United States
Environmental Protection
Agency
Office of Water
Regulations and Standards
Washington DC 20460
EPA-440/2-82-007
November 1982
Water
Economic Impact Analysis
of Effluent Limitations and
Standards for the
Petroleum Refining Industry
QUANTITY
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This document is available from the National Technical Information Service,
5282 Port Royal Road, Springfield, Virginia 22161.
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ECONOMIC IMPACT ANALYSIS OF
EFFLUENT LIMITATIONS AND
STANDARDS FOR THE
PETROLEUM REFINING INDUSTRY
PREPARED FOR
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF WATER REGULATIONS AND STANDARDS,
OFFICE OF ANALYSIS AND EVALUATION
C\'i~- .--'oO, iili.i
NOVEMBER 1982
X
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Fnvfrc:
sgeney
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This document is an economic impact assessment of the recently-issued
effluent guidelines. The report should be directed to the staff respon-
sible for writing industrial discharge permits. The report includes
detailed information on the costs and economic impacts of various treatment
technologies. It is should be helpful to the permit writer in evaluating
the economic impacts on an industrial facility that must comply with BAT
limitations or water quality standards.
If you have any questions about this report, or if you would like additional
information on the economic impact of the regulation, please contact the
Economic Analysis Staff in the Office of Water Regulations and Standards
at EPA Headquarters:
401 M Street, S.W. (WH-586)
Washington, D.C. 20460
(202) 382-5397
The staff economist for this project is John Kukulka (202/382-5388).
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PREFACE
This document is a contractor's study prepared for the Office of Water Regula-
tions and Standards of the Environmental Protection Agency (EPA). The purpose
of the study is to analyze the economic impact which could result from the
application of effluent standards and limitations issued under Sections 301,
304, 306 and 307 of the Clean Water Act to the petroleum refining industry.
The study supplements the technical study (EPA Development Document) supporting
the issuance of these regulations. The Development Document surveys existing
and potential waste treatment control methods and technology within particular
industrial source categories and supports certain standards and limitations
based upon an analysis of the feasibility of these standards in accordance with
the requirements of the Clean Water Act. Presented in the Development Document
are the investment and operating costs associated with various control and treat-
ment technologies. The attached document supplements this analysis by estimat-
ing the broader economic effects which might result from the application of
various control methods and technologies. This study investigates the effect
in terms of product price increases, effects upon employment and the continued
viability of affected plants, effects upon foreign trade and other competitive
effects.
The study has been prepared with the supervision and review of the Office of
Water Regulations and Standards of EPA. This report was submitted in fulfillment
of Contract No. 68-01-6341 by Sobotka & Company, Inc. The work on this analysis
was completed August 1982.
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TABLE OF CONTENTS
Chapter I
Chapter II
Chapter III
Chapter IV
Chapter V
Chapter VI
Chapter VII
EXECUTIVE SUMMARY
A. Introduction
B. Structure of the Industry
C. Methodology
D. Costs of Conforming to Revised Guidelines
and New Source Standards
E. Impact Analysis
F. Limitations of the Analysis
STRUCTURE OF THE PETROLEUM REFINING INDUSTRY
A. Principal Statistics of the Industry
B. Coverage of the Analysis
C. Economic and Financial Structure of the Industry
METHODOLOGY
A. Price Analysis
B. Quantity Analysis
COSTS OF CONFORMING PETROLEUM REFINERIES TO
REVISED BATEA GUIDELINES, NEW SOURCE PERFORMANCE
STANDARDS, PRETREATMENT GUIDELINES, AND PRETREATMENT
STANDARDS FOR NEW SOURCES
A. Existing Sources
B. New Sources
ECONOMIC IMPACT ANALYSIS WITH HIGH LEVEL OF
PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS
A. Price Effects of Revised Guidelines
B. Financial Effects
C. Production Effects
D. Employment Effects
E. Community and Balance of Trade Effects
ECONOMIC IMPACT ANALYSIS WITH LOW LEVEL OF
PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS
A. Price Effects
B. Financial Effects
C. Production Effects
D. Summary of Economic Impacts of Revised
Guidelines on Existing Plants
E. Impacts on New Plants
LIMITATIONS OF THE ANALYSIS
1-1
1-1
1-3
1-3
1-6
1-8
II-1
II-3
II-3
III-l
III-2
IV-1
IV-4
V-l
V-2
V-3
V-4
V-4
VI-1
VI-1
VI-2
VI-18
VI-19
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TABLE OF CONTENTS (continued)
Appendix A PETROLEUM REFINING PROCESSES AND THE REFINING INDUSTRY
A. Types of Refineries A-l
B. Location of Refineries A-8
C. Financial Structure of the Industry A-10
D. Refining Industry Growth A-ll
E. Types of Refining Processes A-13
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LIST OF EXHIBITS
Page
Exhibit I.I SUMMARY OF COSTS TO PETROLEUM REFINERIES
OF CONFORMING TO REVISED EFFLUENT DISCHARGE STANDARDS 1-4
Exhibit 1.2 COSTS TO A NEW PETROLEUM REFINERY OF CONFORMING TO
REVISED EFFLUENT DISCHARGE STANDARDS 1-5
Exhibit II.1 SUMMARY OF RESPONSES TO 1976 PETROLEUM REFINING
INDUSTRY SECTION 308 QUESTIONNAIRE II-4
Exhibit II.2 THE EFFECT OF PRODUCT IMPORT TARIFFS ON CONSUMPTION,
DOMESTIC MANUFACTURE AND IMPORTS OF PETROLEUM PRODUCTS 11-13
Exhibit IV.1 COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES IV-6
Exhibit IV.2 COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES IV-16
Exhibit IV.3 SUMMARY OF COSTS TO PETROLEUM REFINERIES OF
CONFORMING TO REVISED EFFLUENT DISCHARGE GUIDELINES IV-19
Exhibit IV.4 COSTS TO A NEW PETROLEUM REFINERY OF CONFORMING TO
REVISED EFFLUENT DISCHARGE GUIDELINES IV-20
Exhibit VI.1 EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
TO REVISED GUIDELINES OF MORE THAN 4.1
CENTS PER BARREL OF CRUDE OIL PROCESSED VI-4
Exhibit VI.2 COMPARISON OF PROCESS UNIT VALUES
VERSUS COST TO CONFORM TO REVISED GUIDELINES VI-11
Exhibit A.I FLOW DIAGRAM FOR TOPPING REFINERY PROCESSING
LOW SULFUR CRUDE OIL A-2
Exhibit A.2 FLOW DIAGRAM FOR HYDROSKIMMING REFINERY
PROCESSING LOW SULFUR CRUDE OIL A-3
Exhibit A.3 FLOW DIAGRAM FOR FUELS REFINERY PROCESSING
LOW SULFUR CRUDE OIL A-4
Exhibit A.4 FLOW DIAGRAM FOR HIGH CONVERSION REFINERY PROCESSING
LOW SULFUR CRUDE OIL A-5
Exhibit A.5 U.S. REFINERY CRUDE DISTILLATION CAPACITY
AND OPERATIONAL ABILITY MATRIX A-7
Exhibit A.6 GEOGRAPHIC DISTRIBUTION OF REFINERIES
AND REFINERY CAPACITY A-9
Exhibit A.7 FUNCTIONAL CHARACTERIZATION OF PETROLEUM
REFINERY PROCESSES A-14
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Chapter I
EXECUTIVE SUMMARY
A. Introduction
The Environmental Protection Agency (EPA) is in the process of developing
and issuing revised "best available technology economically achievable" (BATEA)
limitations and "pretreatment" standards for aqueous effluents discharged by
existing petroleum refineries. It is also issuing revised new source standards
for future refineries. The standards and limitations will be issued in accor-
dance with Sections 301, 304, 306 and 307 of the Clean Water Act. The purpose
of this study was to analyze the economic impacts that could result from the
implementation of revised limitations and standards.
This study was restricted to 212 U.S. refineries that operated in 1976 and
were expected to discharge aqueous effluents in 1984 into receiving bodies or
publicly/jointly owned treatment plants. (Fifty refineries will discharge no
effluents; twenty-one, including eight known dischargers, did not respond to
EPA's Section 308 Survey Questionnaire and were not included in the analysis.)
Most of the data underlying the analyses in this report were taken from a
development document and a cost manual prepared by EPA. These publications
include information on the size and process unit configuration of each dis-
charging refinery and on the estimated capital and operating costs that may be
required to bring each refinery into conformance with revised guidelines.
B. Structure of the Industry
The petroleum refining industry had been subject to a set of raw material
and refined product price controls that severely distorted competition. This
study assumed that these controls would have lapsed by 1984 when the revised
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1-2
guidelines will become effective. In fact, these controls were terminated by
presidential decree on January 28, 1981.
In the absence of price controls, the market for refined petroleum pro-
ducts is competitive between domestic and foreign plants. Product prices are
determined by the marginal costs of the highest cost supply needed to clear
the market. For several reasons, e.g., preferentially-priced raw materials
and/or fuel, advantageous tax treatment, less severe environmental controls,
less severe occupational safety and health requirements, etc., many foreign
refineries face lower costs than do U.S. plants. So the maintenance of a
domestic refinery industry of roughly the same size that existed in 1978
would have required that some protection be afforded against unrestricted
competition from imported products.
For the purpose of economic analysis, it is useful to segregate the in-
dustry on the basis of four characteristics:
B.I Disposition of Aqueous Effluent. Refineries discharge either direct-
ly or indirectly to publicly or jointly owned treatment plants, or not at all.
B.2 New or Existing Source of Effluent.
B.3 Refinery Configuration. Configuration is a good proxy for value added
by refineries. The more highly configured a refinery is, the greater will be
the value added per unit of crude oil processed.
B.A Geographical Location. Because transportation is an important compo-
nent of delivered product cost, the location of a refinery relative to its crude
oil supply and its product markets, and to its competition, has a significant
impact on its value.
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1-3
C. Methodology
The price analysis, described below, was simple. For the quantity analy-
sis, the cost estimates were restated as annualized costs per unit volume of
crude oil processed. Twenty-seven refineries were found to be facing costs to
conform to revised guidelines which exceeded 4.1 cents per (42 gallon) barrel
of crude oil processed. For each of these the cost to conform was compared to
the value of the refinery. Value was defined from an investors' viewpoint:
the present value of future cash flows. Value estimates were derived for each
of two premised future levels of federal protection against petroleum product
imports: a level high enough to encourage construction of new capacity, and a
lower level adequate to preserve the industry at about its current capacity.
For each level of protection, value estimates were developed from factual
information about refinery process unit costs, historic product manufacturing
margins, and transportation costs for raw materials and refined products.
