
55
6
5
34
35.9
2.77
94.0
86.0
83.9
76.8
59
-
-
-
38
3
45
23
14
18
RGH-015
Bonner & Moore Associates, Inc.
4-9
-------
TABLE 7
GASOLINE SUMMARY FOR SCHEDULE A
(Sheet 2 of 2)
100 Octane Blend:
Volume, 109 Gals/Year
TEL, Gm/Gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromati c Based
Light Iso-Paraffins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, %
Paraffi ns
Olefins
Naphthenes
Aromati cs
Pool:
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi s eel 1 aneous
Hydrocarbon Composition, %
Paraffi ns
Olefi ns
Naphthenes
Aromati cs
RON Clear
MON Clear
1971
29.8
2.29
100.0
93.0
94.5
84.5
-
25
54
9
12
-
66
-
2
32
35
11
27
3
22
2
52
16
10
22
88.5
80.0
1976
13.4
3.00
100.0
92.2
90.8
81.9
38
35
9
-
18
-
65
16
7
12
29
11
31
4
23
2
53
13
10
24
88.5
80.9
1980
4.1
3.00
100.0
92.0
90.9
81.9
40
34
8
-
18
-
63
17
7
13
25
12
34
5
23
1
53
11
7
29
90.4
82.6
RGH-015
Bonner & Moore Associates, Inc.
4-10
-------
TABLE 8
PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE A
Crude Distillation
Coki ng
Cat Cracking
Hydrocracki ng
Cat Reforming
Alkylation
Extracti on
Isomerization
Millions of Barrels/Day
1971
12.0
0.8
3.6
0.6
2.2
0.8
0.3
0.1
1976
15.2
1.4
3.6
1.1
3.0
0.9
1.2
0.1
1980
18.5
2.0
3.6
1.6
3.8
1.2
1 .5
0.1
4.2.7
Cost Effects
Table 9 shows the annual cost for Schedule A relative to the Reference
Schedule. Added costs are broken down into refining investment costs, other
refining costs and distribution investment costs. These costs are shown both as
millions of dollars per year and as cents per gallon of total gasoline.
The "other" refining cost category represents the net effect of increase
in operating costs, raw stock costs and product degradation costs plus credits
for decreased lead usage and by-products. Included in this cost is the effect of
assuming constant value per barrel of gasoline even though the subject case is
not the same ratio of premium and regular as in the reference case.
RGH-015
Bonner & Moore Associates, Inc.
4-11
-------
TABLE 9
COST EFFECTS OF SCHEDULE A
National Added Costs, MM$/Yr.
Refining Investment Costs
Other Refining Costs
Total Added Refining Cost
Added Distribution Costs
Total Added Cost
National Added Cost, if/Gal*
Refining Investment Costs
Other Refining Costs
Total Added Refining Cost
Added Distribution Costs
Total Added Cost
1971
4
(21)
(17)
170
153
(0.03)
(0.03)
0.19
0.16
1972
(69)
(69)
255
186
(0.08)
(0.08')
0..28
0.20
1973
15
(130)
( 1 1>5 )
740
225
0.02
(0.13.
(0.11
0.34
0.23
1974
64
(178)
('114)
340
226
0.06
(0.17)
(0.11)
0.33
0.22
1975
96
(214)
(118)
340
222
0.09
(0.19)
(0.10)
0.32
0.22
1976
141
(250)
(109)
340
231
0.13
(0.22)
(0.09)
0.30
0.21
1977
214
(316)
(102)
340
238
0.18
(0.26)
(0.08)
0.29
0.21
1978
263
(3b3)
(90)
340
250
0.22
(0.29)
(0.07)
0.28
0.21
1979
326
(407)
(81)
340
259
0.26
(0.32)
(0..06)
0.27
0.. 21
1980
383
(441)
(58)
340
282
0.30
(0.35)
(0.05)
0.26
0, 21
*Using total gasoline demand as a divisor.
D
0
3
3
re
•t
3
0
0
1
(5
-------
4.3 SCHEDULE L
4.3.1 Description of Schedule
Schedule L is a lead removal schedule for a three-grade marketer. It
removes lead from all grades of gasoline as quickly as possible within th« pro-
jected growth capacity of the construction industry. It was developed as a
replacement for Schedule E of the original RFP when it was discovered that the
amount of process construction implied by Schedule E exceeded the capability of
the construction industry. The 93.0 Research Octane grade was required to be
clear in 1974.
4.3.2 Reason for Selecting Schedule L for Study
Original study plans called for a detailed study of the extreme
('easiest' and 'most difficult1) schedules for the two-grade and three-grade mar-
keters. The effects of intermediate schedules could then be estimated by inter-
polation. It was anticipated that Schedule E would represent the 'most difficult'
schedule for the three-grade marketer. After some preliminary work with Schedule
E, it was decided to replace it with a new schedule which did not exceed the
estimated capabilities of the construction industry but, at the same time, removed
lead from gasoline as rapidly as possible. Schedule L fulfills this criterion.
4.3.3 Raw Stock Effects
Where subjected to the requirement of minimizing TEL in gasoline, the
model shows the expected result of requiring more raw stock than in a less
restrictive schedule. Both Schedules L and M (discussed later in this section)
utilize more crude oil and natural gasoline than either Schedule A or G. Table 10
presents the raw stock requirements for Schedule L as well as those of the refer-
ence case. It is apparent from these figures that lead removal requires increased
raw stock consumption.
Compared to Schedule A in 1976 (see Table 4), Schedule L requires more
crude oil and total raw stock, but not as much natural gasoline and butanes. Even
though the reference schedule shows a decline in natural gas liquids utilization,
the principal action causing the decrease is the internal production of light
hydrocarbons, thus reducing the need for outside purchase. The drop in percentage
crude increase in 1980 from 1976 is the result of the decrease in both 94 and 100
octane gasoline grades in that period. Compared to the behavior of Schedule A,
Schedule L exhibits the marked effect of producing all gasoline without lead by
1976.
RGH-015 Bonner & Moore Associates, Inc.
-------
TABLE 10
RAK STOCK REQUIREMENTS FOR SCHEDULE L
(Millions of Barrels/Year)
Normal Butane
Iso-Butane
Natural Gasoline
Sub-total
Crude 011
Total
% Increase In Crude
1972
L
92.6
66.7
192.9
352.2
4634.5
4986.7
1
Reference
69.8
50.2
192.9
312.9
4553.7
4866.6
77
1974
L
68.5
49.3
192.9
310.7
5090.9
5401.6
2
Reference
81.6
58.7
192.9
333.2
4954.4
5287.6
76
1976
L
86. 1
62.0
76.5
224.6
5689.8
5914.4
5
Reference
79.8
57.3
192.9
330.0
5417.3
5747.3
03
1980
L
92.6
66.7
162.3
321 .6
6772.9
7094.5
3
Reference
79.8
57.4
192.9
330.1
6557.1
6887.2
29
4.3.4
By-Product Effects
Table 11 presents a comparison of the fuel gas and coke production for
Schedule L and the reference schedule. Because fuel oil demand was held constant,
coke production is correlated closely with crude oil run. However, fuel gas pro-
duced is related more to overall refinery severity. This is readily apparent when
comparing this schedule with both Schedule A (Table 5) and Schedule G (Table 17).
TABLE 11
BY PRODUCT PRODUCTION FOR SCHEDULE L
Coke ,
MMTons/Year
Fuel Gas ,
1012BTU/Year
1972
L
16.6
1710
Reference
15.8
1268
1974
L
20.8
1825
Reference
19.5
1360
1976
L
26.2
2055
Reference
23.8
1528
1980
L
37.2
2079
Reference
36.1
2070
RQH-015
Bonner & Moore Associates, Inc.
4-14
-------
4.3.5
Motor Gasoline Blending
Table 12 presents the lead concentration of each of the three grades for
each year examined under Schedule L. The relatively low TEL levels in each grade
(as early as 1972) emphasize the fact that TEL reduction becomes increasingly
difficult and costly as concentrations approach zero. This is further emphasized
where one observes the gradual decrease in TEL levels from 1972 to 1976 when all
three grades finally are forced to be made without TEL.
TABLE 12
TEL CONTENTS OF SCHEDULE L GASOLINES*
(gm/gal)
93 Octane Grade
94 Octane Grade
100 Octane Grade
Pool
1972
0.4
0.9
0.7
0.8
1973
0.4
0.7
0.3
0.6
1974
0.0
0.5
0.3
0.4
1975
0.0
0.2
0.3
0.1
1976
0.0
0.0
0.0
0.0
'"'All grades unleaded after l'J75.
The lower lead levels shown for the 100 grade gasoline compared to the
94 grade gasoline in 1972, 1973 and 1974 result from the fact that premium level
octane is derived from components which show less response to lead additives than
those which will satisfy the lower quality grades. In 1975, premium shows
slightly more lead than the 94 grade because the emphasis is beginning to shift
from Research Octane to Motor Octane limitation and the lead response octane
level balance shifts slightly.
Table 13 presents the characteristics of Schedule L gasolines for
selected years. As can be seen from the pool composition data, there is a strong
(inverse) relationship between gasoline aromaticity and TEL content. It also
shows the benefit of small amounts of TEL compared to unleaded fuels. It appears
that TEL reduction at low concentration requires about 3 barrels of aromatics
(replacing 3 Bbls of non-aromatics) per pound of TEL eliminated.
RGH-015
Bonner & Moore Associates, Inc.
4-15
-------
TABLE 13
GASOLINE SUMMARY FOR SCHEDULE L
(Sheet 1 of 2)
93 Octane Blend:
Volume, 109 Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi seel 1 aneous
Hydrocarbon Compos i tion , %
Paraffins
Olef ins
Naphthenes
Aromati cs
94 Octane Blend:
Volume, 109 Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromati c Based
Light Iso-Paraffins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composi ti on, %
Paraf f i ns
Olefins
Naphthenes
Aromati cs
1972
11.9
0.398
93.0
85.0
90.9
81.4
49
11
18
13
8
1
50
21
8
21
55.8
0.902
94.0
86.0
89.2
80.1
43
9
26
-
21
1
51
18
7
24
1974
22.4
0.0
-
-
93.0
85.0
28
19
26
14
13
-
54
12
6
28
60.8
0.523
94.0
86.0
91.0
81.5
41
9
29
1
20
"
47
17
7
29
1976
47.4
0.0
-
-
93.0
85.0
38
6
23
16
16
1
44
11
6
39
50.9
0.0
-
-
94.0
86.0
23
20
39
-
18
—
48
13
4
35
1980
88.4
0.0
-
-
93.0
85.0
26
5
39
3
26
1
41
10
7
42
35.9
0.0
-
•
94.0
86.0
24
31
23
16
6
"
64
12
3
21
RGH-015
Bonner & Moore Associates, Inc.
4-16
-------
TABLE 13
GASOLINE SUMMARY FOR SCHEDULE L
(Sheet 2 of 2)
100 Octane Blend:
Volume, 10 9Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf fins
Paraffinic Stocks
Mi s eel 1 aneous
Hydrocarbon Composition,*
Paraf f i ns
Olefins
Naphthenes
Aromati cs
Pool:
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi seel 1 aneous
Hydrocarbon Composi ti on, %
Paraffins
Olefins
Naphthenes
Aromati cs
RON Clear
MON Clear
1972
26.0
0.674
100.0
92.4
98.4
87.8
_
27
57
9
7
-
58
-
3
39
34
14
32
3
16
1
52
15
6
27
91.7
82.2
1974
19.3
0.329
100.0
92.0
99.2
89.6
-
23
54
12
. 9
2
51
-
4
45
32
13
32
5
17
1
49
13
6
32
92.9
83.7
1976
13.4
0.0
-
-
101.4
92.0
_
19
53
8
20
-
47
-
-
53
27
14
34
7
17
1
46
11
5
38
94.4
86.3
1980
4.1
0.0
-
-
100.7
92.0
18
40
33
-
9
-
67
-
-
33
25
13
34
7
20
1
48
10
6
36
93.5
85.5
RGH-015
Bonner & Moore Associates, Inc.
4-17
-------
4.3.6
Process Capacity Changes
Table 14 shows the major process plant capacities for the selected years
of this schedule. These can be compared to the reference schedule capacities
shown in Table 27. Development of Schedule L was restricted to use processes
that 'were shown to be needed in 1976. In other words, the models were not per-
mitted to employ processes in early years that were not selected in 1976 (the
peak year). Doing so caused certain justifiable processes to be ignored. As
explained in paragraph 5.1, this procedure is believed to be more representative
of planning practices than one imposing no look-ahead.
TABLE 1i
PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE L
Crude Distillation
Coking
Cat Cracking
Hydrocracki ng
Cat Reforming
Al kylati on
Extracti on
Isomeri zation
Millions of Barrels/Day
1972
13.1
1.1
3.6
0.6
2.8
1.0
0.3
0.2
1974
14.3
1.3
3.6
0.9
3.3
1.0
1.0
0.2
1976
15.7
1 .7
3.6
1.6
4.1
1.2
2.6
0.2
1980
18.7
2.4
3.6
1 .7
4.6
1 .3
2.9
0.2
RGH-015
Bonner & Moore Associates, Inc.
4-18
-------
4.3.7 Cost Effects
Table 15 shows the annual cost effects for Schedule L relative to the
Reference Schedule. Added costs are broken down into refining investment costs,
other refining costs and distribution investment costs. These costs are shown
both as millions of dollars per year and as cents per gallon of total gasoline.
The "other" refining cost category represents the net effect of increase
in operating costs, raw stock costs and product degradation costs plus credits
for decreased lead usage and by-products. Included in this cost is the effect of
assuming constant value per barrel of gasoline even through the subject case pool
is not the same ratio of premium and regular as in the reference case. (See
paragraph 4.7.4.)
A striking example of the cost of producing low-lead gasolines is shown
by comparing 1976 Schedule A (Table 9) with 1976 Schedule L. The cost difference
in these two cases is about 770 million dollars annually in domestic refining
costs. The difference in TEL consumption between these two cases is about 390
million pounds of TEL annually; thus removal costs about $2.00 per pound of TEL
el iininated.
RGH-015 Bonner & Moore Associates, Inc. "I-I 3
-------
•yo
•a
o
Ol
TABLE 15
COST EFFECTS OF SCHEDULE L
National Added Costs, MM$/Yr.
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
Added Distribution Costs
Total Added Cost
National Added Costs, I/Gal*
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
Added Distribution Costs
Total Added Cost -
*Using total gasoline demand as a divisor.
1972
209
(10)
199
25a
454
0.21
(0.01)
0.20
0,28
0.48
1973
299
(79)
22U
340
560
0.30
(0.08)
0,22
0.34
0,56
1974
407
(107)
300
340
640
0.40
(0.11)
0.29
0.33
0.62
1975
623
(54)
569
340
909
0.58
(0.05)
0.53
0.32
0,85
1976
844
(182)
662
340
1002
0.76
(0.16)
0.60
0.30
0.90
1977
843
(258)
585
340
925
0.73
(0.22)
0.51
0.29
0.80
1978
852
(339)
513
340
853
0.71
(0.28)
0.43
0.28
0.71
1979
881
(406)
475
340
815
0.7]
(0.32)
0.39
0.27
0.66
1980
905
(471)
434
340
774
0.70
(0.36)
O.J4
0.26
0.60
CD
0
3
3
(D
2
o
o
(8
If
ro
O
-------
4.4
SCHEDULE G
4.4.1
Description of Schedule
Lead removal Schedule G is a schedule for a two-grade marketer where the
octanes of the grades correspond to the current regular and premium gasolines.
The regular (94.0 Research Octane) gasoline is permitted to contain 0.5 gm of
lead additive until 1974, at which time the additive must be removed. The pre-
mium grade (100.0 Research Octane) is permitted to contain up to 3.0 gm of lead
additive throughout the schedule.
1.4.2
Reason for Selecting Schedule G for Study
Schedule G could be seen to have the least impact on the refiners of any
of the two-grade schedules offered. This is caused by all others having the same
lead schedule on the regular gasoline and equal or lower allowable lead content
in premium gasolines.
4.4.3
Raw Stock Effects
Although the least demanding of the two-grade schedules. Schedule G fs
noticeably more costly and more demanding than Schedule A. The higher crude oil
requirements are an indication of this. Table 16 shows the crude and other raw
stock requirements along with the comparison figures for the reference schedule.
TABLE 16
RAW STOCK REQUIREMENTS FOR SCHEDULE G
(Millions of Barrels/Year)
Normal Butane
Iso-Butane
Natural Gasoline
Sub-total
Crude Oil
Total
% Increase in Crude
1971
G
58.1
41.8
192.9
292.8
4393.9
4686.7
0
Reference
66.6
48.0
192.9
307.5
4369.7
4677.2
55
1974
G
72.4
52.1
97.2
221.7
5142.9
5364.6
3
Reference
81.6
58.7
192.9
333.2
4954.4
5287.6
80
1980
G
91.6
66.0
122.2
279.8
6815.1
7094.9
3
Reference
79.8
57.4
192.9
330. 1
6557.1
6887.2
93
RGH-015
Bonner & Moore Associates, Inc.
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Comparing the figures in Table 16 with those in Table 4 shows that the
two-grade schedules utilize more crude and less natural gasoline and butanes than
the three-grade schedules. Directionally, a three-grade schedule was able to
utilize slightly more natural gasoline and/or butane purchases because the more
severe operations of the two-grade case produced more light hydrocarbons inter-
nally, thus requiring less outside purchase.
4.4.4
By-Product Effects
Table 17 presents a comparison of the fuel gas and coke productions for
Schedule G and the Reference Schedule.
TABLE 17
BY-PRODUCT PRODUCTION FOR SCHEDULE G
Coke, Million Tons/Year
Fuel Gas , Trillion BTU/Year
1971
G
14.3
1271
Reference
14.1
1195
1974
G
21.2
1756
Reference
19.5
1360
1980
G
37.5
2087
Reference
36.1
2070
A comparison of the 1971 and 1980 fuel gas production of Schedules A and
G (Tables 5 and 17) bears out the more severe operations required by two-grade
schedules.
4.4.5
Motor Gasoline Blending
Table 18 shows the characteristics and composition of each of the two
grades for this schedule. Also shown are the pertinent pool properties. Another
indication of the difficulty of reducing TEL in a two-grade environment is shown
by the need to use 3 gm/gal in the 100 grade even in 1971. In fact, maximum TEL
levels were required for each grade through the full ten years of Schedule G.
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Bonner & Moore Associates, Inc.
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TABLE 18
GASOLINE SUMMARY FOR SCHEDULE G
(Sheet 1 of 2)
94 Octane Blend:
Volume, 109 Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi seel 1 aneous
Hydrocarbon Composition, %
Pa raf f i ns
Olefins
Naphthenes
Aromati cs
100 Octane Blend:
Volume, 109 Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromati c Based
Light Iso-Paraffins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, Z
Paraffins
Olefins
Naphthenes
Aromati cs
1971
62.0
0.5
94.0
86.0
91.7
82.6
35
6
34
6
18
1
45
15
7
33
29.8
3.0
100.0
92.0
91.3
81.8
34
28
19
-
19
-
62
14
6
18
1974
83.2
0.0
-
-
94.0
86.0
27
9
37
7
19
1
42
11
5
42
19.3
3.0
100.0
92.0
90.9
82.0
45
36
-
-
19
-
64
18
7
11
1980
124.3
0.0
-
-
94.0
86.0
24
13
36
7
19
1
46
10
5
39
4,1
3.0
100.0
92.0
90.9
82.0
45
36
-
-
19
-
64
18
7
11
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Bonner & Moore Associates, Inc.
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TABLE 18
GASOLINE SUMMARY FOR SCHEDULE G
(Sheet 2 of 2)
Pool :
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromati c Based
Light Iso-Paraf fins
Paraffinic Stocks
Mis eel laneous
Hydrocarbon Composition, %
Paraf f i ns
Olefins
Naphthenes
Aromati cs
RON Clear
MON Clear
1971
35
12
30
4
18
1
50
15
7
28
SI. 8
82.6
1974
30
13
31
6
19
1
46
12
5
37
93.6
85.5
1980
24
14
35
7
19
1
47
10
5
38
93.9
85.9
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Bonncr & Moore Associates, Inc.
4-24
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4.4.6
Process Capacity Changes
Table 19 shows the requirements for major process plant capacities for
each of the selected years of this schedule. From these figures it is readily
apparent that reforming, hydrocracking and, to some extent, alkylation are the
processes required to produce the added octane quality of this schedule. This
becomes more apparent when compared to A. The requirement to make an unleaded
regular gasoline by 1974'shows Schedule G requiring 20% more reforming capacity
and almost 40% more hydrocracking as does Schedule A in 1976, two years later.
The large increase in extraction separation capacity in 1974 results from needing
to purify the aromatics from a large part of the reformate. This effect is
apparent when one compares the gasoline pool compositions in Table 18 for years
1971 and 1974. There, it can be seen that the fraction of the pool composed of
aromatic stocks is almost constant, while the percentage of aromatics increases
about 10%. To accomplish this, heavy raffinate from the extraction processes was
recycled to the reformer.
TABLE 1_9
PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE G
Crude Disti 1 lation
Coki ng
Cat Cracking
Hydrocracking
Cat Reforming
Alkylation
Extraction
Isomeri zati on
Millions of Barrels/Day
1971
12.4
1.0
3.6
0.9
2.8
0.9
0.9
0.1
1974
14.1
1.5
3.6
1.5
3.6
1.0
2.0
0.1
1980
18.7
2.6
3.6
2.0
4.9
1 .3
2.7
0.1
4.4.7
Cost Effects
Table 20 shows the annual cost effects for Schedule G relative to the
Reference Schedule. Added costs are broken down into refining investment costs
and other refining costs. These costs are shown both as millions of dollars per
year and as cents per gallon of total gasoline.
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Bonner & Moore Associates, Inc.
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o
in
TABLE 20
COST EFFECTS OF SCHEDULE G
National Added Costs, MM$/Yr.
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
National Added Costs, if/Gal*
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
1971
195
(17)
178
0.21
.(0.02)
0.19
1972
244
(15)
229
0.26
(0.02)
0.24
1973
278
(56)
222
0.28
(0,06)
0.22
1974
631
(54)
577
0.62
(0.06)
0.56
1975
669
(100)
569
0.62
(0.09)
0.53
1976
717
(149)
568
0.64
(0.13)
0.51
1977
750
(208)
542
0.65
(0.18)
0.47
1978
755
(271)
484
0.63
(0.23)
0.40
1979
840
(332)
508
0.68
u.27
0.41
1980
845
(388)
457
0.66
(0.30)
0.36
*Using total gasoline demand as a divisor.
D
o
3
3
n
2
0
0
"I
re
-e»
ro
-------
The "other" refining cost category represents the net effect of increases
in operating costs, raw stock costs and product degradation costs plus credits for
decreased lead usage and by-products. Included in this cost is the effect of
assuming constant value per barrel of gasoline even though the subject case pool
is not the same ratio of premium and regular as in the reference case. (See
paragraph 4.7.4.)
Because Schedule G is a two-grade schedule, no added distribution costs
are appli cable.
RGH-015 Bomicr *c Moore Associates, Inc. •»-?./
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4.5
SCHEDULE M
4.5.1
Description of Schedule
Schedule M is a lead removal schedule for a two-grade marketer. It removes
lead from both grades as quickly as possible. It was developed as a replacement for
Schedule K when it was discovered that the amount of process construction Implied by
Schedule K exceeded the capability of the construction industry.
4.5.2
Reason for Selecting Schedule M for Study
Original plans for the study included a detailed analysis of Schedule K as
the 'most difficult1 schedule to be met. After determining that Schedule K could
not be met without exceeding the capability of the process construction industry.
Schedule M was devised to reduce TEL usage as rapidly as possible while not exceed-
ing the estimated growth potential of the construction industry.
4.5.3
Raw Stock Effects
Table 21 shows the raw stock requirements for Schedule M and for the Ref-
erence Schedule. A comparison of Schedule M requirements with those of Schedule L
(Table 10) shows a remarkable similarity in raw stock utilization. Again, the two-
grade situation shows itself to be less efficient by requiring more (slight in this
case) crude as shown in 1976 and compared to Schedule L. It should be noted that
Schedule M did not quite achieve totally lead-free gasoline manufacture in 1976
within construction industry limits. It was also impossible to force the 94 RON
to be lead free in 1974 without exceeding construction industry capacity.
TABLE 21
RAW STOCK REQUIREMENTS FOR SCHEDULE
(Millions of Barrels/Year)
Normal Butane
Iso-Butane
Natural Gasoline
Sub-total
Crude 011
Total
% Increase In Crude
1972
H
92.7
66.7
192.9
352.3
4616.3
4968.6
1
Reference
69.8
50.2
192.9
312.9
4553.7
4866.6
37
1974
M
69.4
50.0
167^8
287.2
5115.2
5402.4
3
Reference
81.6
58.7
192.9
333.2
4954.4
5287.6
25
1976
M
89.8
64.7
39.9
194.4
5737.3
5931.7
5
Reference
79.8
57.3
192.9
330.0
5417.3
5747.3
91
1980
H
91.8
66.1
115.3
273.2
6818.1
7091.3
3
Reference
79.8
57.4
192.9
330.1
6557.1
6887.2
98
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Bonner & Moore Associates, Inc.
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Schedule M shows slightly less raw stock requirement .than Schedule L in
the early years because it was not possible to reduce TEL contents in the two-
grade case as fast as in the three-grade situation. By 1980, Schedule M uses more
crude and less light raw stocks to give essentially the same total consumption as
that of Schedule L.
4.5.4
By-Product Effects
As with raw stocks, Schedule M shows similar results to Schedule L.
Table 22 presents the coke and fuel gas production for Schedule M and for the
Reference Schedule. Comparison of these figures with those of Table 11 shows the
similarity of behavior of the model under Schedules L and M. Given the objective
of minimizing TEL and the constraint of limited Investments by year, the differ-
ence between a two-grade and a three-grade situation becomes less obvious.
TABLE 22
BY-PRODUCT PRODUCTION FOR SCHEDULE M
Coke,
MMTons/Year
Fuel Gas ,
101;'BTU/Year
1972
M
15.0
1612
Reference
15.8
1268
1974
M
20.4
1024
Reference
19.5
1360
1976
M
26.8
2148
Reference
23.8
1528
1980
M
37.4
20 87
Reference
36.1
2070
4.5.5
Motor Gasoline Blending
The primary difference between Schedules L and M is the three versus
two-grade gasoline situation. Table 23 presents the characteristics and composi-
tion of each of the two grades for Schedule M for the years studied. Table 24
shows TEL levels for 1972 through 1976. Levels for subsequent years are zero.
The early reduction to relatively low TEL levels in Schedule M (and as seen in
Schedule L), followed by a gradual reduction through the four-year period follow-
ing 1972, emphasizes the increasing difficulty and cost of removing the last small
increment of TEL. Unlike the three-grade situation of Schedule L, Schedule M can
not achieve total TEL removal by 1976. For all practical purposes, the 94 octane
grade is unleaded in the 1976 case, but the 100 octane grade still shows about
0.1 gm/gal TEL content. In other respects, the gasoline pool for the two
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Bonner & Moore Associates, Inc.