D. Costs of Conforming to Revised Guidelines and New Source Standards
Costs of conforming existing refineries to revised guidelines (BAT and
PSES) will apparently range from zero to 42 cents per barrel of crude oil
processed, i.e., from zero to about 1.1 cents per gallon of refined product
manufactured. Costs of conforming new source refinery capacity to revised new
source standards (NSPS and PSNS) will apparently range from zero to 6.2 cents
per barrel crude oil processed, i.e., from zero to about 0.2 cents per gallon
of refined product manufactured.
The cost data are summarized in Exhibits I.I and 1.2.
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Exhibit I.I
SUMMARY OF COSTS TO PETROLEUM REFINERIES
OF CONFORMING TO REVISED EFFLUENT DISCHARGE STANDARDS
DIRECT DISCHARGERS
BAT-
Level 1
Level 2
Crude Oil
Distillation
Capacity
(1000 bpd)
14,142
14,142
Capital Operating Annualized
Costs Costs Costs
Total Unit
(1000 $) (1000 $/year) (1000 $/year) (cents/barrel)
19,281
112,956
3,678
24,985
7,730
48,703
0.2
1.0
INDIRECT DISCHARGERS
PSES-
Option 1 2,402 9,591
Option 2 2,402 84,807
According to the Development Document:
3,163
14,432
5,175
35,267
0.7
4.1
BAT-Level 1 is current BPT quality plus reduction in effluent flow to 73% of
"model" flow,
BAT-Level 2 is the same flow reduction plus addition of powdered activated
carbon to the biological treater,
PSES-Option 1 is current PSES quality plus removal of chromium from cooling
tower blowdown, and
PSES-Option 2 is flow reduction, equalization, biological treatment, and
filtration of total effluent.
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1-5
Exhibit 1.2
COSTS TO A NEW PETROLEUM REFINERY*
OF CONFORMING TO REVISED EFFLUENT DISCHARGE STANDARDS
DIRECT DISCHARGER (NSPS)S
Level 1
Level 2
NO AQUEOUS DISCHARGE5
Capital
Costs
(1000 $)
0
75
INDIRECT DISCHARGER (PSNS)t
Option 1 260
Option 2 5,800
Operating
Costs
(1000 $/year)
0
218
9,500
140
2,230
1,880
Annual!zed
Costs
Total Unit
(1000 $/year) (cents/barrel)
0
234
195
3,450
3,875
0
0.4
0.3
5.5
6.2
200,000 barrels per stream day capacity, equipped for high conversion.
5 Costs are additional above current NSPS (BADT).
t Costs are additional above current pretreatment standards for existing refineries.
According to the Development Document:
NSPS-Level 1 corresponds to current NSPS (BADT) regulations,
NSPS-Level 2 adds powdered activated carbon to the Level 1 biological treater,
PSNS-Option 1 is current PSES quality plus removal of chromium from cooling tower
blowdown, and
PSNS-Option 2 is flow reduction, equalization, biological treatment and filtration
of total effluent.
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E. Impact Analysis
E.I Price Impacts. It was discussed above that market-clearing prices
of petroleum products are determined by either the long-run costs of products
manufactured domestically or the short-run cost of imports plus tariff.
Under a high level of federal protection against imports, the revised new
source standards would increase product prices by zero to 0.15 cents per gal-
lon. Under a low level of protection, prices will be determined by the costs
of imports (including tariff costs). So revised guidelines would have no
price impact.
E.2 Financial Impacts. With a high level of federal protection, the fi-
nancial effect for existing refineries of revised new source standards and
revised guidelines vrould range from a net cost of 81 million dollars per year
to a net benefit of 327 million dollars per year. The range exists because
there are five possible new source standards that might be price-determining,
and four combinations of revised direct/indirect guidelines that may be imposed.
Under a low level of federal protection, and depending on which combination
of revised direct/indirect guidelines was imposed, the costs to be absorbed by
existing refineries would range from 13 million to 81 million dollars per year.
The larger number represents an average cost increase for the industry of
about 0.1 percent, or roughly one percent of value added by refining.
At the time of this study, petroleum refineries faced major business
uncertainties. The size of the "small refiner bias" in the crude oil entitle-
ments program was under review; price controls on most products had been
allowed to lapse, and further decontrol was under study; crude oil prices were
being increased to world levels by price decontrol; the long range level of
protection against imports to be afforded U.S. refineries was unknown, etc.
Compared to the financial implications of these uncertainties, the estimates
of the costs of conforming to revised guidelines were inconsequential.
E.3 Production Impacts. Twenty-seven existing refineries were estimated
to face conformance costs exceeding 0.1 cents per gallon of product manufactured.
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1-7
Under a high level of federal protection all of these were expected to be
willing to undertake effluent treating revisions and to continue operating.
Under a low level of federal protection, three refineries were identified as
apparently not worth the cost of conforming to revised Option 2 pretreatment
standards for existing sources (PSES) guidelines. These refineries accounted
for only 0.1 percent of industry capacity, so the loss would have no effect on
overall industry outturn.
E.4 Employment Impacts. Under a high level of federal protection, re-
vised standards and guidelines would lead to the following increases in industry
employment:
New Jobs
Existing Direct Dischargers
Level 1 40
Level 2 600
Existing Indirect Dischargers
Option 1 10
Option 2 250
New employment could range from 50 to 750 jobs, depending on the combination
of Level/Option chosen for implementation.
Under a low level of protection, total industry employment would increase
by about 50 people if Level 1 and Option 1 are implemented. If Level 2 and
Option 2 are implemented instead, employment in surviving refineries would
increase by about 850 jobs; but 100 to 150 jobs would be lost at the three
refineries which shut down.
E.5 Community Effects. The three refineries that may shut down are all
small employers located in or near metropolitan areas. Hence, no com-
munity impacts are expected if the plants shut down.
E.6 Balance of Trade Effects. There apparently will be no balance of
trade effects of revised guidelines.
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1-8
F. Limitations of the Analysis
The analysis is based entirely on costs developed by the Effluent Guide-
lines Division of EPA. The costs are based on a statistical analysis of 1976
effluent flow data. Also, land costs were assumed to be negligible for all
refineries.
Existing federal policy currently does not substantially protect domestic
refineries against low priced imports of petroleum products. The lowest level
of protection assumed in this study was a level that would maintain domestic
refining industry throughput at roughly its 1978 level. But in 1978, there
was no clear indication of what the refinery protection policy would eventually
be, if any, or when it might become effective.
At the time this study was made, it was not possible to foresee the dramatic
changes that eventually took place in the world and the U.S. petroleum market
places. Large price increases significantly reduced consumption. In January
1981, all U.S. petroleum price controls were removed, small refiner subsidies
were rescinded and the U.S. industry was given essentially no tariff protection.
U.S refining utilization decreased from 89.4 percent of capacity in 1977 to
below 70 percent in 1981. More than fifty U.S. refineries have discontinued
operations since decontrol.
If the economic impact analysis were redone in the context of the current
economic environment, some changes would be noted. But the impacts on the
existing industry (BAT and PSES) would be small since compliance costs repre-
sent such a small fraction of value added. There would be essentially no con-
struction of new refining sources. Market prices for petroleum products would
be determined by the costs of imports, so there would be no price effects
of revised guidelines applicable to U.S. plants. Therefore, BAT and PSES com-
pliance costs would have to be absorbed by existing refineries.
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1-9
Even though current forecasts indicate that little construction of new
refining sources will take place, it can be concluded that the NSPS or PSNS
standards considered in this analysis would have negligible impact on the
economic viability of new plants. A new refinery of the type noted in Exhibit
1.2 would have to generate a net cash flow before taxes (product revenues minus
the sum of raw material costs plus cash operating expenses) of roughly $150
million dollars per year to be commercially feasible. In this context, the
annual costs of even the more severe treatment options considered for new
sources - PSNS Option 2 or zero discharge - represent roughly two percent of
the cash flow. Relative costs of this magnitude are too small to influence
overall project economics.
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Chapter II
STRUCTURE OF THE PETROLEUM REFINING INDUSTRY
(NOTE: The material contained in this chapter is updated in Appendix A.)
A. Principal Statistics of the Industry
As of January 1, 1978, the petroleum refining industry in the United States
and its possessions consisted of about 280 plants, owned by about 150 firms,
and located in 41 of the 50 states, Guam, Puerto Rico, and the Virgin Islands.1
Industry capacity for processing crude oil was about 17 million barrels (715
million gallons) per calendar day.^ The refineries had a replacement value
in excess of 40 billion dollars. The industry employed about 160,000 persons
in 1977.3
The bulk of refining is done by firms which also market refined products
or produce crude oil, or do both. In most firms the refining portion of the
business is not the major activity. Refinery investment is less than 15 per-
cent of total investment in the domestic oil industry.4
U.S. refineries vary in capacity by over three orders of magnitude - from
500 to 730,000 barrels crude oil per day.5 The degree of refinery complexity
(measured by total refinery replacement value per barrel of crude oil distilla-
tion capacity) varies between refineries by a factor of fifteen.6 Consequently,
1 U.S. Department of Energy, Petroleum Refineries in the United States
and Puerto Rico, January ±, 1978, July 1978.
2 Ibid.
3 American Petroleum Institute, Basic Petroleum Data Book, Petroleum
Industry Statistics, October 1975 and later years.
4 Ibid.
5 U.S. Department of Energy, op. cit.
6 Sobotka & Co., Inc., Capital and Operating Costs for Grass Roots Petroleum
Refineries with Several Different Process Unit Configurations, Department of
Energy Contract EJ-78-C-01-2834, April 12, 1979.
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the replacement value of refineries ranges from roughly one million dollars to
perhaps two billion dollars.
The delivered price of crude oil to U.S. refineries in December 1978
varied from about six dollars per barrel for domestic "lower tier" crude oil
to about sixteen dollars per barrel for imported low-sulfur crude oil.* The
weighted average composite price was thirteen dollars per barrel (thirty-one
cents per gallon). It was anticipated that imports would account for about
forty-three percent of crude oil intake by U.S. refineries in 1979 and about
ten percent of product consumption.2
Average wholesale prices for refined petroleum fuel products in December
1978 were:3
Motor gasoline 42 cents per gallon
Kerosene 39.5
Distillate fuel oil 38
Residual fuel oil 25
Average product yields from U.S. refineries during 1977 were:^
Percent of Crude
Oil Processed
Gasoline 43.4
Jet fuel and kerosene 7.8
Distillate fuel oil 22.4
Residual fuel oil 12.0
Petrochemical feedstocks 3.6
Liquefied gases 2.4
Asphalt 3.0
Lubricants 1.2
All other 4.2
100.0
1 Chase Manhattan Bank, The Petroleum Situation - February 1979.
2 Oil and Gas Journal, May 14, 1979, p. 86.
3 Chase Manhattan Bank, op.
* Department of Energy, Crude Petroleum, Petroleum Products , and Natural
Gas Liquids; 1977, DOE/EIA - 0108/77, December 8, 1978.
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II-3
Not all domestic gasoline was manufactured from crude oil. Roughly ten percent
was supplied predominantly by natural gas liquids.* Also, natural gas proces-
sing plants supplied much more liquefied gases than did refineries.
B. Coverage of the Analysis
The refineries for which revised BAT guidelines or revised pretreatment
guidelines costs were derived are those which answered a survey questionnaire
issued under authority of Section 308 of Public Law 92-217. A total of 299
questionnaires were issued; responses are summarized in Exhibit II.1.
C. Economic and Financial Structure of the Industry
Revised effluent guidelines require compliance by July 1, 198A. Conse-
quently, the economic structure of the industry in 1978 or 1979 is not neces-
sarily relevent to the impact analysis. Rather, the structure in 1984 as it
would be without revised guidelines is the appropriate base for analysis. The
1984 structure was estimated to be the result of five years of endogenous and
exogenous influences on the 1978-79 structure of the industry.
The financial status of the industry in 1978 is not a good base from
which to forecast the 1984 status because then-current conditions will not
exist in 1984. At the time that this analysis was performed, the industry was
subject to price controls and allocation rules for both raw materials and
refined products. Product price controls had been in effect since 1971, and
crude oil price controls and allocations rules since 1973-74. The controls
worked in two directions. On the one hand, the costs of raw materials to U.S.
refineries were lower than the costs faced by essentially all of the rest of
the free world non-OPEC refiners. On the other hand, product prices in the
United States were controlled at levels lower than in most of the rest of the
1 Ibid.
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II-4
Exhibit II.1
SUMMARY OF RESPONSES TO
1976 PETROLEUM REFINING INDUSTRY SECTION 308 QUESTIONNAIRE
Forecast 1984 Waste Number of Reported 1976 Crude Oil
Water Discharge Mode Refineries Processing Capacity
(1000 bpd)
No waste water discharge 50 846.3
Direct discharge to
receiving body 165 14,141.8
Indirect discharge to
publicly or jointly
owned treatment plants 47 2,401.5
Facility not refinery 12
Refinery did not operate
in 1976 4
No response 21* 219.0s
299* 17,389.6
* Includes nine with known discharge modes - 6 indirect, 1 direct, 1 both
direct and indirect, 1 zero.
§ Estimated.
t Includes all refineries reported by the Bureau of Mines as existing in 1976.
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world. The balance of this chapter is devoted to developing a reasonable
estimate of the structure of the industry in 1984.
C.I Exogenous Economic Factors. The legislation which established crude
oil and product price controls and allocations was scheduled to lapse before
1984. Crude oil price controls were lifted in 1981. The prices of several
major product classes, notably distillate fuel oil, had already been decon-
trolled in 1979. Motor gasoline was the only significant product still con-
trolled in 1979. Based on the foregoing, it was assumed that the markets for
crude oil and for refined petroleum products in 1984 will not be subject to
price controls.
The quality of some refined products was forecast to change between 1979
and 1984. The predominant change was expected in gasoline. By 1984, at least
three-fourths of motor gasoline will not contain any lead anti-knock additive,
whereas in 1978, about one-third of gasoline was unleaded.1 In addition, the
average sulfur content of fuel oils was expected to decrease steadily in res-
ponse to State Implementation Plans for sulfur dioxide emissions from existing
facilities and new source performance standards for new facilities. At the
same time, the average sulfur content of crude oils available to U.S. refiner-
ies was expected to increase. Both Alaskan North Slope and Mexican Reforma
crude oils are higher than average in sulfur, as are most Middle Eastern crude
oils. The effect of these quality trends is to increase the cost of manufac-
turing refined petroleum products.
The structure of U.S. domestic demand was also expected to change from
1979 to 1984.2 it had been widely forecast that, because of federally mandated
efficiency rules, domestic gasoline consumption would reach a peak around 1980
and stay at that level for four to five years before resuming growth. Con-
versely, the consumption of distillate fuel oil was forecast to increase slowly
1 Hydrocarbon Processing, April 1979, p. 13.
2 Projections £f Energy Supply and Demand and Their Impacts, Annual Report
to Congress, 1977, Volume II, Energy Information Administration, April 1978,
p. 115.
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11-6
rather than to follow the pattern of gasoline. It was thought that domestic
manufacture of residual fuel oil might grow even if consumption were to stag-
nate, since a large fraction of supply was imported, and could therefore be cut
back in favor of domestic production. In reality, the large petroleum price
increases which took place in 1979/1980 caused consumption of all products to
fall much faster than was premised for this analysis.
It was assumed that as current natural gas price controls and allocations
lapsed, energy consumed by refineries (except purchased electricity) would
come to cost about the same per BTU, regardless of its form. This was not yet
the case in 1979, because some refineries had a cost advantage by being able to
use as plant fuel natural gas which was contracted several years earlier at
low prices, or was priced controlled.
Outside the U.S., it was forecast that OPEC would continue as an effective
cartel, maintaining crude oil prices at the 1979 real price or higher.
Additionally, because all OECD countries were reducing the allowable sulfur
content of fuel oils,l and low-sulfur crude oil reserves accounted for only
about one-fifth of total free world reserves,2 low-sulfur crude oils were
commanding premiums more than justified by the costs of desulfurization.
Consequently, substantial construction of fuel oil desulfurization facilities
was expected.* It was reasonable to assume that the price difference between
high-sulfur and low-sulfur crude oils would eventually reach an equilibrium
which would reflect the long run full cost of desulfurization. That is, the
difference between high-sulfur and low-sulfur crude oil prices would be such
that a refinery owner would be indifferent between two options: purchasing
high-priced low-sulfur crude oil, or purchasing low-priced high-sulfur crude
oil and installing desulfurization equipment.
1 Oil and Gas Journal, November 28, 1977, page 56.
2 International Petroleum Encyclopedia, 1975, page 296.
3 In the years between 1978 and 1982, demand for low sulfur residual
fuel oils declined substantially, so there was a reduced need to construct
desulfurization facilities. But an increasing need developed to install
conversion facilities to convert both high and low sulfur residual materials
into lighter products.
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There existed in 1978, and still exists today, a large worldwide excess
of crude oil distillation capacity.1 This surplus capacity means that high-
sulfur fuel oils will be available indefinitely on the world market at prices
averaging less than ten percent above the acquisition cost of crude oil.
C.2 Price Determination. The petroleum refining industry had been sub-
ject to product price controls between 1971 and 1981. Before that time the
domestic market for wholesale oil products was competitive in the economic
meaning of the term.2 That is, the price elasticity of demand facing indi-
vidual firms was high.
Despite a strong and continuing industry effort to establish brand dif-
ferentiation for retail consumers, the wholesale petroleum product market
operates on a commodity basis. Perhaps one-third of gasoline,-* about half of
intermediates and almost all of residuals are sold as commodities. With such
large volumes sold as commodities by many refiners, an active brokerage busi-
ness exists. Nonbrand marketers maintain aggressive purchasing staffs and oil
companies compete vigorously in the various governmental, institutional and
commercial "bid" markets.
Before price controls, prices on the various wholesale markets typically
were close to, and varied with, short-run marginal costs.^ This indicated
that the industry was highly competitive and that refinery gate (wholesale)
product prices were based on short-run marginal costs. Because of this,
1 Oil and Gas Journal, June 12, 1978, page 40.
2 Executive Office of The President, Energy Policy and Planning, The
National Energy Plan, April 2, 1977, p. 59; and Federal Trade Commission, Staff
Report on Effect of Federal Price and Allocation Regulations on the Petroleum
Industry, December 1976, p. 1.
3 So-called "unbranded" sales at retail by independent oil companies, com-
mercial sales directly to users and sales to government combine to roughly
over 30 percent of total gasoline sales.
* Stephen Sobotka & Company, The Impact £f_ Costs Associated With New
Environmental Standards upon the Petroleum Refining Industry, Council on
Environmental Quality unnumbered contract, November 23, 1971, p. 37.
-------
II-8
wholesale product prices changed essentially instantly when short-run marginal
costs changed. For example, crude oil price changes were immediately reflected
in product prices.1
Short-run marginal costs, of course, vary with capacity utilization. As
the demand for products increases, more and more of total industry capacity
must be brought into use to clear the market. Naturally, the highest cost,
least efficient, capacity is the last to be brought into operation. So in-
creased capacity utilization also means higher marginal costs. At some point
in the expansion of production, short-run marginal costs become equal to long-
run marginal costs. Long-run marginal costs are the total costs of financing,
building and operating new manufacturing capacity. Long-run marginal costs
include raw material costs, cash operating costs (labor, purchased power and
fuel, chemicals, materials, etc.) and the capital-related costs of owning the
new facilities (ad valorem and income taxes, insurance, return of capital, and
return on capital).
To restate, in the absence of price controls, wholesale product prices for
petroleum products have been priced close to short-run marginal refining costs.
Consequently, product prices increase as more and more of industry capacity
is utilized to meet product demand. At some point, product prices are suffi-
ciently high that investment in new refining capacity becomes attractive, that
is, a desirable rate-of-return can be foreseen from an investment in additional
refining capacity.
It is at this stage of the capacity growth cycle that increased fixed
costs become a permanent part of the price structure, since the new capacity
necessarily incurs all total-cost changes. For example, increases in property
taxes have no impact on short-run marginal costs but must be fully reflected
in product prices before new refinery capacity will become an attractive invest-
ment.
1 Short-run marginal costs always include raw materials, purchased power
and fuel, and chemicals. In some cases, labor and maintenance costs will also
vary with output.
-------
II-9
The above reasoning applies to effluent water treating costs faced by new
refinery capacity, and also to other environmental expenditures. The costs
are essentially fixed once the facilities are in place. So the costs enter
long-run, but not short-run, marginal costs.
U.S. petroleum refineries face competition not only from each other but
also from foreign refineries. As was stated above, there was substantial
unutilized crude oil distillation capacity in the world in 1978.* Despite
this spare capacity, large new refineries were under construction or planned
in several Middle East petroleum exporting countries.^ From a world point-of
-view these refineries were economically unjustified. They apparently were
being constructed for strategic reasons^ and to provide employment for nation-
als. Regardless of cause, the effect of this construction has perpetuated a
low utilization rate for world refineries, particularly those in Europe.
In 1978, it was less expensive to manufacture products in U.S. refineries
than in most foreign plants because of domestic crude oil price controls.
However, this crude oil price advantage was to be phased out and U.S. crude
oil was to be priced at world prices. Therefore, by 1984 all refineries in
the world were considered to have approximately identical crude oil acquisition
costs.
Note that refineries controlled by petroleum exporting countries do not
necessarily face the same crude oil acquisition costs as other refineries.
For competitive, political or strategic reasons, an exporting country can
choose to offer crude oil to its own refineries at a lower price than to anyone
else. Given time and a lack of tariff protection, a substantial portion of
world refining capacity could be acquired by crude oil exporting countries
through use of preferential crude oil pricing.
1 Oil and Gas Journal, June 12, 1978, p. 40.
2 Ibid.
3 Crude oil exporting countries that own refineries have more pricing
freedom than do countries that do not, since prices for crude oil sales (but not
refined products) are fixed by OPEC.