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TABLE 23
GASOLINE SUMMARY FOR SCHEDULE M
(Sheet 1 of 2)
94 Octane Blend:
Volume, 109 Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf fins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composi ti on, %
Paraffins
Olefins
Naphthen'es
Aromati cs
100 Octane Blend:
Volume, 109 Gals/Year
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Li ght Iso-Paraffins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composi ti on, %
Paraf f i ns
Olefins
Naphthenes
Aromati cs
1972
69.4
0.855
94.0
86.0
89.5
80.3
44
10
24
2
19
1
51
19
7
23
26.0
0.651
100.0
92.5
98.5
87.9
_
29
56
8
7
-
59
_
3
38
1974
83.2
0.444
94.0
86.0
91.7
82.2
37
9
31
5
17
1
48
16
6
30
19.3
0.235
100.0
92.0
99.4
90.3
-
38
47
6
9
-
58
-
5
37
1976
98.3
0.002
-
-
94.0
86.0
30
11
34
8
16
1
44
12
4
40
13.4
0.098
100.0
92.0
99.8
91.3
-
40
38
4
18
-
63
-
-
37
1980
124.3
0.0
-
-
94.0
86.0
25
13
35
7
19
1
46
10
5
39
4.1
0.0
-
-
100.7
92.0
-
40
33
18
9
-
67
-
-
33
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Bonner & Moore Associates, Inc.
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TABLE 23
GASOLINE SUMMARY FOR SCHEDULE M
(Sheet 2 of 2)
Pool:
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf fi ns
Paraffinic Stocks
Mi seel 1 aneous
Hydrocarbon Compos i ti on, %
Paraffins
Olefins
Naphthenes
Aromati cs
RON Clear
MON Clear
1972
34
15
31
3
16
1
53
14
6
27
91.8
82.3
1974
32
14
33
5
15
1
50
13 .
6
31
93.0
83.6
1976
27
14
35
7
16
1
46
11
4
39
94.7
86.6
1980
24
14
36
7
18
1
47
10
5
38
94.2
86.2
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Bonner & Moore Associates, Inc.
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minimum TEL schedules show quite similar characteristics. All of the observed
differences between Schedules L and M are adequately explained by the three-grade
versus two-grade environments.
TABLE 24
TEL CONTENTS OF SCHEDULE M GASOLINE
(gm/gal)
94 Octane Grade
100 Octane Grade
Pool
1972
0.9
0.7
0.8
1973
0.6
0.4
0.5
1974
0.4
0.2
0.3
1975
0.2
0.1
0.2
1976
trace
0.1
0.01
4.5.6
Process Capacity Changes
Table 25 shows the increases in plant capacities for each of the selected
years of this schedule. These can be compared to the capacity figures for Sched-
ule L in Table 13 and the reference capacities shown in Table 27.
TABLE 25
PROCESS CAPACITY REQUIREMENTS FOR SCHEDULE M
Crude Distillation
Coki ng
Cat Cracking
Hydrocracklng
Cat Reforming
Alkylation
Extracti on
Isomeri zation
MiUions of Barrels/Day
1972
13.1
1.0
3.6
0.5
2.6
1.0
0.3
0.1
1974
14.5
1.3
3.6
0.9
3.0
1.1
0.8
0.1
1976
15.8
1.7
3.6
1.7
3.0
1.2
2.7
0.1
1980
18.8
2.4
3.6
1.9
3.7
1.3
3.1
0.1
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Bonner & Moore Associates, Inc.
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4.5.7 Cost Effects
Table 26 sho,ws the annual cost effects for Schedule M relative to the
Reference Schedule. Added costs are broken down into refining investment costs,
other refining costs and distribution investment costs. These costs are shown
both as millions of dollars per year and as cents per gallon of total gasoline.
The "other" refining cost category represents the net effect of increase
in operating costs, raw stock costs and product degradation costs plus credits
for decreased lead usage and by-products. Included in this cost is the effect of
assuming constant value per barrel of gasoline even though the subject case pool
is not the same ratio of premium and regular as in the reference case. (See
paragraph 4.'7 . 4. )
RGH-015 Bonner AC Moore Associates. Inc. 1-33
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O
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TABLE 26
COST EFFECTS OF SCHEDULE M
National Added Costs, MM$/Yr.
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
National Added Costs,
-------
4.6
REFERENCE SCHEDULE
As explained in the discussion in paragraph 2.1, a Reference Schedule
was defined as a base from which to measure the economic effects of the various
lead-removal schedules. This schedule was required to satisfy all product demand
forecasts as well as all other operating conditions imposed on the refinery models
except for the TEL limitations and attendant gasoline volume increases associated
with compression ratio decreases and catalytic exhaust reactor mileage ineffi-
ciencies.
Cost consequences of subject case behavior were defined as the differ-
ences in investment and cash flows between subject and reference cases. The
actual cash flows derived from model results cash flows have not been included in
this report because, in themselves, they are meaningless. Only their relative
values (to the reference case) can be taken as significant. The absolute magni-
tude of subject case investments are meaningful because they reflect the load which
might be imposed on the construction industry.
All comparisons between subject and reference case behavior have been
incorporated into appropriate tables with the exception of gasoline characteris-
tics and process capacity profiles. These aspects of the Reference Schedule are
presented in the following tables. Table 28 presents the motor gasoline charac-
teristics of Reference Schedule gasoline,and Table 27 shows major process capac-
ity changes.
TABLE 27
PROCESS CAPACITY REQUIREMENTS FOR REFERENCE SCHEDULE
Crude Distillation
Coking
Cat Cracking
Hydrocracki ng
Cat Reforming
Al ky 1 ati on
Ext racti on
Isomeri zati on
Mi 1 lions of Barrel/Day
1971
12.0
1.0
3.6
0.6
2.4
0.8
0.3
0.1
1972
12.5
1.1
3.6
0.6
2.4
0.8
0.3
0.1
1974
13.6
1.3
3.6
0.7
2.4
0.9
0.4
0.1
1976
14.8
1.5
3.6
0.9
2.6
0.9
0.5
0.1
1980
17.9
2.2
3.6
0.9
3.1
1.0
0.8
0.1
RGH-015
Bomicr it Moore Associates, Inc.
4-35
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TABLE 28
GASOLINE SUMMARY FOR REFERENCE SCHEDULE
(Sheet 1 of 2)
94 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf f ins
Paraffinic Stocks
Mi seel laneous
Hydrocarbon Composition, *
Paraffins
Olef ins
Naphthenes
Aromatics
100 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf fins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, %
Paraffins
Olef ins
Naphthenes
Aromati cs
Pool:
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraff ins
Paraffinic Stocks
Miscel 1 aneous
1971
56.0
1.935
94.0
86.0
85.9
77.7
41
-
29
-
28
2
46
18
14
22
35.0
2.738
100.0
92.5
92.8
83.3
24
31
26
7
12
-
62
10
6
22
35
11
28
3
22
1
1972
58.0
2.262
94.0
86.0
85.2
77.2
42
0
26
-
29
3
45
19
14
22
36.0
2.794
100.0
93.1
92.6
83.3
20
30
30
7
13
-
63
8
7
22
34
11
28
2
23
2
1974
62.0
2.373
94.0
86.0
85.1
77.1
42
-
25
-
29
4
46
19
14
21
39.0
2.815
100.0
93.4
92.2
84.1
15
31
31
8
15
-
65
6
8
21
32
11
28
3
24
2
1976
65.0
2.242
94.0
86.0
85.4
77.2
43
-
25
1
27
4
46
19
14
21
41 .0
2.937
100.0
93.9
91 .6
83.7
10
30
33
7
20
-
66
4
8
22
31
11
29
3
24
2
1980
72.0
2.168
94.0
86.0
85.6
77.5
44
-
23
3
26
4
45
20
14
21
45.0
2.690
100.0
94.5
91.9
84.9
-
30
43
3
24
-
66
-
9
25
28
11
31
3
24
3
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Bomier & Moore Associates, Inc.
4-36
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TABLE 28
GASOLINE SUMMARY FOR REFERENCE SCHEDULE
(Sheet 2 of 2)
Hydrocarbon Composition, %
Paraf f i ns
Olefins
Naphthenes
Aromatics
RON Clear
MON Clear
1971
52
15
11
22
88.4
79.7
1972
52
15
11
22
87.9
79.4
1974
52
15
12
21
87.6
79.5
1976
52
14
12
22
88.6
79.6
1980
53
13
12
22
87.9
80.0
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Bonner & Moore Associates, Inc.
4-37
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4.7 SENSITIVITY ANALYSES
The sensitivity of the results of this study to several key assumptions
was measured to provide a better understanding of the results, to improve confi-
dence in the results and to provide a means of estimating the effects of varying
these assumptions.
Cases were run to test the following:
1) The ratio between volumes of 93 octane to 94 octane gasolines
purchased by owners of 1971 through 1974 model automobiles (three-grade
schedules only).
2) The assumption regarding the octane level of the special third
grade of gasoline (Ion lead or clear, low octane fuel).
3) The forecast of miles driven for future years and hence the volumes
of gasoline required in both the reference schedules and the subject
schedules.
The results of these analyses are presented in Table 29.
In general, these results are consistent with other studies of lead
removal. They show the added cost of gasoline to be sensitive to changes in clear
pool octane requirements. The increased sensitivity to assumptions affecting
clear pool octane number of Schedule L, as compared to Schedule A, is a conse-
quence of the fact that a given Improvement 1n octane quality is more expensive
at high octane levels than at low octane levels.
The year 1976 was selected as a key year for this analysis because many
of the effects considered most important to the study were present in this year.
These effects include:
1) The 1976 clear pool octane numbers tended to be a maximum.
2) The 1975 and 1976 model cars accounted for a fair share of the mar-
ket but did not dominate it as in"later years.
Consequently, it was judged that this year would represent a turning
point in the sensitivity of the study to these assumptions.
RGH"015 Bonner & Moore Associates, Inc. 4"38
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O
Ul
TABLE 29
EFFECT ON ADDED COST AND INVESTMENT RESULTS OF VARYING KEY ASSUMPTIONS,
(Year = 1976)
Assumption Change
(1) 1971 - 1974 models buy in 25/75 Added Cost,
l
U)
VO
-------
4-7.1 Assumption Involving Ratio Between Grades
Varying the relative amounts of the 93 and 94 octane gasolines purchased
by owners of 1971 - 1974 model automobiles produced results consistent with this
change in clear pool octane. In Schedule A, an increase in the relative amount
of 93 octane caused an increase in cost because the 93 octane has a higher clear
octane rating than the 94 octane gasoline. Schedule L shows the opposite effect
because both grades are clear.
The sensitivity of the added costs to this would be somewhat less for
all schedules in the earlier years, peaking at about 1975, and then declining
again as the 1971 - 1974 models disappear from the road 1n subsequent years.
Schedule L shows a greater sensitivity to this assumption because the clear octane
level of the total gasoline pool is higher.
4.7.2 Assumption Involving Octane of Third Grade
Added costs vary with this assumption in a manner consistent with clear
pool octane changes and level. The difference between the Schedule A effect,
-.134/gal, and the Schedule L effect, -.204/gal, reflects the fact that, at the
higher clear pool octane level represented by Schedule L, the cost of improving
octane a small amount is about 50% higher than it is at the Schedule A clear
octane levels .
The magnitude of this effect will vary with the amount of the third grade
of gasoline being sold. Thus it will increase with time in Schedule A. The sen-
sitivity of Schedule L to this effect should remain relatively constant since the
effect of increasing the volume of the third grade is offset to a great extent by
the consequent lowering of the total pool clear octane.
In this analysis no further loss in automotive engine efficiency is
assumed by lowering octane. If such a loss in efficiency did occur it still
should not have a significant influence on these per gallon added cost differ-
ences. A consumer effect would be noticed if more gasoline were required at 91
RON.
4.7.3 Assumption Involving Total Gasoline Volume
The added cost for deleading gasoline when expressed on a cents/gallon
basis is not sensitive to this assumption. This implies that the investments and
operating costs change in direct proportion to volume within the range studied.
It must be pointed out that the limitation to construction was not a factor in
these studies. A higher gasoline demand will delay the date at which all gaso-
lines can be manufactured clear.
RGH-015 Bonner & Moore Associates, Inc. 4-40
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4.7.4 Adjustment of Added Cost for Variations in Gasoline Grade
Volumes and Prices
Added production costs for unleaded gasoline are based upon a fixed aver-
age gasoline price at the refinery.
The cents/gallon effect shown in Table 30 can be interpreted as the
across-the-board price increase (above the stated grade prices) to maintain the
per-gallon price for total gasoline equal to the reference case. Alternatively,
had the added costs been calculated on the basis of the indicated grade prices,
the cents/gallon added costs would have been higher by the amount shown.
The relative amount of premium gasoline in the subject schedules is con-
siderably lower than in the reference schedule. Therefore, if the prices for the
individual grades of gasoline had been held fixed, the average price for gasoline
would have been declining in the subject schedules.
KGII-015 MOMIMT fe Mnuri- A.s.soi-iitu-.s. Inc. 4-41
-------
O
171
TABLE 30
EFFECT OF GRADE MIX VARIATIONS ON AVERAGE
GASOLINE REFINERY NETBACKS**
2-Grade Schedules
% 94 RON
* TOO RON
4/Gal Netback
Effect,
I
ro
-------
4.8 EFFECTS ON SMALL REFINERS
Earlier studies of unleaded gasoline economics have shown that the
economic impact of changing gasoline formulations falls more heavily upon small
refiners than upon large ones. This is due, almost exclusively, to the effects
of economies of scale, which result in refinery processes being more costly per
unit of throughput when built in small sizes than when built in large sizes.
In this section the discussion of the small refining industry is broken into four
topics. The first is a history of the role of small refiners in the total U.S.
refining industry to give a perspective of the importance of this industry seg-
ment and of its likely future. Second, the small refinery economic effects of
lead reduction are discussed. Third, present programs of economic assistance to
small refineries are discussed, and fourth, alternate futures of the small
refiner are examined.
In this study, small refiners have been defined as those processing less
than 35,000 barrels per day of crude oil. The cost penalties of small size are
not confined solely to refineries of this size. Earlier work, however, has shown
that small refineries, by this definition, experience a particularly sharp increase
in added costs when being extended to produce unleaded gasoline. Furthermore,
this 35,000 barrel per day size represents an approximate breakpoint below which
certain high-cost processes such as hydrocracking, which is economical for unleaded
gasoline manufacture in larger refineries, can no longer be justified because of
size and economies of scale. In this study all refineries classified as non-small
refineries, those larger than 35,000 barrels per day, represent an average size
equivalent to about 100,000 barrels a day of crude capacity. Many industry people
use a "rule of thumb" that, in the long run, grass roots refineries built in the
United States can be economical only if they are at least 100,000 barrels per day
in capaci ty.
Small refineries tend to fall into two categories: those that are pro-
ducing gasoline and other fuels for the general energy market, and those that are
producing specialty products, for example, asphalt for road building. There are
a larger number of these asphalt refineries, and they produce certain by-products
that enter the general fuels market. Their economic viability, however, depends
on the asphalt market and, as such, they are of little interest in our present
studies and specifically have been excluded from those data that are used to dis-
cuss the effects on small refineries. The remaining small refineries, those that
are principally in the fuel products business, have historically existed for one
reason. That is, they were close enough to a supply of crude oil that transpor-
tation cost savings made it practical to build a small refinery, operating on
local crude oil to supply a local market. Tables 31 and 32 show statistical
histories of the small refiner for the 20-year period 1950 through 1970. During
this time, the number of small refineries declined from 155 to 74. This reduc-
tion came about by shutting down 75 refineries, expanding 45 refineries beyond
35,000 barrels a day crude capacity and building 39 new small refineries. In
RCH-015 Bonrier it Moore Associates, Inc.
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TABLE 31
o
tn
GROWTH AND DECLINE TRENDS AMONG SMALL U.S.
GASOLINE REFINERS FROM 1950 THROUGH 1970
PERIOD
1950 - 1960
1960 - 1970
1970 -
NO. OF SMALL
REFINERIES
(BEGINNING)
155
102
74
NUMBER
SHUT DOWN
47
28
7
NUMBER
EXPANDED TO
35.000+
28
17
7
NEW
SMALL REFINERIES
ADDED
22
17
7
CD
0
3
3
2
0
0
TABLE 32
CRUDE CAPACITY TRENDS OF SMALL REFINERIES
CRUDE
RUNS
1950
SMALL
FUEL
REFINERIES
1 ,683,550
25.7
SMALL
SPECIALTY
REFINERIES
506,815
7.7
ALL
REFINERIES
6,540,265
100
1960
SMALL
FUEL
REFINERIES
1 ,542,120
15.9
SMALL
SPECIALTY
REFINERIES
420,370
4.3
ALL
REFINERIES
9,699,955
100
1970
SMALL
FUEL
REFINERIES
1,244,586
9.8
SMALL
SPECIALTY
REFINERIES
429,991
3.4
ALL
REFINERIES
12,681 ,387
100
-------
this same 20-year period, the percent of crude charged to the small refinery sec-
tor decreased from 26% in 1950 to 10% 1n 1970. From Tables 31 and 32 it can also-
be seen that, although the number of small refineries decreased by almost 50%, the
selective process of shutting down the smallest plants first caused their total
crude runs to decrease only about 25%. Nevertheless, during this period their
portion of the total U.S. refining business declined over 60% from 25.1% to 9.8%.
One significant reason for the decline of the small refiner can be traced
to the quality of gasoline which is sold today as compared with gasoline sold in
1950. In 1950 the average Research Octane Number of gasoline was about 85, and in
1970 the average was about 96.5. Producing higher octane gasoline, as has been
discussed earlier, requires more complex refinery processes and requires ones
which are more capital intensive. Effects of size have thus become more pro-
nounced as the investment per barrel of crude throughput has risen to meet
increasing gasoline quality requirements.
Previous Bonner & Moore studies of the economics of manufacturing
unleaded motor gasoline have used as many as twelve models. The models repre-
sented major geographic areas within the U.S. and various sized refineries within
these areas. This work has provided experience in extrapolating economic
behavior of several models to national behavior. Subsequent work done with
smaller sets of models has shown the earlier work to be an excellent guide for
this extrapolation.
As noted in other areas of this report, the added cost of gasoline manu-
facture stems from five cost contributors:
1) Costs associated with investments.
2) Variable operating costs.
3) Lead reduction credits.
4) By-product credits (debits).
5) Raw stock costs.
Costs associated with investments usually account for the major portion
of added costs, and become magnified for the smaller refiner. Figure 4-1 shows the
investment required to manufacture unleaded motor gasoline versus refinery size,
expressed in volume of motor gasoline manufactured. This plot represents data
from six refinery sizes within the mid-continent3. Three additional points are
shown from a more recent study. Based upon this earlier work, the assumption was
made that the slope of this effect stays constant although the investment
required may be less for lower octane requirements. Therefore, if the added cap-
ital investment required for a given refinery is known, the similar added capital
needs for other sized refineries can be derived.
RGH-015 Bonner & Moore Associates, Inc.
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Investment
MM$
100
90
MO
60
50
40
30
20
10
9
8
/
6
5
4
k
! !
Q API (98 RON, Pool)
X 2nd Study (98 R01I , Pool)
I'!::!'
,--. .,.
! <
•; ;
4 5 6 7 8 910
20
30 40 50 60 80 100
Refinery Size, MB/CD Motor Gasoline
Figure 4-1. Refinery Size versus Added Capital Investment to
Manufacture Unleaded Motor Gasoline
RGH-015
Banner & Moore Associates, Inc.
4-46
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Variable operating costs and lead reduction credits appear to be essen-
tially linear with refinery size. By-product costs and raw stock costs are some-
what greater (per barrel of gasoline) for small plants but not significantly so
until throughput falls well below the 35,000 barrel/day cutoff. Figure 4-2
illustrates the lower efficiency of gasoline production for small refineries as
reflected by added crude requirements. At this small throughput, the refineries
represented account for a negligible part of the nation's gasoline production.
Even so, the extrapolation procedures used to obtain national behavior predic-
tions conservatively assume uniform gasoline yield (regardless of size).
Added Raw Stock
(% of Crude)
Over Base Model
3.0
2.0
1.0
10 ,000 B/D
30,000 I) / D
50,000 13/D
89 90 91 92 93 94 95
Clear Pool Octane
Figure 4-2. Added Raw Stock versus Pool Octane
for Varying Refinery Sizes
To further illustrate how refinery size affects added costs for produc-
ing unleaded gasoline, the factors described above have been used to estimate
added costs for the lead removal schedules A, G, L, and M studied in this report.
Table 33 gives an example of these estimates. It must be understood that these
small refinery costs have not been derived in the detailed manner that has been
used for obtaining the principal results. Instead these principal results have
been used as a base to which the estimation procedure has been applied.
RGH-015
Bonner & Moore Associates, Inc.
4-47
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TABLE 33
EXTRAPOLATION OF REFINERY SIZE EFFECTS
ON COST ESTIMATES FOR SCHEDULE A
Added Cost for Small Refineries,
i/Gal Based on Total Gasoline
100 MBCD Crude
50 MBCD Crude
30 MBCD Crude
10 MBCD Crude
1971
0.16
0.19
0.20
0.25
1976
0.21
0.24
0.26
0.33
1980
0.21
0.24
0.26
0.33
It must be recognized that the "average" cost presented in this report is
greater than that incurred by the larger refinery and smaller than that incurred
by the small one. Any program which attempts to compensate costs (via assistance
programs, taxation or allotments, etc.) adds its burden to the incurred cost and
must be borne by some agent (taxpayer, industry or consumer). Assessment of this
kind of cost is beyond the scope of this study.
The small refiner has been assisted directly or indirectly by the Federal
Government for many years. The principal assistance program has been an indirect
one. This has been the crude oil import program initiated in 1959 with its slid-
ing scale for permissible import quotas. This program was not conceived as a
direct small refinery assistance program. Its provisions, however, guarantee the
small refiner access to any benefits of low cost crude imports to a degree not
allowed large refineries. Historically, a license or "ticket" to import foreign
crude has been valued at $0.90 to $1.25 per barrel. Higher values (as well as
lower values) have been occasionally realized on a spot basis. These values
reflect sales price differences between domestic and foreign crude, less trans-
portation cost differences. In the latter half of 1970, and for several months
of 1971, tanker shortages have driven transportation costs up so sharply that
import "tickets" have virtually no value. Future tanker shortages as well as an
approach to parity between foreign and domestic crude prices each serve to reduce
the value of this indirect small refiner assistance program. Table 34 summarizes
the import allocation method as it existed until the end of 1970. A small refiner
with an import quota equivalent to 15'X of his crude throughput has been able to
realize an income of roughly $0.15 per barrel of throughput from sale of this oil
import allocation. Compared to a large refinery with an import quota of perhaps
4% of throughput, this small refinery is subsidized by $0.11 per barrel of crude.
If this is allocated to gasoline production, it becomes about $0.21 per barrel or
RGH-015
Boiinor *t Moore Associates, Inc.
4-48
-------
0.54 per gallon. It must be remembered that small refinery added costs for
unleaded gasoline, shown earlier, are additive to the present cost differences
partially represented by these assistance programs.
TABLE 34
CRUDE OIL IMPORT ALLOCATION FORMULA
Refinery Average Daily Throughput
PAD Districts I-IV (1970)
0 - 10,000
10 - 30,000
30 - 100,000
Over - 100,000
PAD District V (1970)
0 - 10,000
10 - 30,000
30 - 100,000
Over - 100,000
Al 1 oca ti on As
Percent of Throughput
19.5
11.0
7.0
3.0
40.0
9.3
4.3
1.9
Another type of assistance program is the small business petroleum prod-
uct purchasing procedure. In general this method guarantees that some portion of
government purchases (up to 45%) will be made from small refineries at prices that
in part reflect their manufacturing cost disadvantage. In one type of preferen-
tial purchase called a "total set-aside", the small refiner is able to bid compet-
ively against other small refiners without competing against larger suppliers if
he bids a fair market price. In the other type of purchase called a "partial set-
aside", a small refiner bidder may supply product preferentially over a large
refiner if he meets the large refiner's price.
Financial data on small refineries are not generally available. Most of
the refineries are closely or privately held. Therefore, they do not come under
S.E.C. disclosure requirements, and 1t Is necessary to speculate on the profitabil-
ity of this part of the industry. It is probably realistic to say that the profit
margin for small refiners has been less than their income from the sale of import
tickets. Under this condition then.it is apparent that the basic refining of
crude oil in a small refinery has been unprofitable in the United States for many
years. In 1958 the small refinery industry had reached a virtual crisis in prof-
itability and was unable to generate either cash flows or borrowing power to mod-
ernize and expand facilities. The implementation of the oil import program bred
considerable new economic life into this part of the industry and has prolonged
it well beyond what would probably have occurred under conditions which existed
R6H-015
Bonner & Moore Associates, Inc.
4-49
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in 1958. Had the import program not been enacted, it is reasonable to assume
that the small refinery industry would have continued until its equipment was no
longer operable. It would not have been able to generate funds to cover depre-
ciation and, therefore, would have been unable to replace equipment with new mod-
ern faci1i ti es .
In the intervening years since 1958, however, the small refinery industry
has been able to sustain itself and, by and large, show modest profits for the
owners. Today there are many small refiners which have modern plants able to
produce high quality products.
The fundamental economics of small refiners are harmed by two long-term
trends. One has been cited earlier, namely the continued increase In gasoline
octane necessitating more expensive refining equipment. A second factor has been
the continuous building of pipelines for both crude oil and refined products.
Pipeline transportation Is sufficiently low In cost that the old economics of
building a small refinery at a local crude source to avoid costly rail or truck
transportation is no longer widely applicable. This trend could well be reversed,
however, 1f a chronic energy shortage develops which results in prices for basic
fuel products, such as heating oils and dlstl Hates , .that will permit a reasonable
return on investment to be realized by a refinery company without its own crude
production. Thus, the small refinery industry might find a new opportunity to
supply small local markets with non-gasoline fuels that can be produced in rela-
tively simple plants.
Another, and perhaps more likely, avenue for rationalizing the small
refinery industry under the economic conditions of the '70's would be through
merger or pooled operation of large modern plants. From a logistics standpoint,
this option is open to about 1/2 to 2/3 of the small gasoline refiners. The small
refinery "belt" in the U.S. extends from the Mississippi Delta to the Montana-
Idaho border and is approximately 300 miles wide. In this band lie 47% of all the
U.S. small refiners. In addition, there are other localized groupings of refiners
which in the aggregate represent another 27% of U.S. small refiners. These local-
ized groupings are in California, in Michigan, in the region of Northern Kentucky,
Indiana, Western West Virginia, and in Western Pennsylvania. It appears, consid-
ering logistics alone, that combining almost 75% of present U.S. small refineries
into economic size units is possible.
Any program of rationalization through mergers or acquisitions would
require major amounts of capital. These amounts are beyond the ability of most
small refiners to acquire either through debt or equity sources. Any program to
encourage rationalization of this industry must address this problem of under-
capi tali zati on.
RGH-015 Bonner Ac Moore Associates, Inc. 4-50
-------
4.9 IMPACT ON THE CONSTRUCTION INDUSTRY
The impact of Schedules A, G, L, and M on the construction in.dustry was
studied on a national basis by taking the investments required in the individual
refinery models and scaling these to a national level. The methods used to carry
out this scaling and to make adjustments for obsolescence and replacements are
described in paragraph 5.4.
Table 35 shows the investments being completed by the construction
industry in each year of Schedules A, G, L and M, and the reference schedule. That
is, the facilities represented by these investments are operable for the first
time in the year for which the investment is recorded.
It should be noted that all investments shown in these tables other than
U.S. and Canadian refining are constant for all schedules. Also, U.S. refining
investments for the years 1970, 1971, and 1972 are constant for all schedules.
The refinery investments for these years were based on data reported in the Oil
and Gas Journal and reported levels of engineering and construction backlog.