-------
11-10
The National Energy Plan implied, but did not specifically state, that
maintenance of a viable U.S. petroleum refining industry was a part of the
plan. For example, the strategic petroleum reserve program was planned to
acquire only crude oil, and crude oil is useless without refineries. Moreover,
the Deputy Secretary of the Department of Energy told a Senate Subcommittee
that refining capacity on the East Coast "must be increased."* These observa-
tions established that it was reasonable to assume that a viable refining indus-
try would be maintained in the United States.
In 1979, it seemed that the industry might have required protection against
low-priced imports from oil exporting companies in order to remain viable.
Protection could have taken many forms: domestic crude oil price controls,
quotas on imported finished products, and tariffs on imported finished pro-
ducts. Each of these methods could have been used to achieve a desired size
for the domestic industry. However, the balance of this report was written as
if tariffs would be the method utilized to protect the domestic industry. This
is because product tariffs are the most straightforward and easiest to under-
stand protection method. However, other alternatives are available and might,
in practice, be utilized.2
Of the possible levels of tariff that could be imposed, four are of par-
ticular interest:
C.2.a No tariff. In this case, industry capacity would gradually
decline if OPEC nations engage in competitive practices. But there is a minimum
level of capacity that would be maintained. That level is the capacity required
to process crude oil produced in the U.S.3 If U.S. refining capacity were to
fall below that level, some domestic crude oil would have to be exported for
refining, which would result in lower wellhead value. Consequently, in the
1 Oil Daily, June 22, 1978.
2 In practice, an import quota is likely to be most effective in protec-
tion is desired against excessive product imports from petroleum importing
countries.
3 The most economic location for refining Alaskan North Slope oil is Japan.
However, legislation requires this oil to be domestically refined.
-------
11-11
absence of tariff protection, U.S. crude oil prices would adjust to protect
enough domestic refining capacity to process all domestic production.
C.2.b A tariff designed to maintain industry capacity at approxi-
mately the current level. Such a tariff would lead to attrition of the least
efficient refineries that currently exist in the U.S., offset by "debottleneck-
ing" expansion of efficient, existing refineries. The average differential
between product prices and crude oil acquisition costs resulting from the
tariff would probably be greater than the average differential experienced in
1978. This observation was based on an FTC analysis 1 which concluded that
most refinery capacity expansion begun in the U.S. since 1975 was associated
with the small refiner bias in the crude oil entitlement system. In other
words, almost no expansion took place in refineries that faced average U.S.
price differentials.
C.2.c A tariff designed to encourage construction of enough new
domestic refinery capacity to equal the future growth in domestic product
consumption. This tariff would have to be high enough that the difference
between tariff-paid imported product prices and (tariff-paid) imported crude
oil prices would be adequate to justify construction of new domestic capacity.
C.2.d A tariff designed to provide for growth and also to phase out
the currently substantial quantity of residual fuel oil imports. To achieve a
more rapid growth of output of residual fuel oil than other products, the
tariff on residual fuel oil imports would need to be higher than in the preceding
case.
Of the four tariff levels just discussed, the second (hold constant capac-
ity) and the third (encourage refining capacity growth equal to product consump-
tion growth) were of interest. The no tariff case seemed to be inconsistent
with U.S. policy, although it was the case actually implemented. The highest
tariff case (phase out residual imports) would lead to substantial windfall
Federal Trade Commission, op. cit.
-------
11-12
profits for existing refineries and did not seem to be necessary for strategic
reasons.* Consequently, the economic impact analysis performed in this study
included tariff level as a parameter to be evaluated at two levels. The
effects of differing tariff levels are depicted in Exhibit II.2.
C.3 Industry Segmentation. The proper basis upon which to segment the
petroleum refining industry for an economic impact analysis of effluent guide-
lines is the individual refinery, including its raw material acquisition and
wholesale product shipping activities. There were several reasons for this
conclusion:
C.3.a Revised effluent guidelines will be established for each
individual refinery,, not for refining companies, or for subdivisions of re-
fineries.
C.3.b There is an active market for all domestic crude oil which
guarantees that every barrel produced will be purchased at the same delivered
price that the purchaser pays for other domestic crude oils of the same quality
at that location. Consequently, a decision to close down a refinery will disad-
vantage the crude oil suppliers of that refinery only by the amount of addition-
al transportation expense they may have to incur to deliver the material to a
different location. Note that if the location disadvantage is severe, it may
be cheaper for crudes oil suppliers to reduce their price to the existing nearby
refinery to enable it to keep going rather than to absorb substantial addition-
al transportation costs.
C.3..C Most refined petroleum products are fungible and widely avail-
able in large quantities at wholesale prices that are quoted daily in such
publications as "Platts Oilgram Price Service" and "Oil Daily." As noted
earlier, over half of the industry's outturn is sold as commodities without
1 Most residual fuel oil imports come from refineries located in the
Caribbean. These same refineries would be available, in the event of an embargo,
to process crude oil stored under the strategic storage plan.
-------
11-13
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-------
11-14
brand identification. Moreover, in order to reduce transportation costs,
there is substantial trading between suppliers of products that are eventually
sold on the branded market.
The decision to shut down a refinery, because of pollution control costs
or any other reason, is based on economic criteria. The criteria will be the
same for an independent refinery as for one that is part of a company integrated
forward to the retail market and backwards to crude oil production. The deci-
sion to shut down would be based on an evaluation of the cash flow from the
refining/marketing system. If the present value of expected future net cash
flow generated by keeping the refinery going is less than the plant's salvage
value, it would be better to scrap the refinery than to keep it in operation.
There are no unusual or hidden profits of integration that need to be con-
sidered. 1
The preceding discussion shows that the individual refinery rather than
the company is the proper level at which to analyze the industry for refinery
closures. More important than intercompany differences are the different
types of refineries that will each be uniquely affected by revised effluent
treatment guidelines.
C.S.c.i Discharge mode. There are four modes of waste water
discharge from refineries: 1) Many refineries discharge no effluent water. In
some cases effluent water can all be disposed by such methods as treatment and
reuse, underground disposal via injection wells, percolation into sandy or
gravelly soil, or open pit evaporation. Such refineries will be unaffected
by effluent guidelines. 2) Several refineries discharge their effluent to
publicly-owned treatment works (POTWs) for treatment. Such arrangements will
be regulated by revised pretreatment guidelines. 3) A few refineries, notably
in the San Joaquin Valley in California and along the Houston ship channel,
* This has not always been the case. Before the crude oil production
depletion allowance was repealed, there probably were gains from integration.
Also, transportation facilities probably were not in the past, and it is
alleged, may not presently be equally accessible to all refiners and marketers.
-------
11-15
discharge effluent to jointly-owned industrial treatment plants. It was
unclear whether such refinery/treatment plant combinations will be governed by
a combination of revised pretreatment guidelines and municipal secondary
treatment regulations, or by revised BATEA guidelines. It was assumed that
these refineries are not subject to revised BATEA guidelines. 4) All other
refineries discharge directly into receiving bodies. These plants will be
subject to revised BAT guidelines. A summary of refinery capacity by waste
water discharge mode was provided in Exhibit II.1.
C.S.c.ii New or existing source. New refineries will be
subject to new source performance standards (NSPS or PSNS). Refineries or
major expansions of existing refineries for which construction starts after
proposal of these regulations will be subject to these new source standards.
C.3.c.iii Refinery process unit configuration. Refinery con-
figuration is a good proxy for determining the value added by refining. The
more highly configured a refinery is that is, the more complex it is
the higher will be the average unit value of its products and hence its value
added per unit of throughput. It is useful to distinguish between five levels
of refinery complexity. 1) The most simple plants are those that have only
one significant processing facility, a crude oil distillation, or "topping",
unit. Such refineries process crude oil into residual and distillate fuel
or chemical plants). 2) Slightly more complex refineries consist of topping
capacity plus vacuum distillation of residual fuel oil. Such refineries pro-
cess high-sulfur crude oils into asphalt, high-sulfur distillate and naphtha.
3) Refineries equipped with both topping and catalytic reforming facilities are
able to process crude oils into gasoline and fuel oils. 4) Refineries equipped
with topping and catalytic reforming plus cracking (catalytic, hydro or thermal)
are able to "convert" into gasoline some material that would otherwise be fuel
oil. Consequently, such refineries typically process crude oils into a high
fraction of gasoline, plus kerosene jet fuel (for commercial aircraft) and low-
sulfur fuel oils. 5) Refineries equipped for the manufacture of lubricating
oils are highly complex, requiring large investment per unit volume of finished
lubricating oil. Small lubricating oil refineries typically include only cata-
lytic reforming in addition to topping and lubricating oil processes.
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11-16
C.3.c.lv Geographic location. Location is important for judg-
ing a refinery's competitive position. The least advantageously located
refinery would be one sited in an area, such as Houston, that has many other
refineries Which bring in crude oil and process it into products that must be
shipped to markets elsewhere in the United States. The most advantageously
located refinery would be adjacent to an oil producing field with most of its
sales within short truck delivery distance, and no other refineries or product
pipeline terminals in the area.
Because so few refineries will be significantly affected by revised guide-
lines it was not necessary to develop a formal methodology for describing the
competitive strength or weakness of geographic locations. Rather, this factor
was evaluated on an individual basis.
C.4 Financial Status of Industry Segments. As was discussed in the first
part of this section, the financial status of the petroleum refining industry
in 1978 was not considered relevant for judging the impacts of 1984 of revised
guidelines. Instead, the impact assessment was based on the financial status
that would be expected without price controls but with one or the other of two
levels of government protection of the industry.
C.4.a Low protection. A level of protection was assumed that would
hold industry capacity roughly constant. Some capacity increase would take
place in refineries that are competitively well situated and can be inexpen-
sively "debottlenecked," and some abandonment of inefficient facilities would
take place. With this level of protection the industry would be financially
marginal.
C.4.b High protection. A level of protection was assumed that would
cause the industry to grow at a rate equal to the growth in domestic consumption
of petroleum products. With this level of protection the industry would be
financially strong. The difference in price between crude oil and finished
products would have to be significantly greater than it was in 1978 to attract
new refining investments. Then-existing refineries therefore would experience
greatly increased cash flows.
-------
Chapter III
METHODOLOGY
This chapter outlines the methodology used in the economic analysis of
revised effluent guidelines for the petroleum refining industry. The economic
impact analysis included two keys steps: determination of the price effects
of the revised guidelines, and determination of quantity and employment effects
associated with price changes and with the shutdown of plants faced with high
costs to conform.
A. Price Analysis
The analysis is based on two alternative levels of protective tariff on
imported petroleum products. The two levels are explained and justified on
pages 11-10 and 11-11.
The price in a competitive market for any manufactured product is deter-
mined by the cost of the highest-cost supplier whose output clears the market.