Figures 4-3, 4-4, 4-5, and 4-6 plot these refinery investments together
with the forecast maximum construction industry capacity available to refining.
The sharp peak construction requirement in 1974 for Schedule G is readily apparent
in Figure 4-4. This overshoot cannot be compensated for any earlier than 1976.
Table 36 gives a breakdown of the construction dollar according to the
various sectors of the construction industry for each schedule. This breakdown
includes a distribution of the total investment dollars backward in time to
reflect the fact that engineering must start well ahead of materials ordering,
etc. For convenience in observing the effect of the various schedules so far as
producing boom or bust conditions is concerned, the lower half of these tables
describes the changes in construction activity from year to year.
RGH-015 DOIIIUM- Ac Moon; Associates, Inc. 4-51
-------
TABLE 35
CONSTRUCTION INDUSTRY INVESTMENTS
(Installed Capacity for Years Listed)
o
in
19/.
137J
a
0
3
3
to
"I
If
197-.
1 5 / ::
1 ? V • - \. r. » t - ' j
',' ~ ' ; C —
H: 3,25;,
- 1 . 3i ~- .
:>'r. 3,SJ.
i ' - i '- o •.. > t ; „
i
A
i
t
c
z.
c
J
3
j
>t
3 ^ J
3EF]
J(*L F?W:;!^N C^^AC*
'?--. r-r 115
••*H. -. i:5 127
•'• P 1 a ^ 7n
•- C -^ 1 ^ >. I J
«^;r- • ;Sc ici
.V.j. ;6C 1?5
l«r> ] 7; H5
-:5 :£: ' H7
-«': l&£ 136
02^ ISC 123
Si; 5?S 131
=3C cCC 132
^s, -:5 133
27'j ?1C IS**
ct-.'- 2. Jl? :,560
MN3
US
l/C5o
1*158
ATC
o JD
918
1/138
1/C46
l*C6c
1*235
1*120
1/189
1/199
1/2C8
1/223
14*179
T8TAL
1/270
1*411
fi t, C
C •? 3
1/169
1/424
1/331
1/356
1/555
1/434
1/515
1/531
1/546
1*567
17/953
FOREIGN
205
235
O/t f\
26U
285
310
335
365
390
420
445
480
515
555
4*800
TBTAL
L'S/CANADA
2/365
2/616
A O AC
2* cQs
2/699
3/144
3/181
3/396
3/810
3/934
4/280
4/581
4/921
5/287
46/418
TOTAL
2*570
2*851
» t, M (J
2/465
2/984
3/454
3/516
3*761
4*200
4*354
4/725
5/061
5/436
5/842
5l/2l8
INVESTMENT SUMMAI
SCHEDULE G
?Y - MM9/YEAR
PETRBCMEflCAU . . REFINING
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1962
FOREIGN
100
110
120
135
150
165
185
205
230
250
280
310
345
US/CANADA
1/2CO
1/33Q
1/5CO
1/68Q
1/88Q
2*020
2/220
2/440
2/690
2/S6Q
3/25Q
3/580
3/930
TOTAL
1/300
l/44c
1/620
1/815
2/0.30
2/185
2/405
2*645
2/92C
3/210
3/53Q
3/890
4*275
FOREIGK
105
125
14C
15C
16C
17C
18C
185
19C
195
20C
2C5
21C
CANADA
115
127
70
119
383
It2
140
122
138
131
128
130
131
US
1/050
1/158
635
1/085
3/482
1/292
1/269
1/112
1/253
1/193
1/165
1/180
1/193
TOTAL
1/270
1/411
845
1/354
4/o25
1*605
1/589
1/419
1/581
1/519
i/493
1*515
1*535
FOREIGN
205
235
260
285
310
335
365
390
420
445
480
515
555
TOTAL
US/CANADA
2/365
2/6U
2/205
2/884
5/745
3/455
3/629
3/674
4/081
4/284
4/543
4/89o
5/255
TOTAL
2/570
2/851
2/465
3/169
6/055
3/790
3*994
4/064
4/5ol
4/729
5/023
5/4C5
5/810
TOTALS 2/585
3C/660
33/265
2/215
1/877
17/068
21/16Q
4/800
49/625
54/425
-------
TABLE 35 (cont.J
:/*:•••
to
0
2
0
0
I
ft>
19/r
'.. •
' • - — ' ^
.;•;
i
. ;
:• • •„
r,.. ::••.,
...•..:- i
C - . ;
j- . i
^.
3C v
- '-' . <"-
C i .'. r;
•? : s
H S 'J /
: £:--•. -:
.- 5t-;
• ^ ' )
; SJ- 4
^, C- - JJ
-f"u r^-L
.3 ~ .
*» ** -'.•
, ~. '
'f '. '-•
•T
j ^'
•1 'v ^
'-" 'c. I
C. i .'
'j3-. ?
20 - ;
>.'75 ;
'£65 2,;
;N
- c
c5
-« |
£
A
7
3
3
*
c
:;
= 1
= 15
^ilF iv
CiN-5 -A
us
127
70
152
173
?36
233
112
113
11*
120
11-5
121
1/811
1\3
L-S
!/C5o
1,158
635
1,3S6
1,615
2/1*7
2/116
1,019
1/CSo
1,032
1/093
1/C?5
1/096
16/461
TeTAL
1,270
1/411
845
1/68S
1/953
2/553
2/529
1/316
1/333
1/341
1/*13
1/*09
l/*27
20/*87
F3KEIQN
205
235
260
285
310
335
365
390
420
445
480
515
555
4/800
T8TAL
US/CANADA
2/365
2/616
2/205
3/218
3/673
4/4Q3
4/b69
3/571
3/»33
4/106
4/463
4/78*
5/147
48/952
TOTAL
2/570
2/851
2/*65
3/5Q3
3/983
4/738
4/93*
3/961
4/253
4/551
4/943
5/299
5/7Q2
53/752
. ic;u
. - / c ^ *• /•;,.»
•. y-
• c '•
* I CC
•'.*••
Cl
13
.£»
I
i-e^
y ,
^EIFIN
3S C*N*C*
:F. us
S? 127
"f 70
~C ' 152
f r 1 7 a.
7: S36
«C . 265
:26
s; 126
05 ! "*
-:c 126
::= ir.7
' '. C 123
"5 i/9,;l
ING
us
l/C5o
1,158
635
1,386
1/615
2,1*7
2,113
1,1*5
1,1"4
1,127
1,1*6
1,152
1,165
17,2£3
T6TAL
1/27C
1,411
£45
1/688
1/953
2/553
2/858
I,4b6
1,460
1,446
1,472
1,484
1/5C3
21/395
FOREIGN
205
235
260
285
310
335
365
390
420
445
480
515
555
4,800
TSTAL
US/CANADA
2/365
2/616
2/205
3/218
3/673
4,403
4/898
3,711
3/960
4,211
4,522
4,859
5,223
49/86*
T6TAL
2/570
2/851
3/*65
3/5Q3
3/983
4/738
5/263
4/101
4/380
4/656
5/002
5/374
5/778
54/664
-------
TO
tr>
TABLE 35 (cont.)
o
in
3
(5
1
(f
2
o
0
RtrERENCE SCHEDULE
137*.
1S71
13 /
• o* «
19'?
19, r
15/r
T3TAuS
' 1 . ' f
"'-••- „ 'i / '
." r
~r
. T
t .
% "
'/ ~ '
c' / i < :. J
-:J !L;-~
.. r. -• « •• " '
-^
•j ". *
r ~ ~
% x.
f C 'v C
'- c J ii !
"***». C.
t i- '. ' c
St;.; ^
?"' C ^ J
/ ^i, -
, fc i : .- .>
j f . . r- C <••
' " L ' • -.
- ..
4"» '.
6?'"
, ."."
C" j r*
1 ^ •;
•: 'r -j
•* £. •
S3-1
^ ^
L'73
,;:*.=, 9 ,
;:% '
• c
su
u r
-,
6;
7;
.- c.
5c
c c
?cc
- « c.
r i ^
" i C
= 15
t5EF^
CA\ACA
H5
127
70
94
96
97
90
90
93
9C
95
92
97
llC46
I\3
us
l*C5c
1*1^8
635
S5-4
869
879
320
317
846
819
865
835
879
ll*33o
TCTAL
1*27C
I**!!
645
1*C9S
1*125
1*1*6
1*C91
1*C92
1*129
1*104
1*160
1*135
1*186
14,791
FSKEIGN
20=
235
260
285
310
335
365
390
420
445
480
515
555
4*80C
TBTAL
US/CANADA
2*365
2,616
2,205
2*628
2,845
2*996
3*131
3*347
3*629
3*S69
4,210
4,510
4,9Q6
43,256
TOTAL
2*570
2,851
2*465
2'9l3
3*155
3*331
3**96
3*737
4*049
4*31*
4*690
5*025
5'*61
48*056
en
-b
-------
Annual Investment
($ Billions)
U.S. Refinery Investment
68-70 Reported
71-72 Projected
73-80 Estimated Maximum Growth
Schedule A Investment Required
7.0
6.0 -
5.0 -
4.0 -
3.0 .
2.0 -
1 .0 .
0
68 70 72 74 76 78 80
Year
Figure 4-3. Annual Investment ($ Billions
For Schedule A
RGH-015
Bonner & Moore Associates, Inc.
4-55
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Annual Investment
($ Billions)
(T) U.S. Refinery Investment
68-70 Reported
71-72 Projected
73-80 Estimated Maximum Growth
(2) Investment Required for Schedule G
7.0
6.0
5.0
4.0
3.0
2.0
1.0 -
68 70 72 74 76 78 80
Year
Figure 4-4. Annual Investment ($ Billions!
For Schedule G
RGH-015
Bonner & Moore Associates, Inc.
4-56
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U.S. Refinery Investment
68-70 Reported
71-72 Projected
73-80 Estimated Maximum Growth
Investment Required by Schedule L
Annual Investment
($ Billions)
7.0
6.0
5.0
4.0
3.0
2.0 -
1.0 -
68 70 72 74 76 78 80
Year
Figure 4-5. Annual Investment ($ Billions)
For Schedule L
RQH-015
Bonner & Moore Associates, Inc.
4-57
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Annual Investment
($ Billions)
7.0
6.0
5.0
4.0
3.0
2.0 -
1.0
U.S. Refinery Investment
68-70 Reported
71-72 Projected
73-80 Estimated Maximum Growth
Investment Inquired by Schedule M
68 70 72 74 76 78 80
Year
Figure 4-6. Annual Investment {$ Billions)
For Schedule M
RQHT015
Bonner & Moore Associates, Inc.
4-58
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TABLE 36
CONSTRUCTION COSTS BY SECTOR
c. v .
; 7 »
",Arr RIALS
t
i
f i , 1
1
1
r - * •
'•','
7 .;
'/•,
/-.
(;
I !
. ','
'. ^ j
'-••-
r .T/L.O
-••-•.!• j; rr..
f -1
'.: V i
•Jbc
•*ia
45:
•> 7 ;
513
o1^"
;jfl6
6Jc
fe78
72S
5/374
Lr.^T C.(T p..
I
17
1,217
1/449
1/606
1/661
l/8Ct
1/S62
2/067
?,c33
2/394
S/572
18/966
1 J ^ Y E A ><
-3
19
11
3
S
9
5
3
7
7
FIELD LA8HR
H78
619
686
758
8C1
859
921
991
-8
10
17
5
5
11
6
7
7
7
FEES
502
571
596
638
738
795
853
.6
15
7
10
5
8
7
7
2,890
3/2<»6
3/379
3/641
3/973
4/133
4/519
4/848
5/207
38/380
-4
16
12
4
8
9
6
8
7
7
H L
477
'o5«
6c?
iKS
5? 7
b / 7 i <
1/3C6
1/7C6
2/lEG
i/sec
FIELD LABOR
479
60?
726
856
92:
790
773
828
FEES
20 • 281
965
7/836
451
578
680
786
8cO
697
716
768
831
893
7/2CO
2/617
3/363
3/952
4/523
4/456
3/903
4/06C
4/366
4/72C
5/071
41/031
TC;
17
12
4
31
17
1^
-5
-13
7
O
R
7
21
18
7
•14
-2
7
n
-2
28
18
16
2
-13
3
7
3
7
1
28
18
1*
•1
-12
4
8
8
7
tBecause of the depressed prior year, this percentage could be achieved even though
it is slightly above the maximum growth rate allowed in that year. (See page 5-39.)
RGH-015
Bonner & Moore Associates, Inc.
4-59
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TABLE 36 (cont.)
SCHEDULE G
TOTAL US & FOREIGN • Mf$/YR
1971
1972
1973
1974
1975
1976
1977
1S78
1979
1980
ENGINEERING
363
573
643
516
522
553
596
630
673
724
MATERIALS
1/249
1/951
2*486
1/858
1/946
2/114
2/23Q
2/37?
2/556
TOTALS 5/793 20/581
NET CHANGE AS PERCENT QF PRlBR YEAR
1971
1972
1973
197*
1975
1976
1977
1978
1979
198C
5
98
12
•20
1
6
8
6
7
7
•1
56
27
•27
2
5
?
5
7
8
FIELD LA88R
478
558
999
836
734
752
814
868
918
985
7/943
• 8
17
79
•16
•12
2
8
7
6
7
PEES 5 MJSC
442
595
893
697
669
693
753
798
848
910
7/297
-4
35
50
-22
• 4
4
9
6
6
7
2/532
3/678
5/021
3/863
3/782
3/944
4/277
4/526
4/816
5/175
41/614
-2
45
37
-23
-2
4
8
6
6
7
"77
b?.?
b ,': it
£'••«. 7
•ic
tBecause of the
it is slightly
depressed
above the
1/3C6
i / 7 r ^
1..S88
2 > 3 i 3
e/275
2/364
S,':*!
2^/711
VI.AJ;
4
31
17
16
prior year, this percentage
maximum growth rate allowed
IS
479
726
857
967
828
799
851
911
979
7/999
FEES 5 KISC
451
578
680
795
8^3
725
737
785
8^3
2/617
3/363
3/952
4/607
4/705
4/ 058
4/183
4/461
5/145
41/88C
-* -2 1
26t 28 2e
fl IS 1B
18 17 17
13 6 2
-14 -!4 -!«,
-423
6 7 7
7 7 7
7 7 7
could be achieved even though
in that year. (See page 5-39.)
RCfi-OJS
Bonner & Moore Associates, Inc.
4-60
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4.10 EFFECT ON PETROCHEMICALS
Petrochemical feedstock requirements were met in all years in all sched-
ules. Relatively small differences were observed in the costs of producing incre-
mental amounts of these feedstocks. Schedules L and M show the greatest change in
incremental aromatics manufacturing costs because these schedules attempt to sub-
stitute high octane refined components for lead over a relatively short time span.
Consequently, there is a greater demand for the high octane aromatics during this
transitional period.
Although incremental production costs of aromatics did not follow a
marked trend in this study, certain aspects of a lead removal program may affect
aromatics prices. While construction is under way to substantially increase aro-
matics production facilities, short term imbalances between supply and demand may
exist. Such imbalances could manifest themselves in price instability for short-
term aromatics supply.
Other investigators, as well as Bonner & Moore, have published informa-
tion about rising aromatics costs as a consequence of a program to remove lead
from gasoline. Some of these earlier studies showed clearly that added aromatics
costs were closely correlated with gasoline pool octane. Increases of a few
octane numbers over the present gasoline pool quality have been shown, by calcu-
lation, to result in relatively little increase in aromatics cost. As pool
octanes rise above a level of about 94 Research Octane Number, the incremental
cost of aromatics begins rising very rapidly.
In the present study, pool octane requirements for U.S. refineries are
shown to increase relatively little. The target pool octane of 93 RON is below
the point at which rapid increases in aromatics costs occur. Another mitigating
circumstance offsets the natural trend toward higher aromatics costs with
increased octane. This is the trend toward lower gasoline yields which are
reflected in the product forecast. These forecasts show that non-gasoline petro-
leum products are rising more rapidly in demand than is gasoline. Consequently,
during the next ten years it can be expected that gasoline yields will decline.
This means that there is a smaller pool which must be augmented by aromatics pro-
duced from the same crude volume. This reduces somewhat the need for increased
aromatics production. This study shows that most refiners will find it economical
to build additional reforming and aromatics extraction capacity for gasoline.
This demand for extraction capacity, particularly, results in a substantial capac-
ity base to which demands for aromatic petrochemicals can be added. This results
in lowered average manufacturing costs by combining two economic uses for pure
aromatics, gasoline blending and sales. This reduces the fixed cost portion of
total aromatics production costs.
RGH-015 Bonner & Moore Associates, Inc. 4-61
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This study goes into more depth than some previous studies in anticipat-
ing the sources of future aromatics production. Specifically, this study con-
siders the growth in gas oil cracking capacity to serve future olefins needs at
the same time that it considers refinery growth. The cracking of gas oils for
light olefins results in substantial yields of by-product aromatics. Combining
these effects into a model encompassing both the refinery and basic petrochemical
building block industries discloses ways of meeting future aromatics requirements
at relatively lower costs than might be expected when considering the refining
segment of the industry solely.
It is important that the relation between aromatics cost and gasoline
pool octane be clearly understood. This study is premised on an unleaded gasoline
grade of 93 Research Octane Number. Should an octane race develop which would
force octanes back into the 95 to 100 range, then a substantial Increase in aro-
matics costs would occur. Earlier studies have shown that increases in the order
of 50% would be likely if pool octanes rose to the range of 96 to 97.
RGH-015 Bonner & Moore Associates, Inc. 4-62
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4.11
CALIFORNIA MODEL RESULTS
Because the refining environment in California 1s accountably different
from that of the rest of the industry, a separate model was used to examine the
reaction of California refining to lead reduction. It was expected and indeed
found that economic behavior of the California model could be predicted from
the U.S. (ex-California) model behavior. That is, added costs and investments
for lead reduction in California were expected to be higher but proportional to
the costs and investments obtained from the U.S. (ex-California) studies.
To varify this characteristic, a selected set of cases, including a set
of California reference cases was developed. From these it was possible to
define the proportionality of California to U.S. (ex-California) behavior. The
factors shown in Table 37 are the proportionality constants thus obtained.
TABLE 37
COST RATIOS FOR CALIFORNIA ECONOMIC BEHAVIOR
(Ratios = Callfornia/U.S. ex-California)
Investment and related costs
Non-investment costs
Gasoline Situation
3 Grade
1.0
1 .5
2 Grade
0.9
1.7
Using these factors, it was possible to extend the more complete case
analysis of the schedules studied to include the effect of California. In so
doing, it was recognized that inaccuracies in the factors as well as the basic
assumption of proportionality were greatly ameliorated by the fact that
California refining capacity represents only about 12% of the U.S. total.
Construction costs and utility costs were the same for both regional
models. Important differences which account for the differing unleaded gasoline
costs are the higher octane of California gasoline (higher per cent premium sales)
and the heavier crude oils available. The heavier crude refining to produce large
volumes of high octane gasoline are more expensive. Although crude cost 1s lower,
the net effect is higher added cost for lead removal.
BGH-015
Bonner & Moore Associates, Inc.
4-63
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California currently has more hydrocracking and reforming capacity per
barrel of crude capacity than the rest of the refining sector. Lead reduction
tends to accelerate this and as a result, this study shows slightly higher aro-
matics contents in the gasoline pool. It must be noted that no restriction was
placed on gasoline hydrocarbon composition.
RGH-015 Bonner & Moore Associates, Inc.
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SECTION 5
DETAIL STUDY METHODOLOGY AND PREMISES
Methodology of this study included several simultaneous
efforts which were coordinated to produce the final, industry-
wide analysis. A refining and petrochemical modeling team
developed the refining models, while other teams established
product and petrochemical demand projections, distribution
cost analyses, and a process construction industry basis. A
brief review of these methods was presented in Section 2.
The following is a more detailed and comprehensive account of
the study approach.
S.1 STUDY METHODS
1 ) LI1 Model
The basic study technique employed linear programming models to
determine the optimum response pattern of the refining and petrochemical
industry to varying profiles of product demand and lead alkyl (TEL) lim-
itations. TEL limitations were determined by EPA-supplied TEL removal
schedules, which expressed maximum allowable TEL content for each gaso-
line grade in each calendar year through 1980. Motor gasoline demand
patterns, both for two-grade and three-grade environments, were pro-
jected by methods described in paragraph 5.3 of this report, as were
demands for light-end refining products, petrochemicals, and distillate
and heavy fuels. For each case, the demand patterns and TEL limitations
for a subject year were imposed on the models. Plant capacities pre-
sumed or calculated to exist at an earlier date were provided as input,
and an optimum pattern of new equipment construction and refinery opera-
tion was determined.
Previous experience with the stimulus of reduced allowable levels
of TEL in gasoline had Indicated a high degree of correlation between
the reactions of different sized refineries in different geographic
locations, excepting California. Thus, one model represented "large"
refineries exclusive of California. California's refining industry dif-
fered from this norm in the characteristics and behavior, so separate
modeling and analysis was done of this industry segment. The response
of "small" refineries (smaller than 35,000 barrels per day crude charge)
also differs from the patterns exhibited by the balance of the industry,
and these were handled separately by techniques of analysis and extrapo-
lation. Finally, that segment of the refin.ing industry not manufactur-
ing gasoline was excluded from consideration in modeling because it is
R6H-015 _ . 5-1
Bonner & Moore Associates, Inc.
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characterized by refining facilities which do not include the reformers
or catalytic cracking process units needed to manufacture gasoline.
Linear programming was selected as the basic computational tool for
studying these models because of its inherent ability to seek an economic
optimum from the myriad and conflicting choices of equipment selection,
operating conditions, Intermediate feedstock allocation, and finished
product blending. The results of these case studies served as a basis
for further analysis of proposed schedules' Impact on the refining and
petrochemical industry, on two-grade vs. three-grade marketing and dis-
tribution patterns, on the process construction industry, on the small
refiner, and on the consumer. In addition, the results of the earlier
case studies served as a basis for developing additional demand and TEL
limitation schedules designed to further explore specific facets of the
overall technical/economic environment.
2) Peak year
Initial study of the various suggested lead elimination schedules
disclosed an important fact about the rapid reduction schedules' effects
upon the process construction Industry. Rapid lead elimination programs
require a major buildup of construction capacity to a sharp peak, fol-
lowed by a shrinkage In construction business, thereby virtually guaran-
teeing an induced major business cycle in the industry. The causes of
this are quite straight-forward. As allowable lead levels are reduced,
new refinery equipment must be built to replace the octane quality for-
merly supplied by lead additives. The rapid buildup, requirement could
be well beyond any reasonable expectation of growth potential. At this
same time, the increasing proportion of the automotive population rep-
resented by post-1971 cars (requiring lower octane gasoline) causes a
gradual reduction in the average leaded octane level of the gasoline.
If lead levels are reduced too rapidly, the refining industry must install
equipment sufficient to meet, on a low-lead basis, the higher average
clear octane requirement of an automotive population with a substantial
proportion of pre-1971 cars still on the road. As time brings about
further attrition of the older cars, the average octane requirement of
the automotive population will decline, leaving the refining industry
with surplus octane-producing facilities and little incentive or desire
to order new process construction. These factors can result in business
declines in the process construction industry following the "peak year"
of as much as 50%, extending over several years.
RGH-015 Bonner & Moore Associates, Inc. 5-2,
-------
The precise timing of this "peak year" condition, where the gasoline
clear pool octane reaches a maximum, varies depending upon the rate of
lead removal, assumptions concerning the car population, and the increase
in usage of low-octane fuels. Nevertheless, the effect is real and may
result in a rapid buildup of excessive octane-producing refinery
capaci ty.
Each proposed schedule was therefore examined for the possible pre-
sence of a "peak year". Figure 2-1, depicting Schedule G,
shows a typical peak situation occurring in 1974. For each selected
schedule, the product demand and TEL limitation levels occurring at the
peak year were imposed on both models (California, and U.S.A. ex-
California), and the expanded equipment capacities (and associated
investments) over those required to meet 1969 demand patterns were cal-
culated. These capacities were expressed in terms of the additional
capacity required for processing units considered (crude distillation,
vacuum distillation, reforming, alkylation, etc.).
A series of cases was then prepared for those years that preceded
the peak year. For each year studied, the models were provided with
available unit capacities equal to those available at the close of the
prior year, and were allowed to "build" new equipment as needed to meet
the increasing product demands and decreasing allowable TEL levels. In
no event, however, was a model allowed to "build" capacity of any unit
in excess of that previously established as necessary to meet peak year
condi ti ons.
The period between the peak year and the terminal year (1980) was
handled in similar fashion. A terminal year run was made, allowing the
model lo "build" whatever aild I I. i ona I c.jpol Yeaf Analyai:;
All schedules were not subjected to the identical series of solu-
tions. For some schedules, peak year only or peak and terminal years
only were run. For others, intermediate cases were run. The alterna-
tives of running a complete schedule as a very large "time-staged"
linear programming model, or of running without the "look ahead"
afforded by the peak year and terminal year runs were both considered.
RGH-015 Bonner & Moore Associates, Inc.
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The time~staged approach, although It would produce a more rigorous math-
ematical optimum, would have been significantly more expensive. Further-
more, there is serious doubt as to whether the industry itself possesses
the flexibility or the infallible foresight to plan for the "perfect"
solution which such a model would generate. The "no look ahead"
approach, on the other hand, would fail to recognize the level of fore-
sight and advanced planning which occurs in the industry. We believe
that the techniques chosen represent fairly the level and effect of
advanced planning practiced by the industry.
4) Facilities Investment
New facilities investments required by the model solutions were not
costed in the specific unit sizes indicated by the model solutions.
Instead, investment costs were charged as a pro rata fraction of the cost
for typical size refinery units of the types under consideration. For
example, the typical size of a crude distillation unit was determined to
be 70,000 barrels per day. If, for a particular case, the model indi-
cated that 7000 barrels per day of crude capacity was required, the model
refinery would be costed with l/10th the construction cost of a 70,000
barrels per day unit, not with the estimated construction cost of a 7000
barrels per day unit. This can be considered equivalent to interpreting
the solution as implying that, in the year in question, l/10th of the U.S.
refineries built "average" 70,000 barrel per day crude units. The
installation of new equipment in an individual refinery is, of course, a
sharply discontinuous step function when any individual piece of equip-
ment is considered. Consideration of all new construction within the
industry tends to smooth this function considerably, however. The 90% of
refiners who presumably did not build crude capacity in the example year
would have contributed their share to the overall industry construction
pattern through the installation of other needed new equipment.
In practice, refining process capacity is planned and installed to
recognize and accommodate three-to-five years of growth. Taken as a
whole, the capacity growth of the refining sector would appear to be a
relatively smooth function with time. For a specific refinery, however,
growth would actually occur as discrete changes. For this study, it was
assumed that industry-wide smoothing (via the technique described in the
preceding paragraph) tends to reflect an industry capacity which results
in an industry excess no greater than that normally installed.
Added investment is the investment over the reference case for the
U.S. refineries (excluding distribution costs). These figures are
reported under cost effects in Section 4 on a cost in dol1ars-per-year
basis. The total investment per year, except for the cumulative ten-year
investment reported in 1980, is the investment cost per year over 0.2619
(the assumed yearly cost of investment, see Appendix E).
RGH-015 Bonner & Moore Associates, Inc.