In the case of petroleum products in the U.S. market, there was not enough
existing domestic refinery capacity to clear the market for most products. So
the market clearing supply came from either imports or domestic capacity expan-
sions.
Foreign refineries had substantial idle capacity that could have been
operated at lower costs than can many existing U.S. refineries. So, in the
absence of crude oil price controls the U.S. market price would, up to a point,
be determined by foreign refining costs plus U.S. import tariff costs. However,
at some level of tariff, the cost of imports would have become greater than the
cost of products manufactured in new U.S. facilities.
The price of imports was not affected at all by revised guidelines. So
revised guidelines would have had no impact on market prices of petroleum
products at all tariff/quota levels below that necessary to encourage construc-
tion of new domestic capacity.
-------
III-2
At tariff levels sufficiently high to encourage new domestic refinery
construction, revised guidelines for new plants (NSPS or PSNS) would have had
a price effect. U.S. market prices for petroleum products would have had to
fully reflect the full long-run cost of installing more stringent treatment
facilities, or the new construction would not have been economically attrac-
tive and hence would not have taken place.
B. Quantity Analysis
At high tariff levels, revised NSPS and PSNS could have had a price effect
and an associated quantity effect. The quantity was determined by the price
elasticity of demand for petroleum products. However, at that overall market
price level, no existing refineries were forced to shutdown by the costs of
meeting the revised guidelines.
At low levels of tariff, there would be no quantity effects due to price.
But there might have been shutdowns of existing refineries with high costs-to-
conform to revised guidelines. The shutdown analysis entailed comparing the
value of each existing discharging refinery with the costs of conforming it to
revised guidelines. The value of the existing refinery was established from
an investor's point of view: that is, as a source of cash income. From
that viewpoint, past capital investments or the cost to reproduce the refinery
were irrelevant. The only criteria that established value were the amount and
timing of future cash to be returned to the investor. The analysis, then,
consisted of two steps: estimation of future cash flows from the refineries,
and comparison of these cash flows with the costs of conforming effluent qual-
ity from those refineries to the requirements of revised guidelines.
Since product prices and consumption would not be affected by the costs of
conforming existing refineries to revised guidelines, the shutdown analysis was
straightforward. The cost to conform each refinery to revised guidelines was
compared with the value of each refinery as defined above. Refineries which
faced conforming costs greater than their value would shut down. All others
-------
III-3
would continue to operate, though their value would diminish by the capi-
talized value of the costs to conform.
It was conceivable that the salvage value of a plant could have been
greater than its value from an investor's viewpoint. If this were so, the
plant would be scrapped even though it showed a positive present value cash
flow. But this could not happen in practice, for the salvage value of refinery
equipment was predominantly based on its usefulness to other refiners. Prices
for salvaged refinery equipment were high when it was profitable to construct
and operate new refineries. Conversely, when refinery operations were marginal,
salvage values were also low.
The balance of trade effects of revised guidelines would reflect only the
necessity to replace volume from the very few refineries that would have chosen
to shut down rather than conform to the guidelines. Employment effects of re-
vised guidelines would reflect the number of new employees required to operate
and maintain the new effluent treating equipment offset by the number of em-
ployees losing work due to refinery shutdowns.
-------
Chapter IV
COSTS OF CONFORMING PETROLEUM REFINERIES TO
REVISED BATEA GUIDELINES, NEW SOURCE PERFORMANCE STANDARDS,
PRETREATMENT GUIDELINES, AND PRETREATMENT STANDARDS FOR NEW SOURCES
The cost data used in this study consisted of two sets of capital costs
and operating costs for most refineries that discharged during 1976 (see
"Coverage" in Section B of Chapter II). Five sets of costs were furnished for
a model new refinery. The data were prepared by the Effluent Guidelines Divi-
sion, Office of Water and Hazardous Materials, U.S. Environmental Protection
Agency; and Burns and Roe Industrial Services Corp.* All costs were stated in
dollars of 1977 purchasing power. These costs had been approved for use in
this report by EPA. The contractor was instructed to use the costs as revised
in the latest document.
A. Existing Sources
For indirectly discharging existing refineries, costs were developed for
two alternative treatment methods. Either method was assumed to be applied to
effluent that has already been treated to the quality defined in Draft Supple-
ment for Pretreatment to^ the Development Document for the Petroleum Refining
Industry Existing Point Source Category, EPA 440/1-76/083, December 1976.
"Option 1" is to treat cooling tower blowdown water to remove chromium.
"Option 2" is a combination of flow reduction, biological treatment, equaliza-
tion and filtration that is intended to bring pollutant mass discharge into
conformance with revised PSES.^
1 The data for direct dischargers were reported in March, 1979, in Cost
Manual for the Direct Discharge Segment of the Petroleum Refining Industry as
revised on September 15, 1979. The data for indirect dischargers were reported
in a letter from Burns and Roe to Sobotka & Co., Inc., dated May 18, 1979. The
data for new source dischargers were reported in a letter from Burns and Roe to
Effluent Guidelines Division, U.S. Environmental Protection Agency, dated
April 11, 1979.
2 The revised PSES definition used for Option 2 is not the same as the re-
vised BAT guideline for direct dischargers. The Option 2 definition is asso-
ciated with a version of the Cost Manual that was issued in April 1978.
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IV-2
For directly discharging existing refineries, costs were also developed
for two alternative levels of treatment. Either alternative was assumed to be
applied to effluent that has already been treated to best practical technology
(BPT) quality. For both levels the flow was based on 73 percent of the "model
flow" computed for that refinery. Details of the model flow equation were
presented in the March 1979 "Cost Manual."
Costs for the two levels of treatment were derived from the following
treatment schemes: Level 1 - flow reduction to 73 percent of model flow, plus
installation of equalization and filtration (if not already installed). Level
2 - all Level 1 installations plus installation of either powdered activated
carbon addition facilities or rotating biological contractors.
The cost data are presented for direct and indirect dischargers in Exhibits
IV.1 and IV.2, respectively. Exhibit IV.3 contains a summary of costs for
these refineries.
A term appears in Exhibits IV.1, IV.2 and IV.3 that may require explana-
tion. "Annualized costs" combine capital cost and operating cost into a
single value that represents average total annual disbursements required to
finance, operate, and amortize a facility. The "annualized costs" presented
i
in the exhibits are the sum of two components:
A.I The first component is annual cash operating costs for labor, mate-
rials, chemicals, energy, insurance, and ad valorem taxes. These costs were
those provided in the Cost Manual and the Burns and Roe letters plus the esti-
mated value of increased and ad valorem taxes. The latter costs together
amount annually to about four percent of original capital investment.1
1 Sobotka & Company, Inc., Economic Impact £f_ EPA's Regulations on the
Petroleum Refining Industry, April 1976, EPA 230/3-76-004, Part Two, p. II-2.
The data were supplied by Turner, Mason & Solomon from a survey of Gulf refiners.
-------
IV-3
A.2 The second component is capital recovery and return-on-investment
at the rate of 12 percent per year, the rate recommended by EPA.* It was
assumed that the investments would have the following characteristics: Twenty-
year physical life, sixteen-year life for depreciation, double declining
balance depreciation schedule, fifty percent income tax rate, no investment
tax credit, no working capital, no salvage value, and construction funds
spent over a two-year period: thirty percent in the first year and seventy
percent in the second.
These parameters led to an annual before-tax cash flow requirement of
twenty-one percent of capital cost. In other words, the owners of such an
asset could, on average, have taken this much cash out of the business
each year of its useful life. Some of it, of course, must have been paid as
income tax.
The derivation of annual capital charges could have included other factors.
On the one hand, inclusion of the investment tax credit and of rapid amortiza-
tion (allowed for pollution control facilities) would have led to lower annual
charges. Alternatively, inclusion of land costs (assumed to be zero) and of
"sustaining" investments^ would have led to higher charges. The excluded
factors roughly offset each other. The effect of higher annual charges was
derived in Chapter VII.
Costs were converted to a per-barrel basis on the assumption that crude
oil throughput would average ninety percent of calendar day capacity. It was
noted that such a rate of capacity utilization might not be achievable by
* Gerald A. Pogue, Estimation £f_ the Cost of Capital for Major U.S.
Industries, November 1975, EPA 230/3-76-001.
2 Replacement of worn out equipment; installation of facilities required
to meet new and/or revised environmental, safety and health regulations; re-
placement of" obsolescent equipment with new equipment that costs less to operate
and/or maintain, such as more efficient furnaces and motors; and installation
of new equipment to take advantage of technological advances, e.g., new cracking
or reforming catalysts, process control computers, etc. See David F. Hart,
Harvard Business Review, Vol. 46, No. 5 (September/October 1968), p. 32.
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IV-4
some asphalt refineries with highly seasonal demand. Reported annual average
operating rates in 1976 for asphalt refineries ranged from 17 percent to 100
percent of capacity. Had several years of data been available, it would have
been better to use a historical average rate for each plant rather than an
assumed rate, but such data were not available.
B. New Sources
The costs of conforming new source refineries to revised guidelines were
computed for a specific model refinery. The model1 was sized for a capacity of
190,000 barrels per calendar day of Arabian Light crude oil. The model was con-
figured for a high yield of gasoline, commercial jet fuel and distillate fuel
oil to correspond with demand growth forecasts published by the Department of
Energy.2
Current NSPS (BADT) regulations for new, directly-discharging refineries
corresponded closely to revised Level 1 NSPS guidelines, so there was no cost
for conforming the model to this level. Revised Level 2 NSPS guideline costs
represented the addition of a powdered activated carbon facility to the (assumed)
existing activated sludge unit.
Level 1 revised guideline PSNS costs were based on chromium removal from
cooling tower blowdown. Level 2 revised PSNS costs were based on installing
BPT technology, including activated sludge treatment, filtration, and appro-
priate inplant controls.
1 Memorandum from Sobotka & Co., Inc., to Office of Analysis and Evalua-
tion, NSPS Refinery_ Cpjnfiguration, February 14, 1979.
2 Energy Information Administration, Annual Report _t£ Congress 1977,
Volume JL! - Projections of_ Energy Supply and Demand and Their Impacts, DOE/EIA -
0036/2, April 1978, Chapter 5.
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IV-5
Costs of conforming the model new refinery to revised NSPS and PSNS are
presented in Exhibit IV.4. Also shown are costs for achieving no aqueous dis-
charge . *
1 EPA Internal Memorandum from Effluent Guidelines Division to Office of
Analysis and Evaluation, Compliance Cost for Achieving N£ Discharge - New
petroleum Refineries, 5 June 1979. These 1972 costs were inflated to 1977 using
cost indices published in the Oil and Gas Journal.
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IV-6
Exhibit IV.1
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
TOPPING
2
6
70
100
189
197
199
255
266
292
Subtotal
ASPHALT
3
9
19
52
53
54
72
Distillation
Capacity
(1000 bpd)
CONFIGURATION
20.0
22.0
13.0
11.0
5.0
4.4
9.7
29.5
5.9
1.0
121.5
CONFIGURATION
1.2
3.5
2.5
4.0
14.0
3.0
8.5
Capital
Costs
Lev 1 Lev 2
(1000
0
0
12
0
0
0
125
0
130
0
267
0
0
0
0
0
0
0
$)
50
85
160
35
53
50
197
115
190
0
935
35
52
0
240
35
35
35
Operating
Costs
Lev 1
(1000
0
0
9
0
0
0
13
0
13
0
35
0
0
0
0
0
0
0
Lev 2
$/year)
11
11
33
11
8
8
23
15
74
0
194
6
8
0
26
19
12
18
Annualized Costs
Total
Lev 1
(1000
0
0
12
0
0
0
39
0
40
0
91
0
0
0
0
0
0
0
Lev 2
$/year)
22
29
67
18
19
18
64
39
114
0
390
13
19
0
76
26
19
25
Unit
Lev 1
Lev 2
(cents/barrel)
0
0
0.3
0
0
0
1.2
0
2.1
0
0
0
0
0
0
0
0
0.3
0.4
1.6
0.5
1.2
1.3
2.0
0.4
5.9
0
3.4
1.6
0
5.8
0.6
2.0
0.9
-------
IV-7
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation
Capacity
(1000 bpd)
Capital
Costs
Lev 1
Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
(cents
Lev 2
i/barre
ASPHALT CONFIGURATION (CONTINUED)
108
118
119
120
236
237
260
Subtotal
TOPPING PLUS
109
13.9
6.0
11.0
4.2
4.5
5.0
3.0
84.2
CHEMICALS
23.5
0
0
0
0
0
0
0
0
0
35
55
115
100
35
35
58
865
40
0
0
0
0
0
0
0
0
0
9
9
15
13
14
7
9
165
27
0
0
0
0
0
0
0
0
0
16
21
39
34
21
14
21
344
35
0
0
0
0
0
0
0
0
0.4
1.0
1.1
2.5
1.4
0.9
2.2
0.5
REFORMING CONFIGURATION
1
7
24
30
87
88
91
30.0
38.0
53.3
22.8
5.2
45.0
3.9
0
0
0
180
125
0
0
50
70
240
230
220
175
35
0
0
0
18
13
0
0
23
10
26
44
26
20
5
0
0
0
56
39
0
0
34
25
76
92
72
57
12
0
0
0
0.7
2.3
0
0
0.3
0.2
0.4
1.2
4.2
0.4
1.0
-------
IV-8
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
REFORMING
93
103
112
190
210
213
239
259
265
Subtotal
CRACKING
11
20
32
37
40
41
43
46
Distillation Capital
Capacity Costs
(1000 bpd)
CONFIGURATION
6.5
36.0
12.5
9.0
18.1
21.6
22.7
655.0
200.0
1,179.6
CONFIGURATION
47.0
100.0
110.0
103.0
405.0
365.0
80.0
65.5
Lev 1 Lev 2
(1000
(CONTINUED)
0
0
160
0
0
0
0
0
0
465 1
0
0
0 4
0 1
435
0 6
0 2
0
$)
35
78
330
60
35
73
35
75
48
,789
60
75
,000
,600
555
,400
,100
60
Operating
Costs
Lev 1
(1000
0
0
16
0
0
0
0
0
0
47
0
0
0
0
35
0
0
0
Lev 2
$/year)
7
11
36
9
6
10
18
172
53
476
70
153
352
148
550
546
186
75
Annual i zed Costs
Total
Lev 1
(1000
0
0
50
0
0
0
0
0
0
145
0
0
0
0
126
0
0
0
Lev 2
$/year)
14
27
105
22
13
25
25
188
63
850
83
169
1,192
484
667
1,890
627
88
Unit
Lev 1
Lev 2
(cents/barrel)
0
0
1.2
0
0
0
0
0
0
0
0
0
0
0.1
0
0
0
0.7
0.2
2.6
0.7
0.2
0.4
0.3
0.1
0.1
0.5
0.5
3.3
1.4
0.5
1.6
2.4
0.4
-------
IV-9
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation Capital
Capacity Costs
(1000 bpd)
Lev 1 Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$7yeaf)
Unit
Lev 1 Lev 2
(cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
49
50
51
56
57
59
60
61
62
63
64
65
67
68
71
74
76
77
80
33.5
21.5
150.0
40.0
107.0
57.0
195.0
200.0
295.0
91.0
78.0
154.0
380.0
140.0
21.0
22.5
42.5
23.2
52.0
0
0
865
195
530
0
0
0
0
0
235
370
2,610
385
0
0
180
0
0
120
565
3,140
1,100
630
75
75
80
100
1,900
310
470
5,860
485
200
170
1,430
40
90
0
0
602
22
112
0
0
0
0
0
25
42
379
54
0
0
19
0
0
15
57
1,030
106
678
88
148
208
377
125
221
328
869
434
230
20
135
30
13
0
0
784
63
223
0
0
0
0
0
74
120
927
135
0
0
57
0
0
40
176
1,689
337
810
104
164
225
398
524
286
427
2,100
536
65
56
435
38
32
0
0
1.6
0.5
0.6
0
0
0
0
0
0.3
0.2
0.7
0.3
0
0
0.4
0
0
0.4
2.5
3.4
2.6
2.3
0.6
0.3
0.3
0.4
1.8
1.1
0.8
1.7
1.2
0.9
0.8
3.1
0.5
0.2
-------
IV-10
Exhibit IV.I (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation
Capacity
(1000 bpd)
Capital
Costs
Lev 1
Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
81
83
84
85
92
94
96
97
98
99
102
104
105
106
113
115
116
117
121
57.0
90.0
80.0
138.0
270.0
85.0
528.0
50.0
202.3
28.7
90.0
298.0
89.0
154.9
42.0
131.9
68.0
30.0
295.0
160
0
0
0
480
228
0
0
0
0
230
0
305
0
0
0
0
355
0
1,040
85
75
95
2,810
303
2,480
35
1,600
83
305
4,100
380
1,100
330
90
900
945
3,100
16
0
0
0
50
22
0
0
0
0
23
0
34
0
0
0
0
23
0
99
195
142
268
479
169
442
12
144
11
45
344
218
104
34
220
84
80
275
50
0
0
0
151
70
0
0
0
0
71
0
98
0
0
0
0
98
0
317
213
158
288
1,069
233
963
19
480
28
109
1,205
298
335
103
239
273
278
926
0.3
0
0
0
0.2
0.3
0
0
0
0
0.2
0
0.3
0
0
0
0
1.0
0
1.7
0.7
0.6
0.6
1.2
0.8
0.6
0.1
0.7
0.3
0.4
1.2
1.0
0.7
0.7
0.6
1.2
2.8
1.0
-------
IV-11
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation Capital
Capacity Costs
(1000 bpd)
Lev 1
Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
122
124
125
126
127
129
131
132
133
134
144
146
147
149
150
151
152
153
155
107.0
42.0
56.0
46.0
6.5
5.0
168.0
300.0
100.0
103.0
49.9
4.9
65.0
44.0
51.0
177.0
120.0
125.0
14.5
520
0
0
260
0
120
0
740
660
350
0
125
0
170
0
330
630
0
0
4,920
365
340
4,660
150
220
90
3,070
785
450
113
220
40
970
52
3,030
745
100
95
104
0
0
36
0
13
0
138
161
48
0
13
0
18
0
32
143
0
0
485
38
35
422
18
26
240
577
767
366
14
26
53
92
83
272
760
304
13
213
0
0
91
0
38
0
293
300
122
0
39
0
54
0
101
275
0
0
1,518
115
106
1,400
50
72
259
1,222
932
460
38
72
61
296
94
908
916
325
33
0.6
0
0
0.6
0
2.3
0
0.3
0.9
0.4
0
2.4
0
0.4
0
0.2
0.7
0
0
4.3
0.8
0.6
9.3
2.3
4.4
0.5
1.2
2.8
1.4
0.2
4.5
0.3
2.0
0.6
1.6
2.3
0.8
0.7
-------
IV-12
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
CRACKING
156
157
158
159
160
161
162
163
165
167
168
169
176
179
180
181
183
184
186
Distillation
Capacity
(1000
bpd)
Capital
Costs
Lev 1 Lev 2
(1000
$)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
CONFIGURATION (CONTINUED)
55.
130.
54.
19.
23.
51.
90.
52.
60.
195.
170.
188.
52.
26.
80.
363.
63.
67.
185.
0
3
6
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
575
0
720
0
0
315
980 3
0
0
0
475
75
40
225
35
275
75
700
234
675
80
845
285
225
390
,540
420
75
75
0
0
0
0
0
0
0
0
0
82
0
125
0
0
41
145
0
0
0
48
164
51
24
22
29
201
70
26
482
231
799
30
25
261
590
42
103
149
0
0
0
0
0
0
0
0
0
203
0
276
0
0
107
351
0
0
0
148
180
59
71
29
87
217
217
75
624
248
976
90
72
343
1,333
130
119
165
0
0
0
0
0
0
0
0
0
0.3
0
0.4
0
0
0.4
0.3
0
0
0
0.8
0.4
0.3
1.1
0.4
0.5
0.7
1.3
0.4
1.0
0.4
1.6
0.5
0.8
1.3
1.1
0.6
0.5
0.3
-------
IV-13
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation Capital
Capacity Costs
(1000 bpd)
Lev 1
Lev 2
(1000 $)
Operating
Costs
Annualized Costs
Total
Lev 1 Lev 2
(1000 $/
year)
Unit
Lev 1 Lev 2 Lev 1 Lev 2
(1000 $
/year) (cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
194
196
201
204
205
208
211
212
216
219
221
222
226
227
230
232
233
234
235
405.0
319.0
66.0
103.0
103.4
310.0
125.0
60.0
476.0
80.7
129.5
13.5
7.5
45.0
25.0
55.0
100.0
75.0
94.0
750
1,280
0
268
270
0
0
0
0
0
300
155
0
0
0
0
0
0
0
10,100
4,380
60
358
1,970
100
60
50
3,250
850
390
430
65
60
520
60
60
60
75
74
244
0
29
27
0
0
0
0
0
34
16
0
0
0
0
0
0
0
945
724
82
297
180
394
71
63
488
82
297
45
10
98
52
92
87
87
123
232
513
0
85
84
0
0
0
0
0
97
49
0
0
0
0
0
0
0
3,066
1,644
95
372
594
415
84
74
1,170
260
379
135
24
111
161
105
100
100
139
0.2
0.5
0
0.3
0.2
0
0
0
0
0
0.2
1.1
0
0
0
0
0
0
0
2.3
1.6
0.4
1.1
1.8
0.4
0.2
0.4
0.7
1.0
0.9
3.1
1.0
0.8
2.0
0.6
0.3
0.4
0.4
-------
IV-14
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation Capital
Capacity Costs
(1000 bpd) Lev 1
Lev 2
(1000 $)
CRACKING CONFIGURATION
238
243
252
256
257
261
Subtotal
LUBRICATING
10
12
89
90
154
172
173
174
177
240
241
78.0
42.0
10.6
40.0
150.0
40.0
12,568.9
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000 :
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
(CONTINUED)
243
0
0
0
0
180
17,504
318
145
115
285
1,400
228
106,094
27
0
0
0
0
18
3,026
181
17
15
30
128
59
22,935
78
0
0
0
0
56
6,704
248
47
39
90
422
107
45,217
0.3
0
0
0
0
0.4
1.0
0.3
1.1
0.7
0.9
0.8
OIL CONFIGURATION
6.0
4.5
4.0
2.2
5.5
12.0
3.5
7.1
7.6
5.5
12.0
0
0
0
0
0
185
160
135
175
0
0
70
441
77
60
700
235
200
565
225
40
45
0
0
0
0
0
22
16
13
19
0
0
10
45
12
9
68
88
61
57
86
26
42
0
0
0
0
0
61
50
41
56
0
0
25
138
28
22
215
137
103
176
133
34
51
0
0
0
0
0
1.5
4.3
1.8
2.2
0
0
1.3
9.3
2.1
3.0
11.9
3.5
9.0
7.5
5.3
1.9
1.3
-------
IV-15
Exhibit IV.1 (continued)
COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
LUBRICATING
242
258
Subtotal
Distillation
Capacity
(1000 bpd)
Capital
Costs
Lev 1 Lev 2
(1000 $)
Operating
Costs
Lev 1 Lev 2
(1000 $/year)
Annualized Costs
Total
Lev 1 Lev 2
(1000 $/year)
Unit
Lev 1 Lev 2
(cents/barrel)
OIL CONFIGURATION (CONTINUED)
5.2
85.5
160.0
0 40
0 60
655 2,758
0 30
0 86
70 620
0
0
208
38
99
1,199
0 2.3
0 0.4
PLANT DOES NOT PROCESS CRUDE OIL1
295
309
Subtotal
0.0
0.0
0.0
170 210
220 265
390 475
18 44
482 524
500 568
54
528
582
88
580
668
Grand Total
Direct 14,141.8
19,281 112,956 3,678 24,985 7,730 48,703
No entry for Item II.A in reply to Section 308 Questionnaire.