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Another consideration must be dealt with to achieve a realistic
added investment cost for unleaded gasoline production. This is the fact
that unleaded gasoline production facilities will often be combined into
a construction program for general expansion. The first assumption of
dealing with "average-sized" process units should give a reasonable
industry-wide added investment picture. However, the reference schedule
uses these same average-sized units, and the investment difference is
between differing numbers of these units. In order to approximate a
truer added investment cost, the difference between reference and subject
case investments was reduced by 30%. This accounts for unleaded gasoline
added investments being expended incrementally over a basic expansion
program and thereby realizing a lower than average investment cost. The
305! figure is representative of the savings that are calculated by the
familiar exponential equation relating capacity and total cost, described
elsewhere in the report.
5) Extrapolation Technique
Extrapolation of single model behavior to represent industry-wide
effects involves assumptions about the character of the refining industry
which are derived from experience gained in previous industry economic
studies3. This experience showed that economic behavior can be expected
to follow size-response relationships similar to that represented in
Fi gure 4-1 .
Dependence upon employing this kind of relationship implies that
characteristics among individual refineries of the refining industry are
either uniform or compensating such that uniform (proportional) behavior
may be assumed. However, successful extrapolation to ooui-all. economic
behavior does not suggest that it is possible to extrapolate other char-
acteristics of a single model to represent characteristics of the indus-
try. Obviously, known geographic differences in raw stock quality, prod-
uct demands and economic conditions cause limited sample extrapolation to
become sufficiently erroneous to warrant not attempting the extrapolation.
For example, extrapolating hydrocracking and cat cracking capacities to
national levels implies that local conditions will need both capacities
or that local needs will balance out. The former is very doubtful and
the latter cannot be tested easily. On the other hand, investment require-
ments for mid-barrel conversion can be extrapolated without needing to
define exactly what kind of process will be involved.
For the purposes of this study, industry-wide economics can be pre-
dicted, but details of processing, including process configuration
details can not be safely extended to represent industry-wide behavior.
The procedures used in extrapolating added costs depend upon the rela-
tionship explained in paragraph 5.4
RGH-015 Boiimrr Ac. Moore Associutes, Inc.
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5.2 REFINING AND PETROCHEMICAL INDUSTRY BASIS
5.2.1 Assumptions Pertaining to Process Unit and Blending Data
Petroleum refining processes exist primarily to separate and to modify
the hydrocarbons contained in crude petroleum so that these separated streams will
satisfy the volume and quality characteristics of fuels and non-fuel products pro-
duced from petroleum. These products include gasoline, jet fuels, kerosene, heat-
ing oils, diesel fuels, lubes, waxes, asphalts and heavy industrial fuel. In
today's refining operations, gasoline is by far the primary product of the refin-
ing industry.
The model employed in this study includes representations of all the
typical existing processes for separation and conversion of crude oil into salable
products. Each process is described in terms of the principal mechanism of repre-
sentation within the mathematical model.
1) ('I'udu Uin Li 1 lali-on
Crude distillation is the process of separating crude oil into nar-
row boiling range cuts via fractionation. These separated hydrocarbons
can then be further processed in downstream units and/or used directly
for product blending.
The model is equipped with a variable which represents the yield
structure of the typical composite crude distilled into the fractions
used in this model. It includes an optional variable which represents
the yields of distilling 12 Ib. natural gasoline.
2) Ct'uda Sir-cam Attr-i.butint
A variety of crude stream attributes are combined during the crude
compositing operations of the model to predict the characteristics of
certain streams. These attributes include the octane numbers of straight
run naphthas, the N2A'st, of straight run naphthas as reformer feeds, the
API gravities and characterization factors of gas oils as catalytic
cracker feeds, and the sulphur contents of atmospheric distillates,
vacuum distillates and vacuum residuum for blending fuels.
IMaphthene plus twice aromatics, used as a reforming feed quality characteristic.
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3) Vacuum Distillation
Vacuum distillation separates reduced crude coming from the crude
unit into defined boiling range fractions via distillation under vacuum
conditions to avoid thermal cracking of these heavier boiling hydrocar-
bons. These fractions can then be processed further or used in blending
for fuel products.
The model has a single variable representing distillation of the
reduced crude from the composited typical crude into the boiling range
fractions used.
4) Thermal Cracking
Thermal cracking is a process of cracking long hydrocarbon molecules
into smaller molecules by exposing the molecules to high temperatures for
a long period of time. The lighter molecules produced (gas and naphthas)
generally require further processing before they can be used in final
products; the heavier molecules can often be blended directly into fuel
oi Is.
The thermal cracker is assumed in this study to represent cracking
of virgin gas oil feeds ranging from 20 to 27 API gravity. Linear inter-
polation between these two is permitted by the model. The thermal gaso-
line is optimally depentanized in the model.
5) Coking
The delayed cokers normally found in U.S. refineries crack vacuum
residuum into lighter hydrocarbons by exposure to high temperatures
for an extended time period. The liquid products from the coker are
similar to that of thermal crackers.
The model contains yield patterns for vacuum residuums, steam
cracked tar, cat cracker slurry, heavy vacuum gas oil, thermal cracked
tar, and visbreaker tar. The model also contains a Conradson carbon
correction to reflect the proper yields on feeds from dependent crude
sources. The light coker naphtha produced is optimally depentanized.
6) Visbreaking
Visbreaking is a process similar to thermal cracking, except that
high temperature retention time is greatly reduced. It is used primarily
as a means of reducing viscosity of the feedstock, not as a means of
cracking.to lighter material. The products can be further processed, or
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the heavier gas oils can be blended into final products. This process is
not common to the modern U.S. refinery and is being phased out by many
of- the older refineries.
The model contains a single variable representing visbreaking of
vacuum residuals into the appropriate products. The visbreaker gasoline
is allowed to be depentanlzed.
7) Catalytic Cracking
The catalytic cracker selectively cracks gas oil feeds into lighter
molecules by exposing the gas oil to a catalyst under high temperatures.
The products include olefinic gasolines of high octane and light olefins
for alkylation feedstocks.
The model assumes a basic feedstock quality of -the following
properti es:
n 796° average boiling point.
n K factor of 11.5.
n Operating at a 60% conversion with 100% zeolite catalyst.
A set of variables represents the collection of various feedstocks
into a cat cracker feed pool, along with their average boiling point and
K factor quantities. The basic yield structure is then adjusted by a K
factor and average boiling point corrections. The model is permitted to
increase severity upwards to a maximum of 75% via another corrector oper-
ation. Still another corrector reflects permission to add alumina
instead of zeolite catalyst. The model also reflects the operation of
splitting full range catalytic gasoline into a "Cc to 250" and a "250 and
heavier" fraction. The operation of depentanizing a catalytic gasoline
is i ncluded as wel1.
8) Steam Cracking
This process is often referred to as an olefin plant, or ethylene
plant, as the primary products are ethylene and other light olefins. The
process cracks feeds ranging from ethanes to gas oils under high tempera-
tures and in the presence of steam.
Although large refineries can and do have steam cracking facilities,
most steam cracking capacity exists in petrochemical plants. The model
used in this study includes steam cracking as a process which can take
refinery intermediate streams as charge stocks to produce ethylene,
RGH Olb DOMIUT At Moore Associates, Inc. 5-0
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propylene, and butadiene and return to the refinery the unused butylenes,
gasoline, gas oil and tar resulting from the steam cracking operation.
The steam cracking process is permitted to vary the severity of cracking
naphthas and gas oil feeds to the steam cracker.
9) Hydrocrackiny
Hydrocracking is a process for cracking heavy gas oils and residuals
under very high pressures in the presence of hydrogen, using special cat-
alysts. This process is used to convert high boiling stocks to lower
boiling stocks, and is similar to cat cracking except that the products
have quite different properties than those from catalytic cracking.
The model permitted hydrocracking of all gas oils. Charge stocks
included coker gas oil, light cycle oil from the cat cracker, light
vacuum gas oil, steam-cracked gas oil if present, a light virgin gas oil,
visbreaker gas oil, heavy vacuum gas oil, gas oils from residuum hydro-
cracking, and virgin kerosene. For each of these feeds, three separate
yield structures representing severity levels are called gasoline, jet
fuel, and distillate operations.
A separate operation is also modeled reflecting the hydrocracking of
topped crude or vacuum residuum with the assumption that this would be a
separate, more expensive unit than the one noted above.
10) Residuum Hydro fin-ing
Residuum hydrofining is the desulfurization of heavy gas oils and
residuals with moderate cracking. The products often can be blended
directly or processed further. The model reflects hydrofining of reduced
crude and vacuum residuum.
11) Vacuum Unit J'or Hydro fined/Hydrocracked Residuals
In design and purpose, this is similar to the vacuum unit for
reduced crude from the crude unit. The model has the ability to build
vacuum unit capacity for further fractionation of 650+ material from
either residuum hydrocracking or hydrofining.
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12) Can Oil/Kerosene Hydrogen Treating
Hydrogen treating of 375°F to 650°F material takes place under mod-
erate pressure and hydrogen atmosphere in the presence of a catalyst.
The process removes sulfur, nitrogen and other Impurities, and saturates
most unsaturated molecules. The model allows treating of all the streams
in the 375° to 650° boiling range. The variables represent yields
based on assumed properties of each feed.
13) Naphtha Hydroyan Treating
Hydrogen treating of naphthas is similar to that of gas oils, except
that the feed is lighter. The primary purpose of this unit is to prepare
reformer feedstock to protect the expensive reformer catalyst from impu-
rities. The model contains numerous variables representing hydrogen >
treating of all potential reformer feeds. These include virgin straight
run naphthas, hydrocrackates , thermal and cat cracked gasolines, and
heavy raffinate from aromatics extraction.
14) Reformer
The catalytic reformer is a process to convert nonaromatics to aro-
matics in a hydrogen atmosphere over a platinum or platinum-rhenium cat-
alyst. The products are prime gasoline blending components and/or aro-
matic extraction feedstocks. The model reflects severity levels from 85
to 105 RON clear and a correction of yields based on feedstock proper-
ties. Reformate was permitted to be blended into gasoline or was fed to
aromatics separation facilities for recovery of pure aromatics.
15) A Ikylation
The alkylation process produces prime gasoline blending components
by combining isobutane with light olefins (C^, C,, C^, or Cg), using an
acid catalyst. The resulting product is a gasoline component with rela-
tively high clear octanes.
The process modeled is the HF acid process. The yield structure
was designed for alkylation of propylene, butylene, pentylenes and steam
cracked C.'s. Because of its relatively high cost, ethylene alkylation
was represented in the model as a separate process and its use was
restricted to ethylene feed.
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16) 1somerization
Isomerization is used to convert straight chain gasoline materials
into their highly Branched isomers. By converting some of the light
materials to their isomers, an increase in octane rating is achieved.
The model depicts a yield structure for butane, pentane and hexane
isomerization, each processed through separate facilities.
17) Merox Treating
Merox treating of gasoline and lower boiling fractions removes mer-
captans by converting mercaptans to disulfides. All suTfur-bearing gaso-
line blending streams were represented as requiring Merox treating.
18) Aromatic Separation
Separation of aromatics is accomplished by a combination of solvent
extraction and fractional distillation steps on reformate. The main pur-
pose of aromatic separation is preparation of benzene, toluene and xylene
as petrochemical feedstocks. The other purpose is the preparation of
i
high-octane blend stocks.
Process yields in the model depicted the performance of a full aro-
matics separation complex. In this process, full range reformate is
charged to a tower whose overhead is the benzene fraction. The bottoms
from the tower feed a second tower whose overhead is the toluene frac-
tion. The bottoms from the toluene tower may go either to gasoline
blending or to a third tower whose overhead produces incidental xylenes
and whose bottoms are heavy aromatics. Aromatics separation was limited
to 95 severity reformate or higher.
19 ) Ilijilftitltuil-ky in I.-ion
Hydrodealky1ation of higher boiling aromatics produces benzene.
This is not a common practice in the industry, and only a small amount of
the benzene production results from this process. The model represented
two feedstocks, toluene and xylene, with their appropriate yields.
20) Hydrogen
Hydrogen manufacture and purification are two separate processes
employed to meet demands for high purity hydrogen. The model's predomi-
nant source of hydrogen is the reformer, with some of the more severe
hydrocracking requiring hydrogen purer than commonly produced from
reformers. This pure hydrogen can be produced either through purifica-
tion or through hydrogen manufacture.
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21) Sulfur Plant
The sulfur plant produces elemental sulfur^from hydrogen sulfide.
All hydrogen sulfide produced as a by-product from other refinery opera-
tions in the model was processed through the sulfur plant.
22) Miscellaneous Units
Besides the common units currently in operation in the U.S., the
model included some processes that have been demonstrated commercially
although currently not used extensively. However, none of these pro-
cesses (listed below) was selected in any of the cases studied.
P Catalytic polymerization.
n Propylene d1sproportionafi on.
n Ethylene alkylation.
n Isobutane cracking.
23) Blending'
The gasoline blending properties of all potential gasoline blending
components were represented as linear blending characteristics. Octane
blending values were supplied for each potential gasoline blending agent
for regular grade and for premium grade blending. This included octane
blending values for both research and motor octane methods, with 0, 0.5,
1.0, 1.5, 2.0, 3.0 and 4.0 grams of lead per gallon. In addition to
octane blending values at various lead levels, the model also included
vapor pressure and distillation blending characteristics of each compo-
nent. These characteristics were the percent distilled at 160, 210,
230, 330, and 360 degrees Fahrenheit, respectively. Table 38 presents
the specifications imposed on each grade of gasoline.
The model data base also provided separate blending recipes for
LPG, for JP4 turbine fuel (two recipes), for "special naphtha" (assumed
to include solvents and other special products) and for extremes in per-
missible composition of propylene used as chemical raw materials (two
reci pes ).
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TABLE 38
GASOLINE BLENDING SPECIFICATIONS
Reid Vapor Pressure, Max.
Percent Distilled at
160°F, Min.
160°F, Max.
210°F, Min.
2100F, Max.
230°F, Min.
330°F, Min.
330°F, Max.
Research Octane Number, Min
Motor Octane Number, Min.
"California model imposed 8
leg Ls lation .
Premi urn
10. 3*
18
33
39
54
49
84
96
100
92
25 max. RVP to
Regul ar
1 0 . 1 *
18
35
39
57
49
84
96
94
86
comply with
New "93"
10.1*
18
35
39
57
49
84
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5.3 DEMAND FORECASTS
5.3.1 Automotive Gasoline Demand Projection Basis
1) Engine Fuel Octane Requirements
In 1970, certain automotive manufacturers publicly declared that
their future cars, starting in 1971, would be satisfied with 91 RON gas-
oline. Thus, the RFP for this study defined a 91 RON quality for future
unleaded fuels. After discussion with several industry groups it was
concluded that the .1971 cars intended for use with 91 RON fuel did not
obtain knock-free performance on this fuel to the extent customarily
expected for consumer satisfaction. Consequently, the EPA task force
changed the RFP premise to 93 RON as the anti-knock quality for unleaded
fuel. The following discussion of this point was developed by Mr. L. H.
Solomon.
Public announcements made by automotive manufacturers regarding fuel
requirements for 1971 automobile models suggested that a 91 Research
Octane fuel would satisfy all new-car production. Unfortunately, these
statements were an oversimplification of a very complex problem. It
might have been more appropriate for the automotive companies to suggest
that 1971 models would be designed with an 8.5-to-l compression ratio.
Unfortunately, it is very difficult to specify in advance the actual
octane requirement- of an automobile population.
Figure 5-1 illustrates the distribution of Research Octane Number
requirements for automobiles as a function of compression ratio"1. It may
be noted that the octane requirements for cars with various compression
ratios have been adjusted for the impact of unleaded fuels. At an 8.5-
to-l compression ratio, the level selected by General Motors Corporation
for most of their 1971 automobiles, approximately 10% of the cars could
be satisfied with a fuel as low as 86 RON, but 2% will require over 96
RON. This variability of octane-number requirement is strictly a func-
tion of the manufacturing tolerances of various parts of the engine. In
previous model years, only about 70% of the nominal regular fuel engines
were technically satisfied* with prevailing regular grade gasoline. It
has been estimated that general consumer satisfication would be approxi-
mately 15% higher than technical satisfaction as measured by a trained
test driver. On this basis, we could anticipate 100% consumer satisfac-
tion with the 1971 automobiles using a 94 RON fuel.
tit should be noted that "satisfaction" in this instance describes the percentage
of automobiles which can be operated without developing a knock perceptible to a
trained test driver.
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Research
Octane
Number
Requi rements
10 20 30 40 50 60 70 80 90 95 98
Percent Cars Satisfied
Figure 5-1. Distribution of Research Octane Number Requirements
As Function of Compression Ratio
Satisfaction ion the part of the consumer is masked to some extent by
the phenomenon of overbuying, i.e. the tendency of a large number of con-
sumers to voluntarily select a premium fuel for some automobiles which
can be technically satisfied with prevailing regular grade fuel.
a Implications of Unleaded Fuel Octane Levels
In light of the available information on octane level require-
ments for 1971 automobiles, three possible study approaches were
poss ible.
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First, it could have been assumed that the automotive industry
would be forced into a reduction of compression ratios to ensure
customer satisfaction with 91 RON unleaded fuels. Assuming a 952
customer satisfaction is to be the selection criterion, this would
restrict future automobile engine manufacture to a compression
ratio of approximately 7.2-to-l. However, based on available lit-
erature, such a reduction in compression ratio would reduce the
thermal efficiency of an automotive engine by approximately 5%.
This reduction in thermal efficiency would result not only in
increased fuel consumption, but in reduced performance of future
automobiles, a reduction certain to be poorly received by the gen-
eralpublic.
An alternate method would have continued the study of a 91 RON
unleaded grade, but would have required a 94 RON unleaded grade in
1975, when catalytic systems will be installed. It would not seem
reasonable to add a fourth grade in view of the considerable
investments required on the part of marketing and distribution com-
panies to segregate an additional grade of motor fuel. If the pre-
vailing regular grade fuel in 1975 is also required to be unleaded,
we would find that not only the new cars, but all of the pre-1975
automobiles designed for operation on regular fuel would be forced
to utilize unleaded gasoline. This would sharply increase the
demand for unleaded fuel in 1975 to a point that may exceed the
maximum capability of the petroleum industry. While such a regula-
tion could be imposed upon the petroleum industry, it does not
appear to be a "most reasonable" basis for impartially measuring
the economic impact of lead removal.
A third course of action would have been to select an unleaded
grade of fuel to be imposed upon the market place, a grade which
would result in general consumer satisfaction with all engines hav-
ing a nominal 8.5-to-l compression ratio. Again using the crite-
rion that 95% of the automobiles must be satisfied on a consumer
basis, and translating that to an 80% technical satisfaction, it
would appear that the 8.5-to-l compression ratio automobile would
require a 93 RON unleaded fuel. Though some 5% of the automobiles
would not meet consumer satisfaction, some oortion of these cars
could be satisfied by a very high octane unleaded grade, such as
Amoco's Super Premium. The remaining motorists would simply have
to adjust to a less than completely satisfactory performance of
their automobile engines.
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n Octane Grade Distribution
Based on preliminary test data available on 1971 automobile
engines, it appears likely that the imposition of a 91 octane
unleaded fuel on the petroleum industry will not yield the minimum
economic impact of removing lead from motor fuel. The variability
in automobile engine manufacture suggests that adoption of va 93
octane unleaded fuel would not permit higher compression ratios
than those of the 1971 models, but would lead to a greater consumer
satisfaction in the performance of cars such as those offered by
major manufacturers in the 1971 model year. While a 91 RON
unleaded fuel could be required, an additional, higher octane
unleaded grade would also be necessary in view of the possibility
of catalytic reactor systems which can only perform satisfactorily
on unleaded fuel. It is doubtful that such a situation would
describe the most likely occurrence within the petroleum and auto-
motive industries unless fuel octane number and/or automotive com-
pression ratio are specified by the Federal Regulations.
The detailed distribution of grade requirements 'used as a
basis for this study is outlined in Table 39.
2) Automotive Gasoline Production Requirements
The gasoline production requirements were forecasted for three
major categories of marketing conditions:
n A base case assuming no lead removal or engine revision
programs.
n Cases involving octane requirement reduction on new cars,
exhaust conversion reactors on 1975 models and later, and two
grades of gasoline produced.
n Cases similar to the foregoing except thres grades of gasoline
are produced.
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TABLE 39
BASIS FOR GRADE DISTRIBUTION - AUTOMOBILES AND LIGHT TRUCKS
3-Grade
Pre-1971 Cars
1971 through '74 Cars
Post 1974 Cars
45.4% Premium 100 RON
54.6% Regular 94 RON
50% Regular 93 RON
50* Regular 94 RON
100% Regular 93 RON
2-Grade
Pre-1971 Cars
1971 through '74 Cars
Post 1974 Cars
45.4% Premium 100 RON
54.6% Regular 94 RON
100% Regular 94 RON
100% Regular 94 RON
n o t e s :
1. Pre-1971 cars are assumed to continue past buying habits. Though
many could operate satisfactorily on 93 RON clear, no incentive
exists to shift to the presumably higher cost unleaded grade.
2. 1971 - 75 cars are all assumed to be 8.5-to-l compression ratio.
About 95% could be satisfied with 93 RON clear. However, only
!>0% will buy 93 clear because of:
n Fear of valve failure with unleaded fuel.
n Established buying habits.
n Likely high cost of 93 RON unleaded fuel.
In a 2-grade market, all 1971 - 75 cars buy 94 RON clear or low
lead because it is the only regular grade available and should be
cheaper than 100 RON leaded.
3. Post-1975 cars all buy clear fuel either 2-grade or 3-grade because
of legal restrictions and catalyst intolerance to lead.
4. Heavy-duty trucks burn 94 RON leaded in 3-grade and 94 clear in
2-grade for all years because of minimum cost.
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National demand forecasts for gasolines, under the above marketing
conditions (see Table 40) were based also upon the following assumptions5:
a) The total vehicle miles driven in each year were calculated
from data supplied by the Environmental Protection Agency, using the
following equations:
billions of car miles = -1:17.54 - 36.86 (y) + 1.2073 (y2)
- .0067 (y3)
o
billions of truck miles = -434.95 + 20.86J (y) - .299 (y )
+ .00184 (y3)
Where y = calendar year - 1899.
b) The truck miles calculated in this way represent all classes of
trucks. These miles were distributed among three classes of trucks
in the following proportions:
n Light duty 45.U
n Heavy duty 42.8%
n Others (non-gasoline) 12.1*
c) The miles driven were converted to gallons assuming the follow-
ing miles-per-gal1 on figures:
Vehicles MPG
Base Case
All cars 14.0
All light duty trucks 11.0
All heavy duty trucks 8.5
Lead Removal Cases
Cars, model 1970 and earlier 14.0
Cars, model 1971 - 1974 (14.0)(.95)i
Cars, models 1975 - later (14.0)(.88)1t
Light duty trucks, 1970 and earlier 11.0
Light duty trucks, 1971 - 1974 (11.0)(.95)t
Light duty trucks, 1975 and later (11.0){.88)tt
Heavy duty trucks 8.5
•'Compression ratio drop'for post-1971 automobiles is reflected by a 5% penalty.
ttCatalytic reactor performance effect for post-l'J75 automobiles is reflected by .1
12% penalty.
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TABLE 40
NATIONAL DEMAND FORECAST FOR GASOLINE
Marketing Category
Three-Grade Subject Cases
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
Two-Grade Subject Cases
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
Two-Grade Reference Case
1971
1972
.1973
1974
1975
1976
1977
1978
1979
1980
Billions of Gallons Per Year
93 Octane
6.2
11.9
17.4
22.4
35.3
47.4
58.9
69.4
78.9
88.4
94 Octane
55.8
57.5
59.2
60.8
55.6
50.9
46.6
42.8
39.2
35.9
62.0
69.4
76.6
83.2
90.9
98.3
105.5
112.2
118.5
124.3
56.1
58.0
59.8
61 .7
63.5
65.3
67.1
68.9
70.7
72.4
100 Octane
29.8
26.0
22.4
19.3
16.2
13.4
10.6
8.1
5.9
4.1
29.8
26.0
22.4
19.3
16.2
13.4
10.6
8.1
5.9
4.1
35.1
36.2
37.4
38.5
39.7
40.8
41.9
43.1
44.2
45.2
Total
91.8
95.4
99.0
102.5
107.1
111.7
116.1
120.3
124.0
128.4
91 .8
95.4
99.0
102.5
107.1
111.7
116.1
120.3
124.0
128.4
91.2
94.2
97.2
100.2
103.2
106.1
109.0
112.0
114.9
117.6
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c) Because the average miles-per-galIon varied with year of manu-
facture in the lead removal cases, it was necessary to estimate the
mileage driven by vehicles of each model year. These were based on
Table 41.
TABLE 41
MILEAGE VERSUS VEHICLE AGE
Age of Vehi cle
(Years)
1
2
3
4
5
6
7
8
9
10
11 and ol der
% of Total Miles
Class Assigned to
Cars
15.74
13.69
12.02
10.04
9.36
8.18
7.55
6.52
5.24
4.31
7.35
Dri ven i n Vehi cle
Vehicle Age
Light Duty
10.0
9.5
9.0
8.5
8.0
7.5
7.0
6.5
6.0
5.5
22.5
Group
Trucks
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d) The requirements of gasoline by grade were assumed to depend
upon vehicle type, grades offered, and model year according to the
proportions shown in Table 42.
TABLE 42
GASOLINE CONSUMED PROFILES
Case and Vehicle
Base Case
Cars and light duty trucks
Heavy duty trucks
Lead Removal, two grades
Cars and light duty trucks, 1970 and older
Cars and light duty trucks, 1971 - 1980
Heavy duty trucks
Lead Removal, three grades
Cars and light duty trucks, 1970 and older
Heavy duty trucks
Cars and light duty trucks, 1971 - 1975
Cars and light duty trucks, 1975 and later
% of Gasoline Consumed
in Each Octane Grade
93
50
100
94
55.6
55.6
100
100
55.6
100
50
100
45.4
45.4
45.4
e) Gasoline consumption in California has for several years been
distributed between premium (100 octane) and regular (94 octane) in
a 60/40 ratio in contrast to a 40/60 ratio for the U.S. as a whole.
(Gasoline production in California exceeds the consumption.)
Approximately 10.5 percent of the total U.S. gasoline consumption is
in California. It was assumed that the California demand for motor
fuels was supplied by California refineries and the production in
excess of California requirements was in the same proportion (among
grades) as the total of the U.S. The California consumption was
assumed to be 60/40, premium/regular, for all cars and light duty
trucks in the base case and for 1970 and earlier models in the lead
removal cases. All other classes of vehicles were assumed to have
the same requirements by grade as defined in d) above.
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5.3.2 Aeronautical and Distillate Fuel Demand Projection Basis
1) Naphtha Jet Fuel Projection
Government purchases of Naphtha Jet Fuel (JP4) were 207,773,000 bbls
in February 1969 (83,218,000 were delivered in the U.S.) and 177,173,000
bbls (81,555,000 bbls in U.S.) in February 19706. Government purchases
of JP4 were projected to increase to 181,866,000 bbls in February 19716.
No switch from naphtha based jet fuels to kerosene base is expected in
the near future7.
The Air Force, which is the only major consumer of JP4, has experi-
mented with a kero-jet fuel (JP8) but is dissatisfied with smoke point
specification performance.
No basis exists for predicting a switch from naphtha jet fuel to
kerosene base in the time period 1971 - 1980. The Air Force has success-
fully resisted such a switch for many years.
Therefore, as the Viet Nam conflict declines, JP4 demand will prob-
ably Fall back to 1965 standards, which are generally consistent with
Government U.S. deliveries in 1969 and 1970. (Jet fuel production his-
tory is shown in Table 43. This volume will probably not exceed
82,000,000 bbls.
TABLE 43
NAPHTHA JET FUEL PRODUCTION HISTORY
Domestic Production8 Growth
Year (Thousands of Bbls) Rate
1969 104,748 13.49%
1968 121,165 10.50*
1967 109,650 22.55%
1966 89,473 8.56%
1965 82,416
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2) Kerosene Demand Projection
Government purchases of JP5 (kerosene based jet fuel primarily used
by the Navy) dropped from 24,931,000 bbls in 1969 to 21,453,000 bbls in
'19706. Total consumption of kerosene based jet fuel rose 17.7% from
1967 to 1968 and 13.72 from 1968 to 1969. Almost all commercial jets
use kerosene based fuel7. Kero-jet fuel could increase 12%/year, but
may be retarded by further introduction of jumbo jets. Kerosene produc-
tion history is summarized in Table 44.
TABLE 44
KER06HNE AND KEROSENE JET FUEL PRODUCTION HISTORY
Year
1969
1968
1967
1966
1965
Domestic Demand8
for Kerosene
(Thousands of Bbls )
101 ,738
100,545
99,061
100,849
93,149
Domestic Demand8
for Kerosene & Kero Jet
(Thousands of Bbls)
318,690
204,013
262,596
226,822
201 ,788
Growth
Rate
8.39%
11 .95%
15.77%
12.41%
Fiscal Year 1971 Government purchases of JP5 wi11'continue to
increase at approximately the same rate as in fiscal 19706. One outside
source predicts an average growth in kerosene jet fuel of 14% from 1971
through 19759.
Assuming no switch over from naphtha based jet fuel, the kerosene
jet fuel demand should grow at about 12%/year for the years 1971 - 1980.
Other demand for kerosene will stay essentially the same at 100,000,000
bbls/year. Total annual demand in 1980. then, would be 774,000,000 bbls.
If JP4 is discontinued in favor of a kerosene fuel, the annual
kerosene demand would be increased by about 80,000,000 bbls/year.
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3) Aviation Gasoline Demand Projection
Government purchase of aviation gasoline dropped from 21,506,000
bbls in February 1969 to 15,954,000 in February 1970G, but.will increase
to about 16,630,000 bbls in February 1971. Aviation gasoline demand is
expected to increase during the 1970's as more private aircraft are used.
Domestic private demand is expected to grow 65% from a 1969 level of
597 million gallons (14,214,000 bbls) to 985 million gallons (23,500,000
bbls) in 1981 °- Aviation gasoline production history is summarized in
Table 45.
TABLE 45
AVIATION GASOLINE PRODUCTION HISTORY
Domestic Production* Growth
Year (Thousands of Bbls) Rate
1969 26,460 -16.17%
1968 31,563 -14.86%
1967 37,074 -10.11%
1966 41,244 -15.08%
1965 48,569
The domestic production of aviation gasoline will not exceed
1969's figure of 26,460,000. Continental U.S. production will continue
to meet average demand requirements of less than 25,000,000 bbls/year.
4) Distillate Fuel Oil Demand Projection
Imports of distillate increased 165.9% over the 10-year period
1959 - 1968 (1968's imports were 46,947 thousand bbls)11. Total distil-
late demand (imports and domestically produced) in 1968 was 873 million
bbls11. Both total distillate demand (5.29% increase in 1968 over
1967)11 and its major market, home heating, will continue to grow stead-
ily. The next largest market, diesel highway fuel (127.290 million bbls
in 1968) 12, appears to be growing more rapidly. Demand growth for dis-
tillate has been predicted as just over 5%/year9 and 4.44/year13.
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There is no well-defined basis for predicting a rate of growth for
distillate supplied by continental U.S. refineries. The demand for dis-
tillates should continue to grow at an average of approximately 5%/year
for the time period 1971 - 1980. This demand will probably be met by at
least 846,863,000 bbls (1969 production) from continental U.S. refiner-
ies. At this time, an average of 14.600.00014 bbls can be imported.
Distillate production history is summarized in Table 46.
TABLE 46
DISTILLATE PRODUCTION HISTORY
Domestic Production8 Growth
Year (Thousands of Bbls) Rate
1969 846,863 0.0956
1968 839,373 4.34%
1967 804,429 2.5U
1966 784,717 2.57%
1965 765,071
5) Acronau t, i, aul Puul liumand nummary
Table 47 summarizes the projected demands for all aeronautical and
dis ti]late fuels.
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TABLE 47
DISTILLATE PRODUCT BLEND
(MILLIONS OF BBLS)
Product Location 1969 1970 1971 1972 1973
Light Distillate Fuel*
California 51 55 60 65 71
All Other U.S. 268 29.0 314 342 373
Total U.S. 319 345 374 407 444
Naphtha Jet Fuel**
California 26 24 22 21 21
All Other U.S. 79 73 68 62 62
Total U.S. 105 97 90 83 83
Heavy Distillate Fuel***
California 55 58 61 64 67
All Other U.S. 791 831 872 916 961
Total U.S. 846 889 933 980 1,028
Base Assumption - "California" will behave "like all
* For LDF: .Assume 32% of total is kerosene, which is
7.5 to 12%/year.
California then has 16.3 mm bbls fixed and. 34. 7
All other then have 85. 5 mm bbls fixed 'and 182.5
** For JP4: Assume 7.5% decline first 3 years, then no
***For Distillate: Assume 5% growth.
1974
77
407
484
21
62
83
70
1 ,010
1,080
other U.S.
1975 1976
85 93
446 489
531 582
21 21
62 62
83 83
74 78
1,060 1,113
1,134 1,191
" in regard to
a stable demand; and 68%
will grow @ 12%/year.
will grow @ 12%/year.
change.
1977
102
537
639
21
62
83
82
1,169
1 ,251
these
1978
113
592
705
21
62
83
86
1 ,227
1 ,313
products .
is kero-jet whi
1979
124
652
776
21
62
83
90
1 ,288
1,378
ch will
1980
137
720
857
21
62
83
94
1,353
1 ,447
grow @
0
o
3
O
1
S
o
0
A
S
n
en
i
i i
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5.3.3
Petrochemical Demand Projection Basis
Table 48 presents the national forecasts of petrochemical demands for
the period 1971 - 1980. Bases for individual petrochemical projections are
described below!
1) Ethylene Demands
An examination of several published sources reveals forecasts for
domestic ethylene demand growth rate range from 9%15 to 11X16.17>18 per
year from 1970 to 1980. Similar ranges of estimates exist about 1970's
demand, e.g., from 15.017 to 17.215 bi1 lion'pounds.
The maximum growth rate, 11%. applied to the 1969 usage (14.25
billion pounds) established for prior Bonner 8 Moore studies, produces
a 1970 demand of 15.8 billion pounds. Growth of this demand at a con-
stant 112 over the years 1970-80 will result in a computed 1980 demand
of 45.3 billion pounds, which is comparable to that forecast by Struth16
(45 billion pounds) and by Mills and Tosh19 (44.3 billion pounds maxi-
mum) .
TABLE 48
7
NATIONAL DEMAND FORECAST FOR PETROCHEMICALS
Year
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
Annual Demand
(Billions of Lbs.)
Ethylene
17.5
19.5
21.7
24.1
26.8
29.8
33.1
36.7
40.8
45.3
Propylene
9.0
9.9
11.1
12.3
13.6 .
15.1
16.8
18.7
20.7
22.9
Benzene
9.4
10.3 .
11.4
12.5
13.8
15.1
16.6
18.3
20.1
22.2
Toluene
1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.8
1.9
2.1
Xy lene
2.6
2.9
3.2
3.5
3.8
4.2
4.7
5.1
5.6
6.2
Butadiene
3.2
3.4
3.6
3.8
4.0
4.2
4.5
4.8
5.1
5.4
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At this rate, the 1975 demand of 26.8 billion pounds agrees reason-
ably well with Collinswood17(24 billion pounds) and Lewis20(25-28 billion
pounds). If a growth rate of 11%/year were applied to Col 1inswood's
1970 demand projection (15 billion pounds), the resultant 1975 demand
would be 25.3 billion pounds and the 1980 demand would be 42.6 billion
pounds. Other literature examined15quotes Donald 0. Swan, President of
Esso Chemicals, as predicting a 9% growth on a 1970 base of 17.2 billion
pounds, resulting in a 1980 demand of 39 billion pounds. Humble Oil
predicts21 a 9% growth from 1970 to 1975 and an increasing growth, rate of
10+% from 1975 to 1980.
The EPA study used an 11% growth rate for ethylene. This rate is
recognized by general consensus in the literature through 1975. Past
1975, 11% appears to be as well recognized as any other rate. For two
decades, forecasters have been predicting a decline in ethylene growth.
While this decline may finally arrive in the mid-70's, no literature
referenced gave a reason to expect this to happen.
2) Propylene Demands
Propylene growth rates have been forecast at 9%17, 11.6%19, and 7+%22
for the period 1970-1980. These rates have been applied to various base
1970 demands, all in excess of 7 billion pounds. Forecast demand by
1975 range from 11.2 billion pounds to 17.2 billion pounds, and by 1980
they range from 16.4 billion pounds to 30.3 billion pounds.
A .growth factor of 11%, applied to Bonner & Moore's 1969 demand
estimate of 7.3 billion pounds, produced a calculated 1975 demand of
13.6 billion pounds and a calculated 1980 demand of 22.9 billion pounds.
These demand forecasts are higher than those established by Collinswood
and Ockerbloom6 but within the range set by Mills and Tosh.
No evidence was observed that would indicate any predictable drop
in propylene demand in the 1970's. The EPA study therefore used an 11%
growth rate, which is slightly less than that established by Mills and
Tosh, to establish an acceptable propylene demand forecast through the
period 1970-1980. Use of an 11% growth rate on a 1969 base of 7.3
billion pounds produces a 1975 demand of 13.6 billion pounds and a 1980
demand of 22.9 billion pounds, which are close to Humble Oil's forecast
of 13.4 and 21.1 billion pounds, respectively.
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3) Butadiene Demand
The general absence of literature which forecasts demand growth for
butadiene indicates its tendency toward oversupply and fixed market
position. Demand for synthetic rubber, .a major consumer of butadiene,
is expected to grow at 4%/year in the 1970's15. New uses for butadiene
such as ABS resins may grow in the 1970's, however. These uses appear
to be reflected in Collinswood's forecasts of 3% growth through 1975,
then a rapid acceleration to 8% through 1980. Mills and Tosh forecast
growth ranges for butadiene of 3.9 to 5.2 billion pounds by 1975 and of
4.2 to 7.5 billion pounds by 1985. Humble Oil's forecasts, 4.3 billion
pounds by 1975 and 5.3 billion pounds by 1980, fall within the Mills and
Tosh ranges.
A growth rate of 6%/year applied to a 1969 base of 2.96 billion
pounds provides a demand forecast for the years 1970-1980 which agrees
closely with Humble Oil's projections. These forecast demands fall
within the ranges established by Mills and Tosh and compare with the
1980 demand forecast by Collinswood.
4) Petrochemical Benzene
Because of its potential use as a gasoline blending material and
because of its multiple chemical uses, demands for benzene are difficult
to forecast. A literature search reveals forecasted growths from 4S2 3
to 7%21»2" per year through 1975 and in excess of 7% for the latter 1970's,
Actual demand quantities are forecast as growing from 8.O25'26 to 10.323
billion pounds per year in 1970, to 12.8*3 to 13.321 billion pounds in
1975, and to 14.O2" to 19.221 billion pounds in 1980.
Since petrochemical uses of benzene have grown rapidly, it appears
reasonable to assume demands will continue in the early 1970's so that
it will reach a consensus quantity of approximately 13 billion pounds by
1975. And since no author gives reasons for curtailment of this growth
in the later 1970's, and indeed one source23 shows an increase in the
period 1975-1980, it seems reasonable to apply a growth rate to a base
1969 demand of 7.4 billion pounds (generated for previous Bonner & Moore
studies),which will provide a calculated 1975 demand of approximately 13
billion pounds, and to continue this growth through 1980. A growth rate
of 10% will produce a calculated 1975 demand of 13.9 billion pounds and
a 1980 demand of 22.2 billion pounds.
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5) Petrochemical Toluene
Petrochemical demand for toluene is small in comparison to other
aromatics. Estimates of 1970 demand range from l.O21 to 1.523 billion
pounds, and forecasts for 1980 range from 1.921 to 2.223 billion pounds.
A 10% growth rate applied to the base 1969 demand of 0.83 billion
pounds forecasts a 1975 demand of 1.4 billion pounds and a 1980 forecast
demand of 2.1 billion pounds, which is within the published demand range.
6) Petrochemical Xylene
Xylenes, lead by the ortho and para isomers, have exhibited a rapid
demand growth. Demands for 1970 are set from 1.824 to 2.8523 billion
pounds. All demand growth rates.2: >23.>2"* used for forecasts were approxi-
mately 10%.
A 10% growth rate applied to a. base 1969 demand of 2.18, which was
established for a prior Bonner & Moore study, will provide a calculated
1975 demand of 3.8 billion pounds and a 1980 demand of 6.2 billion
pounds, which is within the published demand range.
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5.3.4 Assumptions Pertaining to Other Product Demands
Fuel gas, coke and sulfur by-products were assumed to have no minimum or
maximum constraints put on them. The model was not committed to maintain a fuel
balance, but was a long-range predicted cost of purchasing outside fuel. The
refinery fuel gas produced was credited at the same value' ($2.93 FOEB). Sulfur
recovered from H_S and the coke produced from the delayed coker were considered
as by-products, and therefore were not constrained. Current values were used,
e.g., coke $5/ton, sulfur $25/long ton.
5.3.5 Assumptions Pertaining to Raw Material Availability
1} Crude
The crude yield and properties of its cuts were determined from
composition of the crudes used in models created for the API study
(Vol. I).3 Therefore, the U.S. model ex-California used the crudes
reflected in 8 models; small refiners were deleted from the set. They
were composited in the ratios used in the API study, correcting for gas-
oline to crude and resulting in an "average" crude for the U.S. The
California crude was determined the same way, using the two California
models from the API study. When establishing a base 1969 case, two
additional crudes were allowed into the solution. These two crudes
represented composited light and heavy crudes that were in the API base
cases, and again the compositing was done in the manner used on the
average crude. The sum charge of these two crudes was not allowed to
exceed ten percent of the total crude selected in the base 1969 cases.
Both models selected ten percent more heavy crude, which was then com-
posited into the average crude so that all subject cases run reflected
this new average crude. Comparison to reported average gravities and
sulfur contents of U.S. crudes was made and a good verification was
found. The volume of crude was al'lowed to seek an optimum at a price
of $3.625/bbl.
2) Twelve-Pound Natural Gasoline
The natural gasoline available as raw materials to refineries was
fixed around the 1969 level. Statistics for natural gasoline and
natural gasoline plus condensate charged to the U.S. refineries for
1968 and 1969 are given below:
Thousand of Barrels
Natural Gasoline N.G. * Plant Condensate
1968 148,132 186,684
1969 157,492 191,824
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The model used in this study does not recognize plant condensate.
which includes a significant amount of natural gasoline as a feed. To
compensate for this, we set the natural gasoline availability somewhat
higher than that reported as such; specifically at 171,200,000 bbls per
year. Of this, 158,500,000 was assigned to the U.S. ex-California
refineries, and 12,700,000 to California refineries.
3) Butanee
The United States Department of the Interior's "Minerals Yearbook"
was used to establish a ratio of normal to iso-butane for the U.S.
excluding California (PADS 1 thru 4) and for California. The 1969 base
cases were, allowed to purchase an unlimited amount of butanes at the
given ratio. The assumption was made that the availability of butanes
would not increase over the next ten years and therefore all subject
cases could purchase from zero to the level established in the base cases
in the ratio mentioned above.
4) Ethylene Plant Gas Feeds
Ethane and propane were allowed to be purchased in the base case
for U.S. model to feed the ethylene plant. The level of purchase in
the.base case was then fixed at the base-case level for all subject cases
on the assumption that ethane/propane availability would not increase
over the next ten years.
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5.4 PROCESS CONSTRUCTION INDUSTRY BASIS
5.4.1 Premises
The process construction Industry Includes the American process plant
contractors, process divisions of larger corporations and those portions of other
major American Industry sectors that support these contractors. They are identi-
fied by their high degree of specialization and by their ability to manage com-
plex, large-scale design and construction projects. Except for a few notable
exceptions, these contractors have no component-making facilities. The construc-
tion load analyzed in this study includes refining and petrochemical investment.
In addition to this type of construction, these contractors are engaged in other
large projects such as power stations, port facilities, metallurgical projects,
and water systems. Recognizing that, within the scope of this study, it is impos-
sible to measure and evaluate all other work areas where the process construction
industry is currently involved, it is assumed that the current capacity in those
undefined areas is capable of expanding to meet growth requirements. It should
be noted, however, that some of this additional construction work may possibly
draw upon the resources required to support petroleum and petrochemical activity,
especially in the field labor market. For example, if the current rate of growth
continues in utility construction, it will be necessary to evaluate the resulting
impact on the field labor market, particularly pipefitters and electricians. It
should also be noted that escalation and labor efficiency have been excluded from
this study. All data are based upon a constant 1972 dollar value and labor effi-
ciency factor.
The refinery investment, on a per-refinery basis, is supplied for each
schedule. The petrochemical investment projected, independent of the refinery
schedule, is from published historical performance.
Given the petrochemical requirements and the yearly investment on a per-
refinery basis for each schedule, this study phase set out to determine:
1) The total U.S. refinery investment.
2) The total construction load on the process construction industry.
3) The maximum growth rate the construction industry can reasonably
achieve.
4) The.feasibility of each schedule, based upon the limits imposed by
the foregoing objective.
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5.4.2 Major industry Sectors Studied
It was necessary to Identify major Industry sectors and to distribute
the investment dollar to each sector. This detailed breakdown was necessary to
derive meaningful capacity limits for industry segments in which the lead time
(prior to facility start-up) varies considerably. The industry was studied 1n
four major sectors:
1) Engineer-ing Included process engineering, estimating and scheduling,
design, project management, contract supervision and overhead.
2} Hardware covered the costs for vessels, columns and exchangers, for
piping and valves, for pumps and compressors, and for controls, electri-
cal wiring, dryers, etc.
3) Field Labor includes pipefittlng, electrical and insulation workers
and others.
4) Fees and Miscellaneous 'covered process fees, contract application
costs and others.
The following list reflects the historical distribution of all process
investment for on-site and off-site facilities. The factors in the foreign column
apply to all foreign investment available to the U.S.-based contractors.
Domestic
(US/Canada) Foreign
U.S. Industry
Engineering 13% 13%
Materials 50% 10%
Field Labor 20% 5%
Fees & Misc. 17% 15%
Foreign Industry 0%
100%
5.4.3 Projection Approach
Given the foregoing relationships and the premise conditions, the load
on each sector was determined and the percent increase over each prior year was
calculated. The percent of increase over the prior year was used as the growth
capability factor for each sector.
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Base capacity calculations for each of the construction sectors used
historical performance of the same process industries evaluated in this study.
Growth was projected from this base, analyzing historical trends and the current
workload, and could be modified significantly by:
1) Drawing from resources currently being used by industries not
included in this study.
2) Having those industries recruit manpower that has historically
worked in the process industries.
From total projections, the expenditures for petrochemicals, foreign
operations, refinery replacement and obsolescence, etc., were subtracted. The
remaining capacity was assumed available for the various lead-removal programs.
It should be noted that any other major changes or environmental regulation
imposed upon the process industry would have to utilize these same resources, and
thus could delay a concerted lead-removal program.
5.4.4 Project Cycle
The model results yielded yearly process construction investment required
to meet projected market demands. This projected investment was then distributed
in time to show when the various construction activities must occur.
Most projects of the type included in this study require from two to four
years for completion. A construction period of 30 months was used 1n this anal-
ysis (see Figure 5-2). This includes 6 months for the start-up year, and two
preceding years. As can be noted from the following table, 96% of the engineering
is completed prior to the start-up year and 1s fairly evenly distributed between
the prior two years, and tends to smooth the sector requirements as related to
the overall investment. The data for this table are from engineering and construc-
tion sources.
Percent Performance by Year
Start-Up Start-Up Start-Up
Construction Sector year .year -1 year -2
Engineering 4 52 44
Materials 2 64 34
Field Labor 28 71 1
Fees & Misc. 14 70 16
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100
80
Complete 60 .
40 .
20 -
Engineering //
Field Labor
Fees £ Miscellaneous
10 20 30 40 50 60 70 80 90 100
% of Projected Construction Time
Figure 5-2. Investment Distribution
for Process Construction Sectors
5.4.5
Historical Investment
•The plot shown in Figure 5-3 illustrates historical investment made by
the U.S. petroleum industry in refining and petrochemicals. The corresponding
data for chemical companies and their petrochemical investment are much more dif-
ficult to define, especially that portion which affects the process construction
industry. . Another factor which further, complicates measuring the chemical com-
panies' impact on the process construction industry is that, during the past sev-
eral years, these companies have been changing from a mode of operation in which
they designed their own plants and procured their materials directly from compo-
nent makers to today's operation in which more than SOX of their major new plants
are engineered, procured, and constructed by process contractors. This is further
reflected in the comment from one major contractor who stated: "In the last few
years we have moved from 100% refining to 100/K chemical business." This shift by
the chemical companies will continue to change the composition of the contractors'
work load and is reflected In the base construction level. Therefore, the petro-
chemical investment which was used as a base was taken from data reported by the
process contractors.
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1500 -
1000 .
Million
Dollars
500 -
100
Maximum Increase %/Year
71.5% Refining
61.5% Chemical
Plants
66.5% Total
Refineries
1960 .1962 1964 1966 1968 1970 1972 1974 1976 1978 1980
Figure 5-3. Historical Investment*7
5.4.6 Projected Maximum Growth Rates by Sector
1) Engineering
The ability of the process Industry contractor to handle a substan-
tial increase In work will be highly dependent upon the timing and the
rate of growth. In mid-1970, the engineering staffs of the process con-
struction Industry reached an all-time high. Since that time this force
has been decreasing. Currently, much of the design engineering force
that has been terminated 1s believed not to have found permanent employ-
ment in other fields and can possibly be attracted back to the process
construction industry. It should also be noted that the retained staff
represents project management and other senior level personnel who are
capable of handling a much larger staff without degrading efficiency.
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Based on the above and on direct Input from the construction and
petroleum companies as reported to the EPA study team, the following
maximum growth was determined.
1973 1974 1975 - 1980
20% 15% 12%/Yr
In order to calculate the percent Increase in 1971, a 1970 base had
to be established. This was accomplished by calculating 1969 engineering
required to support 1969, 1970, and projected 1971 Investment, using the
relationships described earlier (5.4.9 and 5.4.10), and assuming that the
average 1970 engineering level was the same as 1969.
2) Hardware
The manufacturing segment of this industry, as a whole, Is operating
at 60% to 80% of current capacity. Backlog is quite small and a sharp
decline is being projected for the last quarter of 1971. Much of the
total work done by these companies Is external to the construction being
examined in this study and their ability to react to a major expansion is
somewhat dependent upon other construction levels. Another factor to be
considered is the lead time that they have after the engineering has
been initiated. The maximum growth rates used in the analysis are:
1971 - 1972 1973 1974 1975 - 1980
35% 20% 20% 15%
3) Field Labor
The lead time for obtaining a field labor force is approximately one
year (see Figure 5-2). It is therefore concluded that this sector will
not be a limiting factor. In the recent past, however, considerable dif-
ficulty has resulted from reduced efficiency when an abnormally high
demand has been placed upon a local labor force. With this in mind, and
after perusing Bureau of Labor statistics, the following maximum annual
rates for field labor growth were established:
1971 - 1974 1975 - 1980
20%/Yr 15%/Yr
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5.4.7 Refinery Obsolescence and Replacement Costs
The investment required for obsolescence and replacement was set at $284
million for refining in 1969. This amount was increased each year by 1.89Z28 of
the previous year's added investment. The base number was developed by using the
1969 refining capacity, as defined by this study, the obsolescence rate of 1.89%,
and the investment cost of $1,300 per barrel per day.
5.4.8 Petrochemical and Foreign Refining Use of Construction Industry
The rate applied to petrochemical growth is 122 per year for the first
four years and 10% per year thereafter. The 2% decrease after the first four
years reflects completion of environmental and other miscellaneous projects that
are already being planned by the industry. Foreign and residual desulfurization
work is based upon historical performance In the foreign market and upon desulfu-
rization requirements as reported by construction industry sources.
5.4.9 Combined Process Construction Industry Growth Projection
Table 49 shows the combined, maximum process-industry construction capac-
ity in dollars-by-year. Using the maximum growth rates per industry sector and
the average project cycle, maximum annual capacity of the total process construc-
tion industry was derived. The petrochemical and foreign refining demands upon
this capacity were derived from the projections of historical data. These pro-
jections were subtracted from the total annual process construction capacity,
leaving U.S. refining capacity projections shown in Table 49. (The Canadian
refining capacity is 11% of the U.S. refining capacity.) U.S. refining construc-
tion capacity is that available for replacing obsolescent facilities, residual
desulfurization, refinery expansion and lead-removal programs.
At the present time, much of the refining industry is. delaying announce-
ments of future building programs until a positive direction has been established
for lead removal. The impact on the process construction industry is evident;
contractors are reducing engineering staffs, and suppliers are predicting definite
business reductions in late 1971. The current contractor backlog is very low
relative to traditional levels. These observations are taken into consideration
in the projected.growth rates for the various construction sectors. However, this
low construction backlog also implies that other programs are possibly being
delayed for various reasons. If this is a valid assumption, and if other delayed
projects are initiated during the period 1971 to 1980, it shou.ld be reemphasized
that these programs would be competing for the resources allocated in this study
to the lead-removal program.
RGH-015 Bonner & Moore Associates, Inc. 5-40
-------
so
£D
O
ui
TABLE 49
COMBINED PROCESS CONSTRUCTION INDUSTRY MAXIMUM GROWTH PROJECTION
CD
0
3
S
R-
S
0
0
in
in
O
o
MM$/YEAR
PtTK&CHE^ICAL REFINING
r
197;
1SV1
1972
;373
13'-
•:"/ =
1376
;3T7
l£ ~-
;9'3
13-:
;9ai
13.2
T27ALS
tcr|5i<
100
110
122
135
165
105
i.-C5
S3C
e50
iiia
jlO
3".5
2/b85
US/C*N*C* T3TA^
1/2CQ 1/300
1/330 l/t£io
3/2=C 3/530
S/Scj 3/SSC
3/933 »/275
3C/68Q 33/265
FOREIGN
ill
•=:
160
j2;
iSS
!3C
•55
20:
2:5'
sic
2/215
CA\AC*
115
127
. 70
i52
173
236
265
3C5
345
39*
1.1,3-
513
587
3/737
us
1/050
1/158
635
1/336
1,615
2(4t3
2,77j
3/137
3/535
*/C.=5..
1/66C
5/33»
33,976
TSTAL
i,27:
i*5
I,i5£
1/S:5
2/553
2/555
3/Esl
3/S72
*/ I7-
<-/73s
5/373
6/i3:
39/329
TOTAL
FBREIGN US/CANADA
205
235
260
235
3!0
335
365
390
<>20
4-5 •'
"80 u
515
555
4/800
2/365
2/616
2/205
3/218
3/673
4/403
4/098
5/S16
6/172
6/'J39
7/785
8,753
9/850
68,394
T6TAL
2,570
2/=51
2/*65
3/-C3
3/933
4/733
5/263
5/S;S
6/552
7,33"
8,265
9/268
ic/»:5
73,19*
-------
5.4.10 Extrapolation of Investment per Refinery to Industry Investment
Requirements*9
The model results indicate the investment required for an average sized
refinery in the U.S. (ex California) and California. The investments are
extrapolated to represent total U.S. investment by the following formulas.