-------
IV-16
Exhibit IV.2
COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
TOPPING
23
110
128
145
193
195
206
231
264
305
Subtotal
ASPHALT
8
18
31
79
107
148
166
Subtotal
Distillation
Capacity
(1000 bpd)
CONFIGURATION
16.0
6.0
3.8
5.2
3.2
1.0
36.5
10.0
23.0
13.0
116.9
CONFIGURATION
5.0
19.5
12.0
3.0
17.0
20.0
14.0
90.5
Capital
Costs
Opt 1
(1000
0
0
0
59
59
0
70
0
0
103
291
63
145
100
0
100
0
118
526
OPJL-2 .
$)
315
250
277
247
247
247
437
1,110
250
277
3,657
0
495
247
0
255
493
273
1,763
Operating
Costs
Opt 1 Opt 2
(1000 $/year)
0
0
0
9
9
0
11
0
0
15
44
10
19
14
0
14
0
17
74
73
67
41
65
65
65
113
422
66
41
1,018
0
78
65
0
68
131
108
450
Annualized Costs
Total
Opt 1
(1000 $
0
0
0
21
21
0
26
0
0
37
105
23
49
35
0
35
0
42
184
Opt 2
i/year)
139
120
99
117
117
117
205
655
119
99
1,787
0
182
117
0
122
235
165
821
Unit
Opt 1 Opt 2
(cents/barrel)
0
0
0
1.3
2.0
0
0.2
0
0
0.9
1.4
0.8
0.9
0
0.6
0
0.9
2.7
6.1
10.0
6.9
11.1
35.7
1.7
20.0
1.6
2.3
0
2.8
3.0
0
2.2
3.6
3.6
-------
IV-17
Exhibit IV.2 (continued)
COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation
Capacity
(1000 bpd)
Capital
Costs
Opt 1
(1000
Opt 2
$)
Operating
Costs
Opt 1
(1000
Opt 2
$/year)
Annualized Costs
Total
Opt 1
(1000
Opt 2
$/year)
Unit
Opt 1
Opt 2
(cents/barrel)
TOPPING PLUS CHEMICALS
207
REFORMING
16
21
291
Subtotal
CRACKING
13
14
25
29
33
38
45
58
73
78
86
46.0
CONFIGURATION
48.0
20.0
15.2
83.2
CONFIGURATION
193.0
12.4
53.8
131.1
44.0
93.0
111.0
70.0
44.5
30.0
25.0
166
188
102
202
492
620
114
232
357
206
425
480
284
225
143
211
375
826
373
250
1,449
5,800
315
375
4,650
1,090
4,350
3,900
1,900
915
1,390
800
23
28
14
39
81
211
12
51
88
37
152
176
74
45
17
44
108
169
78
61
308
858
64
70
707
196
629
575
235
121
175
136
58
67
35
81
183
341
36
100
163
80
241
277
134
92
47
88
187
342
156
114
612
2,076
130
149
1,684
425
1,542
1,394
634
313
467
304
0.4
0.4
0.5
1.6
0.5
0.9
0.6
0.4
0.6
0.8
0.8
0.6
0.6
0.5
1.1
1.2
2.2
2.4
2.3
3.3
3.2
0.8
3.9
2.9
5.1
3.8
2.8
2.1
4.7
3.7
-------
IV-18
Exhibit IV.2 (continued)
COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation Capital
Capacity
(1000 bpd)
CRACKING CONFIGURATION
111
114
130
142
143
175
182
188
200
203
224
225
228
229
66.0
24.0
5.4
63.0
44.0
165.0
324.5
100.0
29.3
335.0
20.0
40.4
25.0
5.6
Costs
Opt 1
Opt 2
(1000 $)
Operating
Costs
Opt 1
(1000 $'
Annual! zed Costs
Total
Opt 2 Opt 1
/year)
Opt 2
(1000 $/year)
Unit
Opt 1
Opt 2
(cents/barrel)
(CONTINUED)
470
0
0
216
0
972
1,000
500
285
1,062
0
0
216
98
2,450
683
1,310
2,450
2,190
13,300
7,000
3,660
1,150
13,800
655
2,220
710
242
213
0
0
38
0
701
354
202
91
382
0
0
40
13
309
130
473
309
262
2,892
1,061
486
152
2,062
138
266
140
35
312
0
0
83
0
905
564
307
151
605
0
0
85
34
824
273
748
824
744
5,685
2,531
1,255
394
4,960
276
732
289
86
1.4
0
0
0.4
0
1.7
0.5
0.9
1.6
0.6
0
0
1.0
1.8
3.8
3.5
42.2
4.0
5.2
10.5
2.4
3.8
4.1
4.5
4.2
5.5
3.5
4.7
Subtotal 2,055.0
8,,H6 77,305 2,941 12,481 4,645 28,739
LUBRICATING OIL CONFIGURATION
220 10.0 0
258
0
67
0 121 0
3.7
Grand Total 2,401.6
Indirect
9,591 84,807 3,163 14,432 5,175 32,267
-------
IV-19
Exhibit IV.3
SUMMARY OF COSTS TO PETROLEUM REFINERIES
OF CONFORMING TO REVISED EFFLUENT DISCHARGE GUIDELINES
Crude Oil
.lation Capital
icity Costs
Operating
Costs
Annual! zed
Costs
Total Unit
(1000 bpd) (1000 $) (1000 $/year) (1000 $/year) (cents/barrel)
DIRECT DISCHARGERS
Level 1
Level 2
INDIRECT DISCHARGERS
Option 1 2,402
Option 2 2,402
14,142
14,142
19,281
112,956
3,678
24,985
7,730
48,703
0.2
1.0
9,591
84,807
3,163
14,432
5,175
35,267
0.7
4.1
-------
IV-20
Exhibit IV.4
COSTS TO A NEW PETROLEUM REFINERY*
OF CONFORMING TO REVISED EFFLUENT DISCHARGE GUIDELINES
DIRECT DISCHARGE (NSPS)5
Level 1
Level 2
INDIRECT DISCHARGE (PSNS)t
Option 1
Option 2
NO AQUEOUS DISCHARGE8
Capital
Costs
(1000 $)
Operating
Costs
(1000 $/year)
Annualized
Costs
Total Unit
(1000 $/year) (cents/barrel)
0
75
260
5,800
0
218
140
2,230
0
234
195
3,450
0
0.4
0.3
5.5
9,500
1,880
3,875
6.2
Based on 171,000 barrels per day annual average throughput.
Costs are additional above current NSPS (BADT).
Costs are additional above current pretreatment guidelines for existing refineries.
-------
Chapter V
ECONOMIC IMPACT ANALYSIS WITH HIGH LEVEL OF
PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS
It was established in Chapter III that either of two levels of protection
against refined petroleum product imports might have been reasonably ex-
pected to be in place in 1984. In this chapter, a high level of protection
was assumed. Specifically, the level was high enough to support growth of
U.S. domestic refinery capacity at about the same rate as the rate of growth
of consumption of petroleum products. In this situation, the market would
have cleared at prices determined by the full cost of products manufactured in
new facilities.
A. Price Effects of Revised Guidelines
If new refinery capacity is to be built, the entire plant must earn an
adequate rate of return. This includes the effluent-treating facilities.
Consequently, prices with revised new source guidelines will be higher by an
amount equal to the full annualized cost of the facilities needed to achieve
them. The costs are.
Direct dischargers (NSPS)
Level 1 no cost
Level 2 0.009 cents per gallon refined product
Indirect dischargers (PSNS)
Option 1 0.007 cents per gallon refined products
Option 2 0.13
No aqueous discharge 0.15 cents per gallon refined product
* Costs are from Chapter IV, Exhibit 6 divided by 0.94, the approximate
fractional yield of products from crude oil in new refineries.
-------
V-2
There was no way to estimate which of the above four options, in fact,
would have turned out to be associated with the price-determining (market
clearing) refinery at any specific time. All that could be concluded was that
the price effect of revised new source guidelines would have ranged from zero
to 0.15 cents per gallon of product manufactured (stated in 1977 purchasing
power).
B. Financial Effects
This chapter assumed that new refineries would be fully compensated for
all costs by tariff protection. Consequently, revised new source guidelines,
by premise, had no financial effect on new refinery capacity.