1) U.S. (ex California) Investment
1 = investment/98.5MB per day refinery
98.5 - average size of all refineries greater than 35MB/D
.7 (see Figure 4-11)
91 = number of refineries greater than 35MB/D
16.5 = average size of all refineries less than 35MB/D
68 = number of refineries less than 35MB/D
•j
Total Investment = 91 (I )+68( I )Q|y|)
= 91(I)+19.45(I) = 110.45(1)
2) California Investment
I = investment/104 MB per day refinery
104 = average size of all refineries greater than 35MB/D
22.87 = average size of all refineries less than 35MB/D
13 = number of refineries greateY than 35MB/D
.7 = (see paragraph 5.5.1)
6 = number of refineries less than 35MB/D
,-7
Total Investment = 13(I)+6(I)
= 131.0(I)+2.08(1) = 15.08(1)
tlnvestment relationship employed customary form - =
RGH-015 IJonmsr At Mooro Associates, Inc. 5-42
-------
APPENDIX A
LEAD REMOVAL SCHEDULES
Schedules reflect recommendations recently made by
the Commerce Technical Advisory Board (CTAB), i.e.,
general availability of an unleaded yradet of gaeo-
lina hij July '1, IU74, and nation-aide availability
of a liia-Luadud fuci I no Inter than the r-:nd of
calendar yvar
R6H-015
Bonner & Moore Associates, Inc.
A-l
-------
APPENDIX A
SCHEDULE A (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE B (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE C (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE D (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE E (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE F (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE G (2 Pump System)
94 RON
100 RON
SCHEDULE H (2 Pump System)
94 RON
100 RON
LEAD REMOVAL SCHEDULES
(ALLOWABLE LEAD LEVELS GRANS TEL/GALLON)
1971
0.5
3.0
3.0
0.5
3.0
3.0
0.5
3.0
3.0
0.5
3,0
3.0
0.5
3.0
3.0
0.5
3.0
3.0
0.5
3.0
0.5
3.0
1972
0.5
3.0
3.0
0.5
2.0
2.0
0.5
1.0
2.0
0.5
0.5
2.8
0.5
2.0
2.0
0.5
1.0
2.8
0.5
3.0
0.5
2.0
1973
0.5
3.0
3.0
0.5
1.5
2.0
0.5
0.5
1.5
0.5
0.5
2.8
0.5
2.0
2.0
0.5
0.5
2.8
0.5
3.0
0.5
2.0
1974
0.0
3.0
3.0
0.0
1.0
2.0
0.0
0.5
1.0
0.0
0.5
2.8
0.0.
2.0
2.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
1975
0.0
3.0
3.0
0.0
0.5
2.0
0.0
0.5
0.5
0.0
0.5
2.8
0.0
2.0
2.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
1976
0.0
3.0
3.0
0.0
0.5
2.0
0.0
0.5
0.5
0.0
0.5
2.8
0.0
0.0
0.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
1977
0.0
3.0
3.0
0.0
0.5
2.0
0.0
0.5
0.5
0.0
0.5
2.8
0.0
0.0
0.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
1978
0.0
3.0
3.0
0.0
0.5
2.0
0.0
0.5
0.5
0.0
0.5
2.8
0.0
0:0
0.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
1979
0.0
3.0
3.0
0.0
0.5
2.0
0.0
0.5
0.5
0.0
0.5
2.8
0.0
0.0
0.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
1980
0.0
3.0
3.0
0.0
0.5
2.0
0.0
0.5
0.5
0.0
0.5
2.8
0.0
0.0
0.0
0.0
0.5
2.8
0.0
3.0
0.0
2.0
RGH-015
Bomier At Moore Associates, Inc.
A-2
-------
(ALLOWABLE LEAD LEVELS GRAMS TEL/GALLON)
1971 1972 1973 1974 1975 1976 1977 1978 1979 1980
SCHEDULE I (2 Pump System
94 RON
100 RON
SCHEDULE J (2 Pump System)
94 RON
100 RON
SCHEDULE K (2 Pump System)
94 RON
100 RON
SCHEDULE L (3 Pump System)
93 RON
94 RON
100 RON
SCHEDULE M (2 Pump System)
94 RON
100 RON
0.5
3.0
0.5
3.0
0.5
3.0
0.5
2.0
0.5
1.0
0.5
2.0
MIN MIN
MIN MIN
MIN MIN
MIN
MIN
MIN
MIN
0.5
1.0
0.5
0.5
0.5
2.0
MIN
MIN
MIN
MIN
MIN
0.0
1.0
0.0
0.5
0.0
2.0
0.0
MIN
MIN
0.0
MIN
0.0
1.0
0.0
0.5'
0.0
2.0
0.0
MIN
MIN
0.0
MIN
0.0
1.0
0.0
0.5
0.0
0.0
0.0
MIN
MIN
0.0
MIN
0.0
1.0
0.0
0.5
0.0
0.0
0.0
MIN
MIN
0.0
MIN
0.0
1.0
0.0
0.5
0.0
0.0
0.0
MIN
MIN
0.0
MIN
0.0
1.0
0.0
0.5
0.0
0.0
0.0
MIN
MIN
0.0
MIN
0.0
1.0
0.0
0.5
0.0
0.0
0.0
MIN
MIN
0.0
MIN
RGH-015
Bonner & Moore Associates, Inc.
A-3
-------
APPENDIX B
SAMPLE MODEL OUTPUT REPORTS
RGH-015 Bonner & Moore Associates, Inc.
-------
APPENDIX B
SAMPLE MODEL OUTPUT REPORTS
Model solutions were generated as computer printed reports for each
schedule studied. These reports are briefly described here with example reports
of Schedule A, year 1980. One complete set of reports for all schedules and years
studied has been supplied to EPA.
The reports can be described in six categories:
a Build and Expand Investment Summary.
n Material and Economic Balances.
n Blending Summaries.
n Detailed Stream Production/Consumption Reports.
n Utility Summary.
n Overall Economic Summary.
1) Build and Expand Investment Summary
This report includes a row for each active new facility variable,
defining the new stream day capacity constructed, the cost coefficient
on the new facility variable, the investment (broken out as plant, off-
site, catalyst, and royalty), the combined expenses (maintenance,
insurance/taxes/overhead, variable costs and fixed costs) as a single
item, and the capital recovery requirements for each unit.
2) Material and Economic Balances
This group of reports presents weight and volume balances. The
first presents purchases and sales of all weight basis stocks, their
production, the unit price, and the total dollars per calendar day. In
addition, any net production or consumption of weight basis stocks
through volume-to-weight or weight-to-volume conversions is reported,
permitting verification of a complete weight balance around the refinery.
The next report presents similar information for those stocks being
purchased or sold on a volume basis. Note that in order to secure a
proper material balance closure, it is desirable to show volumetric loss
as a sales product, at zero price. All of the information in these two
reports is derived directly from the LP solution.
RGH-015 Bonner & Moore Associates, Inc. . °~*-
-------
3) ' Blending Summaries
This series of reports summarizes the recipe and specification
blended-product formulations. Recipe blended products are reported
first, with volume basis blends following the weight basis blends. For
each such product produced, the composition is displayed both in weight
or volume units, and as a percentage formulation.
In addition to the display of formulations, the specification blend
summaries Include a recap of the status of all specifications. For each
specification on the blend being summarized, the minimum and/or maximum
and the actual final quality is displayed. Although the blend formula-
tions for both recipe and specification blends are developed entirely
from LP solution Information, the specification summary derives some of
its data from the original Input Information.
4) Stream Production/Consumption Reports
These reports include a Unit Operations Recap and an Operations
Summary, presented separately for weight basis and volume basis stocks.
The weight basis Unit Operations Recap includes a row for each stock
referenced on a weight basis in any part of the model (purchases,
sales, blending, unit operations, or weight/volume conversions). It
includes a column for every unit operation, arranged 9 units to the page.
The report displays the total production (as negative numbers) or con-
sumption (as positive numbers) of each stock by each unit. The results
are totaled by columns, giving a quick and convenient verification of
material balance closure around each unit. Following the weight basis
Unit Operations Recap, the weight basis Operations Summary is printed.
The row-wise structure of this report is identical to that of the weight
basis Unit Operations Recap. It includes columns for purchases, unit
operations, recipe blending, sales, and weight/volume conversions. The
entries in the unit operations column are the row totals from the weight
basis Unit Operations Recap, representing the new production or consump-
tion of the stock in question by all of the unit operation submodels
combined. The other columns contain appropriate entries, following the
same sign convention as the Unit Operations Recap. Row totals are cal-
culated and displayed, and a total of zero verifies proper material bal-
ance closure and accountability for all production and consumption of the
stock in question. A final column displays the reduced costs or Incre-
mental value for all of the stocks. Since this report Includes both the
3 character tags and the full 18 character labels for all of the weight
basis stocks, it serves as a convenient cross-reference index of stock
labels and tags.
RGH-015 o „ • , B'3
Boniier & Moore Associates, Inc.
-------
The weight basis Unit Operations Recap and Operations Summary are
followed by a similar pair of reports for volume basis stocks and units.
The volume basis Operations Summary includes a column for specification
blends in addition to the same columns that are included in the weight
basis Operations Summary. If a particular unit has both weight and vol-
ume basis stocks .represented, it is included in both reports.
This group of reports gives a comprehensive picture of the patterns
of production and consumption of all raw materials, intermediate stocks,
and finished products in the refinery model.
5) Utility Summary
The utility summary report presents the net production or consump-
tion of each utility by each unit operation. Each utility occupies a
column of the table, and a row is assigned to each unit operation. The
net utility cost for each unit, and the unit cost and total cos.t for each
utility are reported. If there is a net production (rather than con-
sumption) of a particular utility, its cost is reported.as zero.
6) Overall Economic Summary
The overall economic summary 1s a consolidation and recap of cost
information presented 1n the earlier reports. It Includes the net sales
and purchase figures from the weight and volume basis feed and product
balances, the total utilities from the utility summary, TEL purchases,
and the expenses associated with installation and operation of the new
equipment (maintenance, insurance/taxes/overhead, fixed and variable
operating costs, as well as the capital recovery requirement).
RGH-015 Bonner & Moore Associates, Inc. B-4
-------
I
o
USA/ EX c;#Lir/
PROCESS
V£AK issc/ SCHEDULE A PEAK PERISC RUN PRIOR YEAR is 1970
BUI i.0 A'.C EXPAND INvESTfEM SUMMARY
1 1 1
a
0
3
3
A
0
0
ffl
o
n
iUILU V.-C,-J. .'-.IT
sjUIL- viSS-LA,'::^
3UIL-, VAC
5UJ-LJ t\ f T 1 C
4/0-SIZt
-C.147
-C.128
-C'585
-0.161
-G«186
•Q.fc54
-0«*l6
-C.l'jt
-C.Q5''
"C«e?6l
-C'422
-0.459
-0.153
-0.16*
-C.179
-0.764
-0-316
-0.019
-Q.C62
-2.1C3
-5.Q2C
-C.3C8
-0.013
Tkiii^OTutkiT Ui»
PLANT BFFSITE CATALYST RBYALTY TOTAL */CD .$>co
5/7Q1 5/359 11/059 2/424 5/5ll
3/303 1/156 4/459 977 2*222
6/090
517
189
4/93Q
2/313
1/864
775
1/1C6
5/866
1/149
1/794
1/717
719
544
125
15
0.
43C
118
763
631
2/131
145
53
1/394
675
373
217
310
1/642
138
215
206
86
109
30
2
0
82
23
305
208
245
227
35
45
919
89
17^
8/221
661
242
496 7/116
318 4/033
2/237
1/026
166 1/626
752 9/179
200 1/576
2/010
1/923
805
670
155
16
0
Sll
141
1/068
839
1/802
145
53
1/397
764
490
217
310
1/646
282
440
422
176
143
34
4
0
112
31
234
184
4/097
330
120
3/310
1/836
1«U5
soo
743
4/042
693
1/002
958
401
328
77
8
0
255
70
532
. *18
41/2Q7 14/853
1*5.76
1/933 59/574 12/288
28/571
-------
ya
o
M
o
3
3
n
i
*
2
0
0
3
EX CALIF* YEAR 1980* SCHEDULE A PEAK PERI6B RUN
MATERIAL ANC EC8N8MIC BALANCE-. HEIGHT BASIS
PRODUCTS
ce<: a *s. CO/TON
SULFUR & 425.QC/LT
ETHYLE:,L
PRCiPANt UNSATS
BL'T AuIEf-E
BENZENE!
TSLUENt
XYLENE.S
-EIG^T Less
•„! TO ySL CSNV
T6TAL PRODUCTION
FEECS
ETHA.\E
V8L-TB KT C6KV
T8TAL FEEDST8CKS .
PRBQUCTICN MARGIN
*/i"LB
2*500
11.360
35OCO
37.000
75.000
33-000
29.000
3l« 000
-12.900
MLS/CD
1/578
57
1/160
586
134
560
55
128
457
2*626
7/341
311
7/131
7/341
»/CD
3/945
648
40/605
21/696
10/054
18/481
1/583
3/969
100/980
•2/717
'2/717
98/264
PR1BR YEAR iS 1970
MMLB/YR
576
21
423
214
2Q
00
I
01
-------
i
o
USA/ EX C.ALIF, YEAR
Q
o
3
3
O
I
fr
0
0
O
V)
Iff
0
o
n
£C>-EC;-WLE A PEAK FERI8D RUN
AN.; rC3\eMC BALANCE . V6LWE BASIS
YEAR IS 1970
PR8C.CTS
FUEL GAS
LPu F8,, FILL
93 KPN r-fcTI-W 3ASC
94 ^'J-\ C.eT-'.W GASS
JOU n&.v, r3T8R CiASS
SPECIAL i^APhTn^s
JP-4 NAPr.Tr.A JS.T
KEReSI:.E & JP-5
DIbTILLATE FUELS
RESIOCAL FwEL £IL
vSLt'^LTRIC LOSS
V8L TO *T C6NV
TSTAi. PReDUCTI8N
FEEtS
NSKr-AL ctTANE
ISJ-boTA.\E
\ATcRAi. GASSLI^'E
CnLiuil
XT TC v8L CS,\w
S/BBL
2-930
2-730
4.620
4.630
5.670
4.200
Ilfio
3.780
2.730
•3.15C
•3.260
-3t470
•3.625
BBL/CC
6/906
8C4
47/180
19/3C7
1/837
3/669
1/E88
18/444
34/660
9/644
-7/786
22/577
159/251
1/552
1/4C5
4/C60
142/401
9/433
8/CO
20/236
2/196
217/965
89/39g
10/417
15/*93
6/671
81/340
131/015
26/328
601/056
•6/149
•4/532
-14/0*8
"516/203
»•••«•
TOTAL FEECSTSCKS
PRSDUCT16N MARGIN'
159/252
•541/022
••••««•
60/034
2/52J
294
17/22J
67
l/346
580
6/732
12/65!
3/52(j
•2/842
513
l/*82
5l/976
DO
•sj
-------
TO
ff>
X
I
USA, EX CALIF/ YEAR igSQ/ SCHEDULE A PEAK PERIOD RUN PRjflR YEAR JS 1970
ts WEIGHT BASIS RECIPE BLENDS
o ----•--•.---•-.-•....._...
3
O
Jl PR6PANE UKSATS
o PERCENT
o CBMPBNENT ^LB/CD CBUPSNEN
«
>
» C3U PROPYLENE 586 100»0
o •-••«» •.«».
o
KM*
£ TCTAL 586 lOO'O
ui
M
rt
CD
00
-------
t
o
09
I
«O
USA, EX CALIF' YEAR I9fao, SCHEDULE A PEAK PERI8D RUN
UIE EASIS RECIPE BLENDS
PSJ6R YEAR IS 1970
0
o
3
3
O
•1
8-
0
0
o
ID
HI
0
n
LP3 res PULL
C6MPGNENT
C3S
NEH^.AL BUTANE
T6TAL
EBL/CO
760
PERCENT
COMPONENT
94«5
5»5
80* 1CO»C
*•«»«**
SPECIAL NAPj-jHAS
BbL/CD
PERCENT
C8MP8NENT
HSM MERbX Tr
-------
TO
Ct
X
USA/ EX CALIF/ YEAR 19«0/ SCHEDULE A PEAK PERIOD RUN PRIOR YEAR JS 1970
-.E BASIS RE.CIPE BLENDS
CD
o JP-* NAPHTHA JET
2 PERCENT
f ceMP6,\ENT eaL/co COMPONENT
2
o LLM ,C5-l*5 CKO'^'APt 175 11. 0-
159 1C»0
2CO-320 CR3«NAP. <»6J 29-0
«i HS« MCR'jX TKTD HSR 191 12-0
8 KHR H2 TRTD KEROSENE 6Q4 38. 0
2. ..--.. .....
!»
S TeTA»- i'588 100«0
i
O
-------
A, Ex CAi-iF, vEAR
70
O
A PEAK PEKI8C RUN
L-"SIS SPEC SLE.'CS
S3 *5\ «-.ST9K GASe
PRIOR YEAR jS 1970
i PEF6RT
PERCENTAGE
NC4
IC5
B
o
3
3
n
i
tf
2
o
0
a
o
n
3
n
Pi \TA\t3
2*532
72
'J/7C3
•.AT
T;._
395
XYH
-T r^L.OAsS.
•' \ ~
591
T3..E--' FEED
C«2
1*0
2*6
6.7
3.9
4.3
12*1
6.9
8.6
9.C
1.3
3.6
25.9
4.7
79 10Q.O
CUALITY REPORT
•I^IfU^ CLAU'ITY
12/2CC
2*201
1/900
TLL
rf ._' -,
."'; -N
oo
i
lu.
'd'.Z
2J:
3JC
11C
.0
1S.G
' w - r r
93.C
85.0
1C.1
33<6
5.?. 8
92-7
MAXIMUM
35«0
57«0
96«0
-------
USA/ EX CALIF, YEAR 198Q*
o
(71
A PEAK PERIOD RUN
BASIS SPEC BUE\CS
94 «8N M8T8R GAS8
PRI0R YEAR JS 1970
VQLUKE AND COMPOSITION.REPORT
td
• o
3
3
o
i
2
o
o
NU
LLn
TtJ BLEND
NCR.-.AL BUTA.VE
FCM
HCM
145-200 CRC'NAP,
C5-oOO VlSB'SASb.
C5-<.30'CAT GAS8.
250-410 CAT GAS8
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VOLUME
BBL/CB
927
745
517
9*253
494
1*769
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4.8
17.6
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160 PCT SFF AT 160
210 PCT &FF AT 2ic
230 PCT OFF AT 230
330 PCT SFF AT 33c
86.Q
18.0
39.Q
49.0
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CUALITY REP3RT
CUALITY
2.771
94.0
86.0
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57,0
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USA* EX CALIF* vE*S
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39.9
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92'0
18.Q
39. C
49.0
84.Q
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10.3
33.0
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67.7
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00
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USA, EX CALIF/ YEAR 198Q, SCHEDULE A PEAK PERIOD RUN P«I3R YEAR l'S 1970 1 10
VOLIKE BASIS SPEC BLENDS
KER8SJNE 5 JP-5
ffl 'VOLUME AND COMPOSITION REPORT
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141
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USA, EX CALIF, YEAR 198C, SCHEDULE A PEAK PERIOD RUN
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1 13
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251
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T^'C L7l'.A: .-;.?.
-c ;-e.
3.?«
TS'C \;£i 3.3'
TRT-: L" C^CLL -IL
H2 "-»: L • • CC-< '-Ar
C6-c=C C'7 GiSS.
H2 TTtT^ .-.-» CAT
S3 3c .• : i-
9J b£. =E
85 S£-, ^£
b£. ==:-•;•, --.ATE
PEA*
UNITS KEC BUN
P?:ieR YEAR is 1970
1 20
C
-1*373
•141
-<,S5
•309
-2*347
1*787
•16*762
•3C6
•2*G32
•6*327
-72
•773
1*5*6
1*8C5
•3*C98
C
•1*769
95 Sil. F.'.L. =F-.T
C
0
•12»2CC
3*136
SPEC ^LN SALES y/w ce\v
1*373
1*1
4&5
309
2*347
•1*787
13*57?
306
2/032
6*327
72
773
•1*546
1*805
3*098
1*769
•4*384
4*248
12*200
TBTALS
0
0
0
0
0
0
0
•0
0
0
0
0
0
0
0
0
HBB
HBF
HLG
HUB
HHB
Lee
GS8
SCO
KHR
CFD
C2S
FCG
hce
LCG
HCG
CCS
LCD
NC5
LA3
LA4
LAS
IC5
HVA
SC4
P8L
' SOS
SLG
SHV
SKB
SV8
SCY
RF1
SBN
HRF
TCC
TLK
DLC
HCH
TCH
PYR
SCN
F05
FOO
F95
F9Q
F85
SOS
SOQ
S95
INCR VAL
3.558
. 3.004
4.288
4*288
2.840
4.105
4.185
4.122
4.35Q
•>1»442
2. Q92
4*889
3*520
4*581
5*474
4*337
4.256
3. 180
5.582
5.993
7.Q51
4.800
4.350
2.792
6.188
4.318
4.288
4*288
4*288
4*288
4*288
3*742
5*121
4.304
3*929
4*592
5*276
5.847
6*766
5.925
5.530
5.320
5.171
6.788
5.943
5. 543
-------
70
cn
B
o
9
A
t
2
0
0
"I
a
y
M
O
USA/ EX CALIF/ YEAR 198C/ SCHEDULE A PEAK PERIBD RUN
PURCHASES UMTS REC
90 SEv FULL RF.-T
85 SEv FtLL RF.-.T
C5-IC6 R*FFI\ATE
AKg CIST I '..ATE
XYi-E'-E
HW AHefATJGS
T8LUt\£ DISTILLATE
XYLEf'E T6..E5 FEED
C5-IC6
5-eCO C".
C5"»CO
CS-^CC VIS5
S.=
GAS?.
GAS3,
C5-V30 CAT &AS-«
C5-250 CAT 2AS3
cSi-^lO CAT GAS3
15J-35C. C?rs
THii«.>'.Ai. FE\:
LPo F8^ F-jEL
.-ST'JH G*S6
j ^eiss GAse
JP.4» \APHTi-A jET
XEf
-------
0
o
3
3
2
o
0
1
w
0
o
M
M
CRUDE: DIST
VACUUM
C8KEK 'DE.LD
H'B.nYCSJjF
lyAC dYC« a
CAT C*AC<
ALK CJ-Cd
,\AP.
PYWBL
AR3M SSlr.
PU?<:FC.T
;ex TRT
?LT
[UTILITIES
T3TAL
UNIT CEST £/-MT
T8TAL
193C* SC
ff-
* vt\
ThRfrL-T
142/4C1
63/C96
i5/727
7*S52
2/eC6
SjS
E/=27
27'=C6
S/132.
21*635
£i*e^4
''/SS't
2S*'.86
il/c99
i* J6P
:*us
s
3l*C3l
57
10^*520
5ie/'r77
^-.EDLLE A
STf<
STEAM
fl-LS
1*262
•793
229
185
22
241
-391
101
66
462
487
1/174
730
0
140
•154
-3'762
-0
PEAK PEKI8C RUN
LTILITY Si
KXK
ELEC PKR
K'^H
109/649
31/548
57/371
15/2F9
11*168
552
119,372
83*C22
3^*247
67/326
26/742
3/069
88/477
8/Q25
1*653
3
6
0
194/848
852/336
-O.Q09
,-PKARY
H20
C89L H28
f.-GAL
3/275
1*663
5*341
10*061
16/6^9
33*488-
3/9Q7
2/017
19/376
2*736
1/035
' 1/610
•101/158
-C
PRIOR
ru.L .
FLEL GAS
n^-BTu
15/379
3/786
4/300
1/526
221
75
5/259
9/543
2/*30
811
548
9/629
369
441
68
4/89Q
39/275
-Q'^65
YEAR JS 1970
CRC
CHEM ETC
DOLLARS
379
^
529
2/063
274
44
1/233
88
3/673
51
302
4/767
12/802
•1»000
TOTAL
«/CD
•8/171
•2/054
•2/533
-851
• 586
-40
•4/084
•2/835
•5/030
••1/800
•1/8B9
-371
•8/373
• 297
-205
-317
-0
-0
• 32
•8/853
1 21
-7/927
"27/563 '12*802
An. UTILITIES
•48/292
00
I
"
-------
i
o
ffl
0
(B
1
fr
0
0
A
01
HI
0
o
A
IB
3
n
USA/ EX CALIF/ YEAR 198Q/ SCHEDULE A PEA« PERIOD RUN PRIOR YEAR JS 1970
OVERALL ECONOMIC SUc.rARY
PROM WEIGHT BASIS
SALES . IOC/SBO
PURCHASES . -2/717
^T .98/264 35*866
FROM VOLUME BASIS SUMMARY
SALES 601/056
PURCHASES "5*1/022
NET 60/034 21/913
UT1L 5 MISC 8PER COSTS "48/292 '17/627
TEL PURCHASES .-5*326 -1/944
NET SPERATINQ REVENUE lO<»/679 38/208
E^^SES
MAINTENANCE -9/216
lNS/TAx»eHD -3/072
TOTAL UNITS - -12/288 -4/485
TOTAL NU ECulFf.ENT ExP .-12
-------
APPENDIX C
COMMENTS ON OTHER SCHEDULES OF THE RFP
RGH-015 Bonner & Moore Associates. Inc. '*"''
-------
APPENDIX C
COMMENTS ON OTHER SCHEDULES OF THE RFP
In addition to the four schedules discussed in detail in the body of
this report, the RFP identified nine other schedules. These were either inter-
mediate in their impact to the four schedules or, as in the case of Schedules E
and K, were impossible to achieve within the forecasted construction industry
capacity. Except for Schedules C, D, F and I, every schedule created a business
cycle in the process construction industry. Moreover, each schedule caused a
growth rate in the early years which exceeded the industry's capacity.
With the results derived from the detailed studies, it is possible to
predict by interpolation some of the consequences of the nine schedules not
studied in detail. Specifically, the TEL requirements, aromatic contents of
(\ii-j ol i nu , and* re f i niny Investments have been estimated. Spot checks have been
run to confirm these approximations.
Table C-l presents the lead requirements for these schedules. Table C-2
presents the estimates of aromatics burned in pre-1975 vehicles and Table C-3
presents the projected investment requirements.
RGH-015 Bonner & Moore Associates, Inc. C-2
-------
TABLE C-l
LEAD REQUIREMENTS
(Thousand Tons/Year)
Schedule
B
C
D
E
F
H
I
J
K
1971
207
207
119
207
207
119
119
119
119
1972
190
122
112
190
146
88
88
65
88
1973
155
75
106
189
106
85
65
54
85
1974
106
53
89
176
89
36
18
9
36
1975
62
39
77
158
77
30
15
8
30
1976
54
35
66
0
66
25
12
6
0
1977
46
31
56
0
56
20
10
5
0
1978
39
28
47
0
47
15
7
4
0
1979
33
25
38
0
38
11
5
3
0
1980
27
22
31
0
31
8
4
2
0
TABLE C-2
AROMATICS BURNED IN PRE-1975 VEHICLES
(Million Barrels/Year)
Schedule
B
C
D
E.
F
H
I
J
K
1971
490
490
560
490
490
560
560
.560
560
1972
510
550
570
510
540
610
610
640
610
1973
550
630
600
530
600
630
660
700
630
1974
600
690
630
550
620
780
910
960
780
1975
580
620
560
480
560
740
830
850
740
1976
520
550
500
740
500
680
740
770
790
1977
450
490
440
640
440
630
670
690
710
1978
400
420
390
550
360
570
600
620
630
1979
340
360
340
460
340
500
520
530
540
1980
280
290
270
370
270
480
480
490
500
RGH-015
Bonner & Moore Associates, Inc.
C-3
-------
TABLE C-3
REFINING INVESTMENT
(Million Dollars/Year)
YEAR
SCHEDULE B
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
150
160
170
180
185
190
195
200
127
70
179
226
231
128
131
132
132
133
1,158
635
1.624
2,052
2,097
1,160
1,188
1,202
1,199
1,213
1,411
845
1,953
2,438
2,497
1,468
1,503
1,525
1,526
1,547
SCHEDULE C
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
158
171
157
117
122
123
125
126
1,158
635
1,435
1,556
1,423
1,064
1,108
1,120
1,135
1,148
1,411
845
1,742
1,888
1,750
1,361
1,415
1,434
1,455
1,475
SCHEDULE D
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
138
189
145
127
133
134
131
133
1,158
635
1,252
1,719
1,322
1,150
1,206
1,221
1,191
1,206
1,411
845
1,540
2,068
1,637
1,457
1,524
1,546
1,517
1,538
RGH-015
Bonner & Moore Associates. Inc.
C-4
-------
TABLE C-3 (cont.)
YEAR
SCHEDULE E
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
149
168
176
353
122
122
123
123
1,158
635
1,358
1,530
1,603
3,212
1,106
1,110
1,122
1,117
1,411
845
1,658
1,858
1,949
3,746
1,412
1,422
1,440
1,440
SCHEDULE F
FOREIGN
.CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195.
200
12.7
70
205
167
146
128
133
133
134
133
1,158
635
1,860
1,516
1,326
1,167
1,213
1,210
1,216
1,213
1,411
845
2,214
1,843
1,642
1,475
1,532
1,533
1,545
1,547
SCHEDULE H
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974,
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
156
248
158
120
127
128
127
127
1,158
635
1,414
2,251
1,435
1,095
1,156
1,162
1,158
1,154
1,411
845
1,719
2,659
1,762
1,395
1,469
1,480
1,480
1,481
RGH-015
Bonncr & Moore Associates, Inc.
C-5
-------
TABLE C-3 (cont.)
YEAR
SCHEDULE I
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
201
158
155
117
122
122
122
123
1,158
635
1,830
1,433
1,407
1,068
1,113
1,108
1,113
1,117
1,411
845
2,181
1,751
1,732
1,365
1,420
1,420
1,430
1,439
SCHEDULE J
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
160
227
138
116
121
120
122
119
1,158
635
1,452
1,067
1,255
1,052
1,097
1,092
1,105
1,082
1,411
845
1,762
1,454
1,563
1,348
1,402
1,402
1,421
1,401
SCHEDULE K
FOREIGN
CANADA
US
TOTAL
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
125
140
150
160
170
180
185
190
195
200
127
70
156
248
158
163
118
120
122
123
1,158
635
1,414
2,251
1,435
1,486
1,075
1,088
1,109
1.1H2
1,411
. 845
1,719
2,659
1,762
1,830
1,379
1,397
1,426
1,445
RGH-015
Bonncr it Moore Associates, Inc.
C-6
-------
APPENDIX D
MARKETING CHARACTERISTICS OF OIL COMPANIES
RGH-015 Bormer & Moore Associates, Inc. D"1
-------
o
a:
i
MARKETING CHARACTERISTICS OF OIL COMPANIES
OIL COHPAIIf
Gulf
Hurtle
Sid Oil-til
Std Oll-Hy
Phillips (651)
2S.SI Group 1
A»co
Area
Murphy
Shell
Teiaco
Marathon
Std Oil-Ohio
BP Oil
Boron
Fleetntng
37.41 Group 2
Cities Service
Conoco
Nohll
Chimps (351)
Sun
Union 76
23.21 Group }
Others 13.91 Group 4
Total
Hen Construction
4000/yr i 4 yrs
(1972-7S)
TOTAL
BRANDED
OUTLETS
31271
29427
8217
. 82S4.
13B42
91011
29702
22778
1282
• 22000
40230
361 5
3100
9700
475
29D
133172
9459
6900
25513
7454
16900
16426
82652
49473
356308
16000
PROJECTED STATION
COMMITTED CONVERSIONS CONVERSION t
CONVERSION • 65.81 • S8030
25000
20000
5000
SMM
59885 481
11000
22778
11000
2000
96778
147.010
• 65.81
87627 703
54385 437
0 0
201897 1621
65.81 S8030
1- gride Increnental
10528 85
TERMINALS
TOTAL
485
711
441
26S
. 1902
TERMINALS
CONVERSIONS
« 40t
194
284
176
0
654
TERMINAL
CONVERSION
COST « S150.000
INN
29
43
26
0
98
TOTAL
CONVERSION
COST
{MM
510 - not included in
lead decisions
SMM
746 - already conftted -7*6
as result of lead
decisions
463 - Incremental cost - 463-
to go to 3 grades
0
1719
85 - Incremental cost - 85
to go to 3 grades
Uncomitted1 44U (U]«B5
Coral tted 746
Total 1797
I
IM
-------
APPENDIX E
CAPITAL RECOVERY FACTOR
RGM-015 Bonner & Moore Associates, Inc.
-------
APPENDIX E
CAPITAL RECOVERY FACTOR
Premi ses:
1) Economic Life: 16 years.
2) Depreciation for Income Tax: 16 years Double Declining.
3) Income Tax Rate: 48%.
4) Investment Service Cost - Maintenance, Insurance, Taxes and
Overhead: 8%.
5) Rate of Return on Investment: 10% DCF.
Notation:
1) G for Capital Recovery Factor including Income Tax and Investment
Service Cost.
2) C for Capital Recovery Factor with no Income Tax. For 16 years/
10% = .12781. C modified for Double Declining Depreciation = .1278 -
.0066T = .1246.
3) D for Depreciation on SL basis. For 16 years .0625.
4) T for Income Tax. At 48% is .48.
5) S for Investment Service Cost comprising of Maintenance, Insurance,
Taxes and Overhead.
6) P for Investment in Plant = $1.00.
L 'I
'C = * (f *J )— .: Whore i iu 10% diid n Is JO yu.ir:: C. - .12711.
(H-i)n -1
RGH-015 Bonner & Moore Associates, Inc. t-2.
-------
Deri vati on:
G = i-i + SP
.1216 - (.U8) (.0625)
= .1819 + .08
= .2619
-08
RGH-015 Bonner & Moore Associates, Inc.
-------
APPENDIX F
GLOSSARY OF TERMS
RGH-015 Bonner & Moore Associates, Inc. F-1
-------
APPENDIX F
GLOSSARY OF TERMS
Alky lotion
A.P.I. Gravity
A process for the manufacture of high-octane gasoline by
the addition of an alkyl radical to an olefin to produce
a saturated isoparaffln. Sulfurlc or hydrofluoric acids
are the usual catalysts.
A density scale commonly used In the petroleum industry
in America; related to specific gravity by the equation:
sp. gr: at 60°/60°F = i**i.5/(i3i.5 + API°)
Water with 1.0 sp. grav. = 10° API and the lower the sp.
grav., the higher the API gravity.
Base Stock
Blending Octane
Number
A component In a blend which serves no unique purpose.
The apparent octane number of a component when blended
with other components; not necessarily the same as the
octane number determined by testing the unblended
materi al.
Catalytic'Cracking
A process for converting high molecular weight hydro-
carbons into lower boiling hydrocarbons. The process
is catalyzed by an alumna-si 1ca type catalyst.
Charge
Cracking
The material fed or to be fed into a process unit.
A process for changing the chemical composition of a
petroleum fraction wherein the product is predominantly
lighter in molecular weight and lower in boiling range
than the feed. The older cracking processes are ther-
mal whereas more recently catalytic cracking processes
have been perfected. Catalytic cracking has the advan-
tage over thermal cracking 1n that the yield of more
valuable products are greater and the naphtha has a
higher octane rating. For these reasons catalytic
cracking 1s generally preferred despite the greater
complexity and cost of the equipment.
Debutanizer
The fractionator where butane and any lighter hydrocar-
bon is removed from higher boiling material.
RGH-015
Bonner & Moore Associates, Inc.
F-2
-------
Dehydragenation
The removal of hydrogen atoms from a molecule yielding
an unsaturated material, e.g., olefins, diolefins, aro-
ma tics .
Distillate
Distillation
Any overhead product of distillation.
An operation In which oils are separated Into products
of shorter boiling range by successive vaporization and
condensation, usually in a bubble plate fractionating
tower. Rerun distillation refers to the refractiona-
tion of a distillate to recover special boiling range
stocks or to remove undesirable fraction products result-
ing from preceding processing steps. Extractive distil-
lation permits the separation of close boiling compounds
by the addition of another component to modify the rela-
tive volatilities of the original materials. Superfrac-
tlonatlon is a term used to describe a distillation
operation in which at least one of the products is a
relatively pure compound. Stabilization refers to a
distillation carried out to remove light ends from a
heavier fraction.
End-point
(1) The highest vapor temperature reached during a
distillation in which all components are vaporized.
(2) The state of completion of some chemical reaction.
That material which is removed by extraction.
Flash
Flash Point
(1) To distill by equilibrium vaporization in which all
the vapor formed remains in contact with the residual
liquid during the vaporization process.
(2) To ignite momentarily a combustible mixture of
vapor and air. The momentary burning of a mixture of
combustible vapor and air.
Lowest temperature at which a substance gives off enough
vapors under controlled conditions to produce a momen-
tary flash of fire when a small flame is passed near its
surface.
Fuel Oil
Any petroleum liquid product used to produce heat as in
a stove, furnace, or boiler.
RGH-015
Bonner & Moore Associates, Inc.
F-3
-------
Gas Oil
Gasoline
Gravity
Any petroleum distillate boiling approximately between
gasoline end point and 700°F; so named because origi-
nally used iji carbureting water gas.
A mixture of hydrocarbons whose ASTM distillation range
is approximately .90 to 425°F. Finished gasoline con-
tains certain additives such as tetraethyl lead, metal
deactivators, oxidation inhibitors, and dye.
Density; usually refers to °API, a density scale which
is related to specific gravity by the following formula:
'API
141.5
sp.
at 60°/60°r
131.15
Intermediate
Any process material that is in an unfinished state.
Lead Susceptibility
Light Ends
Broadly defined is a measure of the effectiveness of
tetraethyl lead in improving the antiknock properties
of a1 gasoline.
Any material boiling considerably lower than the major
part of the oil in question.
Naphtha
Natural Gasoline
A loose term referring to almost any virgin or straight
run* distil'late boiling below the kerosene range; often,
materials boiling below approximately 200°F are excluded
from naphtha. "Has not been cracked.
i
Gasoline condensed from a mixture of lower paraffin
hydrocarbon gases saturated with vapors of low boiling
liquid hydrocarbon, the mixture occurring naturally in
petroleum fields.
OcLane Numbar
An arbitrary scale for engine knock rating of gasolines,
based on volume percentage of Isooctane in a blend with
n-heptane which shows the same knocking as the motor
fuel under test.
Octane Number, Clear
The octane number of a component or blend without TEL
fluid.
RGH-015
Bonner & Moore Associates, Inc.
F-4
-------
Pour Point
The temperature at which an oil ceases to flow when
cooled under specific conditions.
Kaffinate
Material from which some substance has been removed by
extraction.
Reforming
Reid Vapor Pressure
A process that uses gasoline boiling range material as
the charge stock for the conversion of low octane
straight run naphtha to higher octane material by molec-
ular arrangement and cracking.
Approximately the absolute vapor pressure (expressed in
pounds per square inch) of a material under specified
test conditions.
To redisti11.
Hi::: i.' (i full tin I, tint;
Residue
Hitud OtiLunit Number'
An engine knock rating scale (F-l) based on isooctane
as 100 and n-heptane as zero. Differs from motor method
octane numbers in the speed of the test engine, spark
advance setting and intake air temperature. Research
octane ratings are usually higher than motor octane
ratings depending on hydrocarbon type.
The bottom product from a column; usually refers to
heavy, black material.
The apparent octane number of a gasoline in a passenger
car engine in actual, controlled operation. Road per-
formance and road rating are related terms.
Straight Run
Hydrocarbon material that has not been cracked or syn-
thesized.
Sweet
Containing insufficient mercaptan or sulfide sulfur to
be detected.
.'•'iiii-i1 l.fiti. //;;
Any of several available processes which render petro-
leum products sweet to the doctor test.
Th 'i rma L f.'runki tnj
A process for pyrolysis of hydrocarbons Into lighter
products. Concomitant.ly a small amount of heavier
products is also formed by molecular condensation.
RGM-015
Bonncr & Moore Associates, Inc.
F-5
-------
virgin stock Any petroleum product or Intermediate that was not
produced by cracking or synthesis.
A mild thermal cracking of very viscous material.
The ratio of shear stress to velocity gradient in lami-
nar flow.
RGH-015 Boiincr At Moore Associates, Inc. F-6
-------
APPENDIX R
BIBLIOGRAPHY
RGH-015 Bonner & Moore Associates, Inc.
-------
APPENDIX G
BIBLIOGRAPHY
1. Bureau of Mines Mineral Industrial Survey.
2. United States Department of Commerce Census of Business.
3. API - United States Motor Gasoline Economics, Volume 1, pp. 2-10.
4. Paper presented to California Assembly Transportation Committee, Subcommittee
on Air Pollution, W. Robert Epperly, Esso Research and Engineering Company.
5. Equations furnished by EPA from Bureau of Roads information.
6. oil and Cas Journal, "Military Fuel Demand Turns Up Again," October 26, 1970,
p. 44.
7. Aarlund, Leo R, oil and Cm: Journal, "Refiners Caught as Jet-Fuel Boom Looses
Luster," November 11, 1970, pp. 97-100.
8. United States Department of Interior, Bureau of Mines, I'iji.rblnum ::i.nii:munL
Annual, "Crude Petroleum, Petroleum Products, and Natural Gas Liquids," 1970.
9. Dosher, John R. , "Trends in Petroleum Refining," chemical Kntjinccrimj,
August 10, 1970, p. 102.
10. Oil and Gas Journal, "Jet Fuel to Hit 17.7 Billion Gallons by '81," May 25,
1970, p. 37.
11. National Petroleum News, Mid-May, 1970, pp. 76-97.
12. API, Department of Statistics, Annual Statistical Keview , April, 1970.
13. Oil and das Journal, "IPAA Sees More of Same for '71," November 11, 1970,
p. 46.
14. McCracken, Paul W. and Lincoln, George A., Statement on: "The Fuel Situation
for the Winter of 1970-71," September 29, 1970.
15. nit tinil <;
-------
23. Loehmer, K. H. and Dodge, R. G. , "World Aromatics Review and Forecast,"
presented at joint meeting of Chemical Institute of Canada and ACS Division
of Marketing and Economics, Toronto, May, 1970.
24. Bregazzi , M. , "The Canadian Petrochemical Market Picture," presented at joint
meeting of Chemical Institute of Canada and ACS Division of Marketing and
Economics, Toronto, May, 1970.
25. chemical Week, "Aromatics: Output Up, Profits Down, Demand Soft," August 12,
1970, pp. 7-8.
26. Boulitrop, R., "The Petrochemical World of the 1980's," presented at joint
meeting of Chemical Institute of Canada and ACS Division of Marketing and
Economics, Toronto, May, 1970.
27. Oil and C.ao Journal, February g, 1971.
28. API I'etroleum Facts Figures - 19C?.
29. Oil and Gas Journal, April 6J 1970, pp. 115-144.
(
30. Campau, R. M., Ford Motor Company, "Low Emission Concept Vehicles," Society
of Automotive Engineers, paper no. 710294, presented at the Automotive
Engineering Congress, Detroit., Michigan, January 11-15, 1971.
31. Ecc.leston, B. H. , and Hurn, R. W. , "Comparative Emissions from Some Leaded
and Prototype Lead-Free Automobile Fuels," United States Department of
Interior, Bureau of Mines Publication, R.I. 7390, May, 1970.
RGH-015 Bonner & Moore Associates, Inc. G-3
-------
AN ECONOMIC ANALYSIS
OF
PROPOSED SCHEDULES 0 & N
FOR
REMOVAL OF LEAD ADDITIVES FROM GASOLINE
25 June 1971
Prepared for the Environmental
Protection Agency under Contract
Number 68-02-0050
Bonner & Moore
Associates, Inc.
5OO Jefferson Bldg. | Cullen Center
Houston, Texas 77OO2 | (713) 228-O871
Cable: BONMOR
MANAGEMENT SERVICES OPERATIONS RESEARCH INFORMATION SYSTEMS
PROGRAMMING SYSTEMS
RGH-015 Addendum 1.
TECHNICAL PUBLICATIONS PROCESS CONTROL
-------
TABLE OF CONTENTS
Paragraph Page
SECTION 1
INTRODUCTION
SECTION 2
RESULTS AND CONCLUSIONS
SECTION 3
DETAILS OF THE STUDY
3.1 SCHEDULE 0 - 3-1
3.2 SCHEDULE N 3-9
3.3 IMPACT ON THE CONSTRUCTION INDUSTRY - - 3-19
3.4 IMPACT OF SCHEDULES 0 AND N UPON REACTIVE EMISSIONS -- 3-24
RGH-01 5 Bonner & Moore Associates, Inc.
Addemdum 1
-------
LIST OF ILLUSTRATIONS
Figure Page
2-1 Cumulative Investment Requirements • 2-2
3-1 Refinery Investment Required by Schedule 0 3-21
3-2 Refinery Investment Required by Schedule N 3-22
3-3 Lead and Aromatics Levels for Schedules N and 0 3-25
RCH-015 Uoiincr & Moore Associates, Inc. il
Addendum 1
-------
LIST OF TABLES
Number Page
1 SUMMARY OF RESULTS, SCHEDULES N & 0 - 2-3
2 RAW STOCK REQUIREMENTS FOR SCHEDULE 0 .--- 3-2
3 BY-PRODUCT PRODUCTION FOR SCHEDULE 0 -- 3-3
4 TEL CONTENTS OF SCHEDULE 0 GASOLINES - 3-4
5 GASOLINE SUMMARY FOR SCHEDULE 0 T -- 3-5
\
6 PROCESS CAPACITY GROWTH FOR SCHEDULE 0 --. 3-7
7 COST EFFECTS OF SCHEDULE 0 - --- 3-8
8 RAW STOCK REQUIREMENTS FOR SCHEDULE N 3-10
9 HY-PRODUCT PRODUCTION FOR SCHEDULE N - 3-12
10 AKOMATIC'S AND LEAD LEVELS -- '--- 3-13
11 ' TEL CONTENTS OF SCHEDULE N GASOLINES __-_^-__ 3-13
12 GASOLINE SUMMARY FOR SCHEDULE N - 3-14
13 PROCESS CAPACITY GROWTH FOR SCHEDULE N - 3-16
14 COST EFFECTS OF SCHEDULE N -. - 3-18
15 CONSTRUCTION INDUSTRY INVESTMENTS -- 3-20
16 CONSTRUCTION COSTS BY SECTOR ----- 3-23
RGH-015 • Bonner & Moore Associates, Inc. ill
Addendum 1
-------
SECTION 1
INTRODUCTION
This addendum to "An Economic Analysis of Proposed Schedules for Re-
moval of Lead Additives From Gasoline" (Report #RGH-015) describes the results
of investigating two new schedules for removal of lead additives from gasoline.
The new schedules were designed by the EPA to achieve reasonably rapid reduc-
tion of lead additive content in motor gasolines without the severe impact upon
the Process Construction Industry indicated by preliminary results of the
earlier study.
This investigation of the economic impact of the two new schedules in-
volved the same mathematical models used in previous schedule analyses, and re-
sults are described in comparison to the same reference schedule. The refer-
ence schedule, modeling technique, and other study methodology are described in
Section 5 of the original report.
RGH-015 Bonner & Moore Associates, Inc. 1-1
Addendum 1
-------
SECTION 2
RESULTS AND CONCLUSIONS
Figure 2-1 compares the added investment required over the reference for
the USA refineries for Schedules N, 0, A, and L. This plot clearly illustrates
the comparative severities of each of the schedules. Each of these schedules is
within the capacity of the engineering and construction industry although Schedule
L exhibits business cycle tendencies.
Characteristics of Schedules N and 0 are compared with those of Sched-
ules A and L in Table 1.
RGH-015 Bonner & Moore Associates. Inc. 2-1
Addendum 1
-------
4.0
3.0
US Refining
Cumulati ve
Investment
Above
Reference
($ Billion)
1.0
77 78 79 80
Figure 2-1. Cumulative Investment Requirements
RGH-015
Addendum 1
Bonner & Moore Associates, Inc.
2-Z
-------
TABLE 1
SUMMARY OF RESULTS. SCHEDULES 'N & 0
Characteristi cs
1. Added Yearly
Investment .(MM$
Above Reference1.2
2. Total Added Cost
U Per Gallon)
3. Per Cent Lead.
Reduction
(Above 1971 Base)'
4. Per Cent Crude .
Increase
(Above Reference)
5. Process Industry
Construction
Activity
(% Increase Over
Prior Year)
6. Clear Pool Octane
(RON)
7. Per Cent
Aromati cs
Pool
93 RON
Grade
94 RON
Grade
100
Schedule
A
0
N
L
A
0
N
L
A
0
N
L
A
0
N
L
A
0
N
L
A
0
N
L
Ref.
A
0
N
L
Ref.
A
0
N
L
A
0
N
L
Ref.
A
0
N
L
Ref.
1971
15
-
-
-
0.16
.
_
-
15
0
0
.
0.34
.
-
-
M
(3)
(3)
1
88.5 .
-
.
-
88.4
22
-
.
-
23
18
_
.
-
19
_
_
-
23
32
_
-
_
22
^Excluding Cost for Distribution
21980 Figures are Cumulative
3Includes 1971 Investment
Schedule Year
1972
134
8173
7983
0.20
0 19
0.32
0.48
15
21
59
64
0.67
0.27
1.17
1.77
16
17
21
28
87.7
88.2
91.1
91.7
87.9
_
22
26
27
22
_
34
32
21
_
22
25
24
22
_
15
28
39
24
1973
42
256
95
344
0.23
0.23
0.34
0.56
15
33
59
73
1.37
0.96
1.40
12
10
19
18
87.5
88.8
90.8
92.2
87.6
_
23
26
28
21
_
39
32
20
_
21
26
28
21
_
15
21
37
21
''Calculated on 1971 llase whereas Previous Summary
was calculated on 1970 Base.
1974
187
221
277
412
0.22
0.25
0.41
0.62
15
45
73
82
1.80
1.41
1.42
2.76
4
8
8
14
87.7
89.4
91.7
92.9
87.6
_
24
28
32
21
_
41
41
28
_
21
24
29
21
.
14
27
45
22
1975
122
389
462
825
0.22
.0.27
0.52
0.85
17
59
84
93
1.65.
1.26 .
3.20
-
8
8
(1)
(1)
88.3
90.4
92.8
93.8
87'. 6
_
26
31
36
21
_
39
28
37
_
19
31
36
21
_
18
37
38
21
1976
172
218
290
844
0.21
0.25
0.48
0.90
20
63
88
100
2.42
1.79
2.83
5.03
9
7
3
(12)
88. -5
90.6
92.6
94.4
88.6
24
27
32
38
22
32
39
39
39
20
16
23
35
21
12
23
40
53
22
1980
1462
2008
2474
3456
0.21
0.25
0.36
O.GO
50
77
91
100
3.16
3.02
3.01
3.29
7
7
7
7
90.4
91.5
92.6
93.5
87.9
29
30
31
36
22
34
32
29
42
18
21
38
21
21
13
47
39
33
24
RGH-015
Addendum 1
Dormer & Moore Associates, Inc.
.2-3
-------
SECTION 3
DETAILS OF THE STUDY
3.1 SCHEDULE 0
3.1.1 Description of Schedule
Lead removal Schedule 0 Is for a three-grade marketing environment in
which the lowest octane grade (93.0 RON) is permitted to have 0.5 gm/gallon until
1974, at which-time all lead is removed from it. The two grades corresponding to
current regular and premium gasolines are permitted to contain equal lead levels
throughout the schedule. The lead levels are shown below in paragraph 3.1.5.
3.1.2 Reason for Selecting Schedule 0 for Study
Schedule 0 was designed to remove approximately 60 percent of the current
lead additives without inducing a business cycle in the construction industry.
The scheduled lead removal rate over the current national consumption is shown
below.
Year 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980
% Removal Over 0 21 33 45 59 63 68 71 74 77
1970-71 Usage*
-Average lead level used for base years 1970-71, was 2 . H gin/gallon
3.1.3 Raw Stock Effects
The comparison of raw stock requirements for Schedule 0 to raw stock
requirements for the Reference Schedule is shown in Table 2. Since Schedule 0 is
relatively mild in the early years, its raw stock requirements are similar to
Schedule A.
3.1.4 By-Product Effects
Table 3 shows the production of variable by-products. These are shown
with the Reference Schedule for comparison.
RGH-015 Bonncr & Moore Associates, Inc. 3-1
Addendum 1
-------
O.O
(D I
3 O
TABLE 2
RAW STOCK REQUIREMENTS FOR SCHEDULE 0
(Millions of Barrels/Year)
Normal Butane
Iso-Butane
Natural Gasoline
Subtotal
Crude Oil
TOTAL
% Increase in Crude
1972
Schedule
0
76.8
55.3
192.9
325.0
4565.9
4890.9
0.27
Ref.
69.8
50.2
192.9
312.9
4553.7
4866.6
1973
Schedule
0
72.7
52.4
192.9
318.0
4786.2
5104.2
0.96
Ref.
82.9
59.7
192.9
335.5
4740.6
5076.1
1974
Schedule
0
67.2
48.4
192.9
308.5
5024.3
5332.8
1.41
Ref.
81.6
58.7
192.9
333.2
4954.4
5287.6
1975
Schedule
0 j Ref.
i
81.7; 78.5
58.8
192.9
333.4
5247.1
5580.5
1.26
56.5
192.9
327.9
5182.0
5509.9
1976
Schedule
0
85.8
61.8
192.9
340.5
5514.2
5854.7
1.79
Ref.
79.8
57.3
192.9
330.0
5417.3
5747.3
1980
Schedule
0
92.7
66.8
192.9
352.4
6754.9
7107.3
3.02
Ref.
79.8
57.4
192.9
330.1
6557.1
6887.2
B
0
3
3
O
1
-------
S> TO
a. en
CL n:
n> i
3 O
Q.—•
c ui
TABLE 3
BY-PRODUCT PRODUCTION FOR SCHEDULE 0
Coke, MM Tons/Yr.
Fuel Gas, 1012 BTU/Yr.
1972
Schedule
0
15.7
1222
Reference
15.8
1268
1973
Schedule
0
17.7
1295
Reference
17.5
1292
1974
Schedule
0
19.9
1391
Reference
19.5
1360
1975
Schedule
0
21.9
1404
Reference
21.6
1443
1976
Schedule
0
24.4
1499
Reference
23.8
1528
1980
Schedule
0
37.2
2020
Reference
36.1
2070
03
0
3
3
O
2
0
0
-------
3.1.5 Motor Gasoline Blending
Schedule 0 was designed to remove approximately 60 percent of the
1970-1971 lead usage by 1975. This is achieved by scheduling the lead levels
of the three grades as illustrated in Table 4. Table 5 shows the character-
istics and compositions of the three grades as well as composition of a com-
posited pool of the three grades.
TABLE 4
TEL CONTENTS OF SCHEDULE 0 GASOLINES
(gm/gal)
Grade
93
94
100
Pool
1972
0.50
2.00
2.00
1.81
1973
0.50
1.70
1.70
1.49
1974
0.00
1.50
1.50
1.17
1975
0.00
1.25
1.25
0.84
1976
0.00
1.25
1.25
0.72
1977
0.00
1.25
1.25
0.61
1978
0.00
1.25
1.25
0.53
1979
0.00
1.25
1.25
0.45
1980
0.00
1.25
1.25
0.39
KGH-015
Addendum 1
Homier At Moore Assoriiil.es, Inc.
3-4
-------
TABLE 5
GASOLINE SUMMARY FOR SCHEDULE 0
(Sheet 1 of 2)
93 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi seel laneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthenes
Aromatics
94 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products-
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Miscellaneous
Hydrocarbon Composition, %
I
Paraffins
01,e'fins
Naphthanes
Aromatics
1972
11.9
0.5
93.0
85.0
91.3
82.2
33
5
36
10
10
6
43
16
7
34
57.5
2.0
94.0
86.0
85.7
77.5
43
-
27
-
28
2
45
19
14
22
1973
17.4
0.5
93.0
85.0
91.5
81.8
19
-
53
13
6
9
46
11
5
39
59.2
1.7
94.0
86.0
86.3
78.1
46
3
23
-
28
-
46
19
14
21
1974
22.4
0.0
-
.
93.0
85.0
.
6
62
17
15
-
56
_
3
41
60.8
1.50
94.0
86.0
86.9
78.5
45
5
24
-
25
1
48
19
12
21
1975
35.3
0.0
-
-
93.0
85.0
-
8
61
14
17
-
57
-
4
39
55.6
1.25
94.0
86.0
87.6
79.2
51
9
17
-
23
-
49
21
11
19
1976
47.4
0.0
-
-
93.0
85.0
1
9
60
12
18
-
56
-
5
39
50.9
1.25
94.0
86.0
87.5
79.2
57
12
7
-
24
-
49
24
11
16
1980
88.4
0.0
-
-
93.0
85.0
17
17
40
8
17
1
54
8
6
32
35.9
1.25
94.0
86.0
87.7
79.1
49
5
18
-
28
-
49
21
9
21
RGH-015
Addendum 1
Bonncr Ac Moore Associates, Inc.
3-5
-------
TABLE s
GASOLINE SUMMARY FOR SCHEDULE 0
(Sheet 2 of 2)
100 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Mi seel laneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthanes
Aromatics
Pool:
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Miscellaneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthanes
Aromatics
RON, CL
MON, CL
1972
26.0
2.00
100.0
94.5
93.0
85.1
9
48
23
6
14
-
76
4
5
15
34
11
27
3
23
2
52
15
11
22
88.2
80.1
1973
22.4
1.70
100.0
95.4
93.4
86.6
_
52
24
7
17
-
80
_
5
15
33
11
29
3
22
2
53
14
10
23
88.8
80.6
1974
19.3
1.50
100.0
92.7
94.1
85.5
24
45
15
3
12
1
69
10
7
14
32
11
31
4
21
1
53
13
10
24
89.4
81.1
1975
16.2
1.25
100
92.1
94.9
85.8
23
40
19
5
9
4
65
11
6
18
30
13
32
5
19
1
53
13 .
8
26
90.4
82.0
. 1976
13.4
1.25
100
92
94.8
85.3
20
34
24
5
12
5
65
9
3
23
29
13
31
6
20
1
54
12
7
27
90.6
82.4
1980
4.1
1.25
100.0
92.0
94.7
85.0
.
9
64
-
27
-
53
.
-
47
26
13
34
6
20
1
53
11
7
30
91.5
83.3
RGH-015
Addendum 1
Bonner & Moore Associates, Inc.
3-6
-------
3.1.6 Process Capacity Changes
The capacities of the major processes required for Schedule 0 are
shown in Table 6.
TABLE 6
PROCESS CAPACITY GROWTH FOR SCHEDULE 0
(Millions of Barrels/Day)
Crude Distillation
Coking
Cat Cracking
Hydrocracking
Cat Reforming
Alkylation
Extraction
Isomerization
1972
12.5
1.0
3.6
0.5
2.3
0.8
0.4
0.1
1973
13.1
1.1
3.6
0.7
2.6
0.9
0.6
0.1
1974
13.9
1.3
3.6
0.8
2.9
0.9
0.7
0.1
1975
14.5
1 .4
3.6
1.1
3.1
1 .0
0.9.
0.2
1976
15.2
1.6
3.6
1.2
3.3
1.1
1.1
0.2
1980
18.6
2.4 -
3.6
1.4
4.1
1.2
1.7
0.2
3.1.7
Cost Effects
Table 7 shows the cost differences between the Reference Schedule and
Schedule 0. These costs, shown as it/gallon and as total annual costs, are
broken down into refinery capital investment cost, other refinery costs, and
the cost of three grade distribution.
RGH-015
Addendum 1
Bonner & Moore Associates, Inc.
3-7
-------
O.G?
O.Z
ID I
3 O
O.—•
C (71
TABLE 7
COST EFFECTS OF SCHEDULE 0
National Added Costs, MM$/Yr.
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
Added Distribution Costs
Total Added Costs
National Added Costs. t/Gal*
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
Added Distribution Costs
Total Added Costs
1972
35
(110)
(75)
255
180
0.04
(0.13)
(0.09)
0.28
0.19
1973
102
(213)
(111)
340
229
0.11
(0.22)
(0.11)
0.34
0.23
1974
160
(244)
(84)
340
256
0.15
(0.23)
(0.08)
0.33
0.25
AUsing total gasoline demand as a divisor.
1975
262
(316)
(54)
340
286
0.25
(0.30)
(0.05)
0.32
0.27
1976
319
(380)
(61)
340
279
0.29
(0.34)
(0.05)
0.30
0.25
1977
371
(433)
(62)
340
278
0.32
(0.37)
(0.05)
0.29
0.24
1978
423
(404)
(61)
340
279
0.35
(0.40)
(0.05)
0.28
0.23
1979
474
(519)
(45)
340
295
0.38
(0.41)
(0.03)
0.27
0.24
1980
526
(546)
(20)
340
320
0.41
(0.42)
(0.01)
0.26
0.25
ffl
O
3
3
tf
S
0
0
A
VI
ID
0
O
00
-------
3.2 SCHEDULE N
3.2.1 Description of Schedule
Lead removal Schedule N is .for a three-grade marketing environment in
which the lowest octane grade (93.0 RON) is permitted to have .5 grit/gallon until
1974, at which time all lead is removed from it. The two grades corresponding to
current regular and premium gasolines are permitted to contain equal lead levels
throughout the schedule. For the years 1972-1974, the lead level was determined
by the construction limit, and for 1975-1980 the level was set at 0.5 gm. The
calculated lead levels are shown in paragraph 3.2.5.
3.2.2 Reason for Selecting Schedule N for Study
Schedule N was selected to determine the earliest economically feasible
year for setting the lead level at 0.5 gm's for current premium and regular grade
gasolines. The term "economically feasible" is defined as not exceeding the con-
struction industry growth capacity (see RGH-015, Section 5), and further, as not
inducing a business cycle in this industry. Percent removal over current usage
is shown below.
Year 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980
% Removal Over 0 59 59 73 84 87 88 89 90 91
1970-71 Usage*
-Usage based on average 2. i* gin/gal lead level of average motor gasoline.
3.2.3 Raw Stock Effects
Table 8 shows the raw stock usage of Schedule N. Although Schedule N
is more severe than Schedule 0 in removal of lead, the raw material requirements
do not significantly vary until the peak years of 1975 and 1976, and by 1980 the
raw material requirements are essentially the same as those shown for Schedule 0.
These schedules fall between Schedules A and L (both three-grade schedules) in
crude requirements for the peak years. By 1980 all three-grade schedules demand
about the same amount of additional crude due to the (predominant) percentage of
unleaded 93 octane motor gasoline.
RGH-015 Bonner & Moore Associates, Inc. 3-9
Addendum 1
-------
CXO
Q.Z
(D I
= O
Q.—•
c in
TABLE 8
RAM STOCK REQUIREMENTS FOR SCHEDULE N
(Millions of Barrels/Year)
ffl
o
3
3
S
0
0
n
3
o
Normal Butane
Iso-Butane
Natural Gasoline
Subtotal
Crude Oil
TOTAL
% Increase in Crude
1972
Schedule
N
51.3
37.0
192.9
281.2
4607.0
4888.2
1.17
Ref.
69.8
50.2
192.9
312.9
4553.7
4866.6
1973
Schedule
N
56.8
40.9
192.9
290.6
4806.9
5097.5
1.40
Ref.
82.9
59.7
192.9
335.5
4740.6
5076.1
1974
Schedule
N
67.6
49.5
192.9
310.0
5025.0
5335.0
1.42
Ref.
81.6
58.7
192.9
333.2
4954.4
5287.6
1975
Schedule
N
49.7
35.9
181.4
267.0
5348.0
5615.0
3.20
Ref.
78.5
56.6
192.9
327.9
5182.0
5509.9.
1976
Schedule
N
69.1
49.7
192.9
311.7
5570.8
5882.5
2.83
Ref.
79.8
57.3
192.9
330.0
5417.3
5747.3
1980
Schedule
N
92.7
66.8
192.9
352.4
6754.6
7107.0
3.01
Ref.
79.8
57.4
192.9
330.1
6557.1
6887.2
CO
I
-------
3.2.4 By-Product Effects
Schedule N falls approximately midway between A and L in severity of
processing as indicated by the by-product fuel gas production for 1976 (see
Table 9). Fuel gas production indicates that Schedule N requires more cracking
capacity than Schedule 0 for all years since it removes lead at a faster rate.
Coke production is more closely related to the volume of crude runs. Therefore,
as in the raw material effects, coke make does not significantly vary except
in the peak 1974 and 1976 years.
RGH-015 Bonner Ac Moore Associates, Inc. 3-11
Addendum 1
-------
39 7i
n. e>
D. 2:
Si
Q. —•
C "1
3
TABLE 9
BY-PRODUCT PRODUCTION FOR SCHEDULE N
Coke, MM Tons/Yr.
Fuel Gas, 10i2 BTU/Yr.
1972
Schedu le
N
15.5
1320
Reference
15.8
1268
1973
Schedul e
N
17.4
1344
Reference
17.5
1292
1974
Schedule
N
19.3
1422
Reference
19.5
1360
1975
Schedule
N
22.3
1634
Reference
21.6
1443
1976
Schedule
N
24.7
1691
Reference
23.8
1528
1980
Schedule
N
37.1
2033
Reference
36.1
2070
Q
0
3
S
a
S
o
0
o
00
I
ro
-------
3.2.5
Motor Gasoline Blending
A review of the average aromatic contents of the composite pool for
Schedules A, 0, N, and L for the year 1976 is shown in Table 10. The average
lead level of the pool shows clearly the inverse relationship of aromatic con-
tent to lead level at a given pool octane requirement. Table H shows the maxi
mum lead levels set for the three grades to meet the objectives of the sched-
ule. Table 12 shows the characteristics and composition of each of the three
gasoline grades as well as the properties of the composite pool. A comparison
with the table for Schedule 0 indicates Schedule N is more severe, requiring
more aromatics to make motor gasoline.
TABLE 10
AROMATICS AND LEAD LEVELS
1976 Pool Aromatic Content, %
1976 Avg lead Content, gm/gal
SCHEDULE
AON
24 27 32
1.56 0.72 0.29
L
38
0.0
TABLE 11
TEL CONTENTS OF SCHEDULE N GASOLINES
(gm/gal)
Grade
93
94
100
Pool
1972
0.50
1.00
1.00
0.94
1973
0.50
1.00
1.00
0.91
1974
0.00
0.75
0.75
0.59
1975
0.00
0.50
0.50
0.34
1976
0.00
0.50
0.50
0.29
1977
0.00
0.50
0.50
0.25
1978
0.00
0.50
0.50
0.21
1979
0.00
0.50
0.50
0.18
1980
0.0
0.50
0.50
0.15
RGH-015
Addendum
Bonner & Moore Associates, Inc.
3-13
-------
TABLE 12
GASOLINE SUMMARY FOR SCHEDULE N
(Sheet 1 of 2)
93 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded WON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf f ins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthanes
Aromatics
94 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraf fins
Paraffinic Stocks
Miscel 1 aneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthanor;
Aroma tic:,
1972
11.9
0.50
93.0
85.0
91.1
81.8
33
-
38
18
5
6
46
16
6
32
57.5
1.00
94.0
86.0
88.8
79.7
43
6
27
-
24
-
49
18
8
25-
1973
17.4
0.50
93.0
85.0
91.1
82.0
36
.
36
17
6
5
44
17
7
32
59.2
1.00
94.0
86.0
88.9
79.8
41
5
30
1
23
-
49
17
8
26
1974
22.4
0.0
-
-
93.0
85.0
19
3
44
16
18
-
46
8
5
41
60.8
0.75
94.0
86.0
89.7
80.5
41
11
26
1
20
1
52
17
7
24
1975
35.3
0.0
-
-
93.0
85.0
32
17
22
15
13
1
52
14
6
28
55.6
0.50
94.0
86.0
91.2
81.5
36
7
35
-
21
-
48
15
6
31
1976
47.4
0.0
-
-
93.0
85.0
19
6
41
13
20
1
47
8
6
39
50.9
0.50
94.0
86.0
91 .0
82.0
45
16
19
2
18
-
51
19
7
23
1980
88.4
-
-
-
93.0
85.0
29
19
27
9
15
1
52
12
7
29
35.9
0.50
94.0
86.0
91.2
81.5
21
-
54
-
25
-
50
9
3
38
RGH-015
Addendum 1
Bon tier & Moore Associates, Inc.
3-14
-------
TABLE 12
GASOLINE SUMMARY FOR SCHEDULE N
(Sheet 2 of 2)
100 Octane Blend:
Volume, 109 Gals/Yr.
TEL, gm/gal
Leaded RON
Leaded MON
Clear RON
Clear MON
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthanes
Aromatics
Pool:
Stream Composition, %
Cracked Stocks
Alkylate Products
Aromatic Based
Light Iso-Paraffins
Paraffinic Stocks
Miscel laneous
Hydrocarbon Composition, %
Paraffins
Olefins
Naphthanes
Aromatics
RON Clear
RON Clear
1972
26.0
1.00
100.0
92.9
96.6
86.9
8
34
38
14
6
-
66
3
3
28
34
12
31
5
17
1
53
15
6
26
91.1
81.8
1973
22.4
1 .00
100.0
94.3
95.8
88.1
_
46
29
12
13
-
75
_
4
21
33
12
31
5
18
1
53
14
7
26
90.8
81.9
1974
19.3
0.75
100.0
92.0
96.9
87.2
12
32
38
11
7
-
63
5
5
27
32
12
32
6
17
1
53
13
6
28
91.7
82.7
1975
16.2
0.50
100.0
92.0
98.3
87.8
_
22
58
13
6
1
58
_
5
37
30
12
34
7
16
1
50
13
6
31
92.8
83.6
1976
13.4
0.50
100.0
92.0
97.4
88.6
_
25
56
-
19
-
53
-
7
40
29
13
32
6
19
1
49
12
7
32
92.6
84.0
1980
4.1
0.50
100.0
92.0
97.7
87.8
_
20
57
15
8
-
57
-
4
39
26
13
35
7
18
1
52
11
6
31
92.6
84.1
RGH-015
Addendum 1
noiinor it Mooro Associates, Inc.
3-15
-------
3.2.6
Process Capacity Changes
Table 13 shows the in-plant capacity requirements for the major pro-
cesses. No over building or excess capacity over the normal service factor is
reflected in the figures. These figures represent the normal fresh feed through-
puts for all but alkylation and extraction, which are in terms of product. A
review of the numbers again illustrates that Schedule N is more severe than
Schedule 0 and less severe than Schedule L. As an example, in 1976 Schedule A
required 3.0 of reformer capacity compared with 3.3 for Schedule 0, 3.6 for
Schedule N, and 4.1 for Schedule L.
TABLE 13
PROCESS CAPACITY GROWTH FOR SCHEDULE N
(Millions of Barrels/Day)
Crude Distillation
Coking
Cat Cracking
Hydrocracking
Cat Reforming
Alkylation
Extraction
Isomerization
1972
13.0
1.0
3.6
0.8
2.8
0.8
0.5
0.2
1973
13.4
1.1
3.6
0.9
2.9
0.9
0.7
0.2
1974
14.1
1.2
3.6
0.9
3.1
1.0
0.9
0.2
1975
15.0
1.4
3.6
1.1
3.6
1.0
0.9
0.2
1976
15.4
1.6
3.6
1.3
3.6
1.1
1.6
0.2
1980
19.3
2.4
3.6
1.5
4.3
1.3
2.0
0.3
RGH-015
Addendum 1
Banner Ac Moore Associates, Inc.
3-16
-------
3.2.7 Cost Effects
Table 14 shows the annual cost for Schedule N relative to the Ref-
erence Schedule. These costs are broken down Into refinery investment costs,
other refining costs, and added distribution costs for the three-grade system.
The costs are shown in millions of dollars per year and in cents per gallon,
using the total gallonage of Schedule N for each year.
RGH-015 Bonncr Ac Moore Associates, Inc. 3-17
Addendum 1
-------
Q-JC
n> i
a o
a.—•
c in
TABLE 14
COST EFFECTS OF SCHEDULE N
National Added Costs, MM$/Yr.
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
Added Distribution Costs
Total Added Costs
National Added Cost, it/Gal*
Refining Investment Costs
Other Refining Costs
Total Added Refining Costs
Added Distribution Costs
Total Added Costs
1972
214
(159)
55
255
310
0.22
(0.18)
0.04
0.28
0.32
1973
239
(245)
6
340
334
0.24
(0.24)
0.00
0.34
0.34
1974
312
(234)
78
340
418
0.30
(0.22)
0.08
0.33
0.41
1975
433
(218)
215
340
555
0.41
(0.21)
0.20
0.32
0.52
1976
509
(316)
193
340
533
0.46
(0.28)
0.18
0.30
0.48
1977
530
(379)
151
340
491
0.46
(0.33)
0.13
0.29
0.42
1978
565
(524)
41
340
381
0.47
(0.43)
0.04
0.28
0.32
1979
600
(484)
116
340
456
0.48
(0.38)
0.10
0.27
0.37
1980
648
(521)
127
340
467
0.50
(0.40)
0.10
0.26
0.36
*Usir.g Schedule :i ' s total gasoline as a divisor.
CD
0
3
3
n
2
0
0
1
V,
01
0
o
O
U!
CJ
00
-------
3.3 IMPACT ON THE CONSTRUCTION INDUSTRY
The Impact of Schedules 0 and N upon the construction industry was
studied by scaling the investments required in the individual refinery models
to a national level. The methods used to carry out this scaling and to make
adjustments for obsolescence and replacements are described in Section 5 of
report 0RGH-015.
Table '15 shows the investments being completed by the construction in-
dustry in each year of Schedules 0 and N. That is, the facilities represented
by these investments are operable for the first time in the year for which the
investment is recorded.
It should be noted that all investments shown in these tables other than
U.S. and Canadian refining are the same for all schedules. Also, U.S. refining
investments for the years 1970, 1971, and 1972 are constant for each schedule.
The refinery investments for these years were based upon data reported in the
Oil and Gas Journal and reported levels of engineering and construction backlog.
Schedule 0 did not require as much investment in these early years as
shown on Table 15, indicating that the industry should be' capable of meeting
this schedule in the early years without too much difficulty. The implied ex-
cess capacity was distributed over the years 1973, 1974, and 1975 in the same
ratio as the model year results for the same period.
Figures 3-1 and 3-2 plot these refinery investments together with the
forecasted maximum construction industry capacity available to refining.
Table 16 gives a breakdown of the construction dollar according to the
various sectors of the construction industry for ea'ch schedule. This breakdown
includes a distribution of the total investment dollars backward in time to
reflect the fact that engineering must start well ahead of materials ordering,
etc. For convenience in observing the effect of the various schedules so far as
producing boom or bust conditions is concerned, the lower half of these tables
describes the changes in construction activity from year to year.
RGH-015 Bonner & Moore Associates, Inc. 3-19
Addendum 1
-------
TflB'LE 15
CONSTRUCTION INDUSTRY INVESTMENTS
CLCD
Q-rc
n> i
3 O
Q.—<
C VI
SOtC-LI. 0
0
o
3
3
(B
o
o
o
71
I/I
0
O
OJ
I
ro
PLTKL-OEriCAu s»EriM\a TBTAL
F|
19/C
1971
1972
1973
197»
19/5
1976
1977
I97a
1979
l9a'C
19al
4 Q b. !5
19&2
TOTALS
JREIG*
iOO
110
120
135
150
165
135
205
c3C
250
c&O
310
j»b
2/'jS5
L'S/CANACA
1/2CC
1/333
I/ SCO
l*6Bc
1/8SQ
2*020
2*22'j
c/*4J
2/6SC
2/960
3/25U
3/5cQ
3/930
JC/68C
T3TAL
1/3CC
1/44U
1»620
1/315
2/03C
2/185
e/*Cb
2/645
2/920
J/210
3/530
3/89C
4/275
33/265
FfSRTIjS
ICE
125
1*C
isc
16C
17C
33C
185
19C
195
?cc
205
?1C
2/215
CAKAJA
115 •
127
70
110
117
128
132
137
139
1*1
1*2
144
1*6
1/649
US
1»C5C
1/158
635
I/ CO*
1/C6*
1/162
1*20»
1/2*5
1/262
1/27?
1/29*
1/311
1/327
l*,99T Ct.f'N.AL.'v _ fy«/vc.L
1 *¥&«*''•&
1970
1971
1972
1973
1974
1975
1976
1977
1976
1979
1980
1931
I9d2
TSTALS
fQKElS->
100
11C
120
135
15U
165
135
205
T3C
25C
e3C
31C
3*5
2/L-.B5
PETKGCrEMCAL
Ub/CANACA
1/2CO
1/330
I/ SCO
1/6«C
i/sec
2/020
2/22C
2/**0
2/69C
2*960
3/ 2 = C
3/5fcO
3/930
3C/6er,
REFIMN3
T?TAL
1*300
1/44C
1/62C
l/ais
2/030
2/185
2»*Cb
2/645
2/92C
J'2lC
3/&3C
3/390
•»/275
33/26=
FOREIGN
ICE
12=
1*C
ISC
16C
17C
18C
185
19C
1S5
2CC
2CE
?1C
2/?15
CANADA
115
1?7
70
11*
156
179
1*5
129
131
132
13*
136
137
1/7C5
L-S
1/050
1/15«
635
1/C36
1 • * 1 7
1/625
1/315
1*173
If 1«S
1/2C3
1*217
1/232
1*2*7
15,497
TOTAL
1/27S
1/*11
8*5
1/30C.
1/733
1/974
l/6*c
l/tB7
1/509
1/530
1/55}
1/572
1/59*
19/416
F9REIG.M
205
235
26o
285
31 S
335
365
390
"20
445
48Q
515
555
*/?or.
TOTAL
US/CA.VADA
2,365
2,616
2/205
2/830
3,*53
3,«24
3/63C
3/742
4/009
4/295
4/601
4,947
5,31*
47,881
TOTAL
5/570
2/851
2**65
3*115
3*763
4/ 1'59
4*0*5
4/132
*/*29
4/74C
5/Cfil
5/*62
5/369
P.p/681
-------
0 - U.S. Refinery Investment
62 - 70 Reported
71 - 72 Projected
73 - 80 Limited by Construction
n - Schedule 0
Annual
Investment
($ Billions)
7.0
6.0
5.0
4.0
3.0
2.0
1.0
62 64 66 68 70 72 74 76 78 80
Year
Figure 3-1. Refinery Investment Required by Schedule 0
RGH-015
Addendum 1
Doiirior At Moore Associates, Inc.
3-21
-------
0 - U.S. Refinery Investment
62 - 70 Reported
71 - 72 .Projected
73 - 80 Limited by Construction
Q - Schedule N
Annual
Investment
($ Billions)
7.0
6.0
5.0
4.0
3.0
2.0
1.0 ,
62 64 66 68 70 72 74 76 78 80
Figure 3-2. Refinery Investment Required by Schedule N
RGII-015
Addendum 1
!!- At Miiori- AssociiiU-s, Inc.
3-22
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TABLE 16
CONSTRUCTION COSTS BY SECTOR
. SOtCwLL N
IS f.
1S7J?
1S7J
197*.
197*
1S77
197E
3fcC
439
508
533
531
554
1*240
1*544
1*815
1*918
I*«fi9
1*956
2*093
2*24?
681
1980
TUTALj
(.MNul.
1971
2*585
19/688
197J
19V*
1977
l97c
1979
1930
Pt>CtM Br PK'IUH Yt".*«
16
5
-C
4
7
7
7
7
-2
»
7
7
7
7
FIELD UABBR
«78
• 5*6
672
76C
76?
765
865
9?7
996
7.579
• 8
1*
23
13
C
C
6
7
7
7
FEE.S 5
526
629
688
685
701
746
799
856
920
6*991
-5
19
20
9
•0
2
6
7
7
7
2*518
3*055
3*62*
3*898
3*868
3*975
4*5«1
4*87C
5*233
39*821
• 3
21
19
8
<•!
3
7
7
7
7
LS
SCHtCULE 0
1S7J?
197.1
1577
137*
358
414
525
6C3
6*5
052
7*3
1S7*
I97b
I97n
1977
1S7S-
1S8,.
HilALli
As Pt.KCE.NT llF
1
16
9
o
7
7
7
7
7
1*23*
1*466
1*6C2
1*729
1*994
2*629
lS/379
YEAR
•2
19
9
7
7
7
7
7
7
FIELD LABBH
478
54Q
613
665
716
769
824
882
944
1»C13
7*445
-S
13
13
»
8
7
7
7
7
7
FEES 5 wise
44C
s M
567
614
661
709
760
"13
871
935
-5
16
11
f
a
7
7
7
7
7
2*bo9
2*931
3*235
3*496
3*76C
4*036
4*321
4*956
5*321
39*138
-3
17
1C
8
8
7
7
7
7
7
RGH-015
Addendum 1
Boiincr & Moore Associates, Inc.
3-23
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3.4 IMPACT OF SCHEDULES 0 AND N UPON REACTIVE EMISSIONS
Figure 3-3 shows the estimated lead usage and aromatics burned in pre-
.1975 cars for years 1972 through 1980 on Schedules N and 0. Schedule N has a
lower lead usage than Schedule 0 and consequently has a higher aromatic usage in
pre-1975 cars.
RGH-015 Bonner & Moore Associates, Inc. 3-24
Addendum 1
-------
Lead Aromatics
(Thousands Millions
of Tons) of Barrels)
150 -
100 -
50 -
0 J
450
300
150
O
200
150 -
100 -
50 -
300
150
0 J 0
SCHEDULE N
72 73 74 75 76 77 78 79 80
O Lead (103 Tons)
D Aromatics (10s Bbls) Burned in Pre-1975 cars
SCHEDULE 0
73 74 75 76 77 78 79 80
72
Figure 3-3. Lead and Aromatics Levels for Schedules N and 0
RGH-015
Addendum 1
Bonner & Moore Associates, Inc.
3-25
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