For existing refineries, the financial impact of revised guidelines would
have been the difference between the benefits associated with higher product
prices caused by revised new source guidelines, and the costs associated with
meeting revised guidelines for existing sources. As developed above, the
benefits might have been as low as zero or as high as 0.15 cents per gallon of
refined product. Existing refineries would process roughly 5,435 million
barrels per year of crude oil.* So the annual benefit to existing refineries
from revised new source guidelines might have been as low as zero or as high
as 340 million dollars per year.^
The total annualized cost to existing refineries of revised guidelines for
existing sources would range from 13 million dollars per year (BATEA Level 1 and
PSES Option 1) to 81 million dollars per year (BATEA Level 2 and PTES Option
2).^ So the net financial effect on existing refineries of revised guidelines
might have been as adverse as a cost of (zero minus 81 =) 81 million dollars
1 Chapter IV, Exhibit IV.3: (14.142 + 2.402) million barrels per day x
0.9 operating ratio x 365 days per year.
2 5,435 million barrels per year x 0.062 dollars per barrel crude oil
processed = 340 million dollars per year.
3 Chapter IV, Exhibit IV.3.
-------
V-3
per year or as beneficial as a revenue increase of (340 minus 13 =) 327 million
dollars per year.
C. Production Effects
This chapter was based on a premise of protection against imports suffi-
ciently high to support growth of U.S. domestic refinery capacity. Hence "by
definition" there could be no production impacts of revised new source guide-
lines on new refineries. Whether or not revised existing source guidelines
had an impact depended on how much the condition of the industry would change
from its current status if a high protection policy were to be implemented.
New refinery capacity^ required a difference between product sales revenue
and raw material acquisition cost of about three dollars per barrel of crude
oil processed^ to justify its construction. During 1978 the difference between
revenue and raw material was approximately 2.3 dollars per barrel.3 Thus, the
gap between 1978 conditions and a high protection policy was 0.7 dollars per
barrel crude oil processed. This improvement in condition was greater than the
highest cost estimated for conforming an existing refinery to revised guide-
lines: 0.42 dollars per barrel.^ So the combination of high protection and
revised guidelines would have left the highest cost-to-conform refinery better
off than in 1978 by roughly 0.28 dollars per barrel of crude oil processed.
Clearly, there would be no production effects of revised guidelines if a high
protection policy was implemented.
1 Size and configuration as outlined in Chapter IV, Section B.
2 Sobotka & Co. , Inc. , Capital and Operating Costs for Grass Roots Re-
fineries with Several Different Process Unit Configurations, Department ojf
Energy Contract No. EJ-78-C-01-2834, Task No. 10, April 12, 1979.
3 Chase Manhattan Bank, The Petroleum Situation, March 1979.
4 Chapter IV, Exhibit 4, Refinery 130.
-------
V-4
D. Employment Effects
Given high protection, no jobs would be lost in the U.S. petroleum refin-
ing industry because of revised effluent guidelines. New jobs would have been
created by revised guidelines. New effluent-treating facilities would have
needed to be operated, maintained, and supervised. It was possible to develop
rough estimates of employment from the data prepared by Effluent Guidelines
Division. The estimates were:
New Jobs
Existing Direct Dischargers
Level 1 40
Level 2 600
Existing Indirect Dischargers
Option 1 10
Option 2 250
Hence, new employment could have ranged from 50 to 850 jobs, depending on
which combination of Level/Option was chosen for implementation.
E. Community and Balance of Trade Effects
Given high protection, revised effluent guidelines were expected to have
no community or balance-of-trade effects.
-------
Chapter VI
ECONOMIC IMPACT ANALYSIS WITH LOW LEVEL OF
PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS
It was noted in Chapter II that either of two levels of protection
against refined product imports might have been expected to be in place in
1984. In this chapter, a low level of protection was assumed. Specifically,
the level was such that the capacity of the industry would remain roughly con-
stant during the period 1979-1990. Of course, there would be some shifting of
capacity as inefficient and/or poorly located plants were abandoned while
efficient and/or well-located plants expand modestly by "debottlenecking"
existing facilities. In this situation, the market would clear at prices
determined by the costs of imports (including the cost of tariffs, if any).
A. Price Effects
Market prices for petroleum products will be determined by the costs of
imports. Import costs would be unaffected by U.S. effluent guidelines. So
there would be no price effects of revised guidelines.
B. Financial Effects
Because petroleum product prices would be unaffected by revised guide-
lines , the costs of revised guidelines would have been absorbed by the petro-
leum refining industry. The total costs of revised guidelines to the existing
industry were shown in Exhibit IV.3 and are repeated here. The costs for a
"model" new source were shown in Exhibit IV.4.
-------
VI-2
Direct Dischargers
Level 1
Level 2
Capital
Costs
(1000 $)
19,281
112,956
Annualized Costs
Operating
Cost
(1000 $/year) (1000 $/year) (cents/barrel)
Total
Unit
3,678
24,985
7,730
48,703
0.2
1.0
Indirect Dischargers
Option 1 9,591
Option 2 84,807
3,163
14,432
5,175
32,267
0.7
4.1
These were small costs compared to other cost elements incurred by refineries,
e.g., raw material cost was about 14 dollars per barrel, cash operating costs
ranged from 0.50 to 2 dollars per barrel, and capital charges ranged from 0.50
to 3 dollars per barrel. It was concluded that revised guidelines would have
a negligible impact on the financial status of the industry as a whole.
C. Production Effects
Although the average cost of revised guidelines would be small, there were
some refineries that would have faced significant cost increases. If such
costs were sufficiently high, refiners would have been better off shutting
down than incurring the costs. It was the purpose of this section to identify
high-cost refineries and to judge whether or not they were likely to shut
down.
A reasonable minimum value for judging the significance of conformance
cost was one-tenth cent per gallon, or 4.2 cents per barrel. One-fourth cent
per gallon is the usual increment by which price quotes for almost all products
are changed. Also, it was essentially impossible to measure unit manufacturing
costs within one-tenth cent per gallon, because product volume measurement was
not sufficiently accurate.
-------
VI-3
The 27 refineries with revised-guideline costs greater than 4.1 cents per
barrel of crude oil processed were listed in Exhibit VI.1.
C-l Values of Existing Refineries. As was stated in Chapter III, the
value of an asset to an investor is the present value of its expected future
cash flow. Of course, no one can compute the present value with certainty
because all the facts required for the computation lie in the unknown future.
But it is possible to infer present values from actions that informed investors
are taking. For example, if several informed investors decided independently
to invest in new catalytic cracking capacity, it was reasonable and useful to
assume that they expected the present value of future cash flow from new cata-
lytic cracking units to equal (or exceed) the cost of such units. Conversely,
if existing crude oil distillation capacity in the world was more than adequate
to meet forecast 1990 needs, it was reasonable and useful to assume that compe-
tition would have restricted cash flow from less efficient crude units to zero;
and no unit would have come anywhere near generating a cash flow commensurate
with its replacement costs.
In the following paragraphs, estimates of the values of new processing
units were developed. Except where otherwise indicated, evidence of new con-
struction was based on listings in Hydrocarbon Processing, February 1979, and/or
Oil and Gas Journal, May 7, 1979. Construction costs of new processing units
(stated in dollars of 1977 purchasing power), were from Sobotka & Co., Inc.,
op. cit., April 12, 1979. Adjustments for unit capacity and age were developed
after unit values are derived.
C.I.a Conversion processes and catalytic reforming. In 1979, many
units of each of these processes were under construction. This established
that many different investors had concluded that acceptable rates of return
could be expected from investments in such units. For consistency with the
annualized costs computed for revised guidelines (Exhibit IV.1) it was assumed
that a discounted cash flow rate-of-return of twelve peripMit per year was
"acceptable." The expected annual before-tax cash flow from such new units,
then, was 21 percent of capital cost. Expected before-tax cash flows from new
large conversion and reforming units are
-------
VT-4
Exhibit VI.1
EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
TO REVISED GUIDELINES OF MORE THAN 4.1
CENTS PER BARREL OF CRUDE OIL PROCESSED
Crude Oil
Refinery
Code
130
195
231
154
193
175
128
12
126
173
174
145
110
266
52
225
177
143
38
78
Distillation
Capacity
(1000 bpd)
5.4
1.0
10.0
5.5
3.2
165.0
3.0
4.5
46.0
3.5
7.1
5.2
6.0
5.9
4.0
40.4
7.6
44.0
93.0
30.0
Configuration*
Discharge
Mode5
Compliance Costs
Lev /Opt Lev /Opt 2
(cents/barrel)
C
T
T
L
T
C
T
L
C
L
L
T
T
T
A
C
L
C
C
C
I
I
I
D
I
I
I
D
D
D
D
I
I
D
D
I
D
I
I
I
2.0
1.7
0.6
4.3
1.8
1.3
2.1
2.2
0.8
0.5
42.2
35.7
20.0
11.9
11.1
10.5
10.0
9.3
9.3
9.0
7.5
6.9
6.1
5.9
5.8
5.5
5.3
5.2
5.1
4.7
As defined in Chapter III: T = topping, A = asphalt,
R = reforming, C = cracking, and L = lube.
§ Direct or Indirect
-------
VI-5
Exhibit VI.1 (continued)
EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
TO REVISED GUIDELINES OF MORE THAN 4.1
CENTS PER BARREL OF CRUDE OIL PROCESSED
Crude Oil
Refinery
Code
229
146
203
129
122
87
224
Distillation
Capacity
(1000 bpd)
5.6
4.9
335.0
5.0
107.0
5.2
20.0
Configuration*
Discharge
Mode8
Compliance Costs
Lev/ Opt Lev/ Opt 2
(cents/barrel)
C
C
C
C
C
R
C
I
D
I
D
D
D
I
1.8
2.4
0.6
2.3
0.6
2.3
4.7
4.5
4.5
4.4
4.3
4.2
4.2
As defined in Chapter III: T = topping, A = asphalt,
R = reforming, C = cracking, and L = lube.
Direct or Indirect
-------
VI-6
Process
Catalytic
cracking
Alkylation
Hydrocracking
Thermal cracking t
Delayed
coking
Catalytic reforming
(including naphtha
desulfurization)
Expected Annual Cash Flow
Capacity,
Thousand Total Cost * Total Unit §
(barrels/day) (million 1978 $) (million $) ($/barrel/day cap.)
127
61
126
27
26.7
12.8
26.5
5.7
485
640
590
285
55
20 §
45
20
20 40 8.4
35 83 17.4
* Including offsite and associated costs.
§ Thousand barrels per day of product.
t Estimated.
420
500
C.l.b Lubricating oil manufacture. The operation of this complex
combination of processes created substantial cash flow. Since World War II, 1
lubricating oil manufacture had generated a before-tax cash flow ranging between
two and four dollars per barrel manufactured.^ Also, the demand facing U.S.
and free world lubricating oil manufacturers was growing at least as rapidly as
is manufacturing capacity.3 Consequently, a continuation of before-tax cash
flows at historical levels seemed assured for many years. On the same basis
as tabulated above, the expected annual cash flow from lubricating oil manufac-
ture was about 1,200 dollars per barrel of calendar day capacity.^
1 With the exception of the Arab oil boycott of 1973 and 1974.
2 R.F. Sommerville, Hydrocarbon Processing , August 1977, p. 127
3 Ibid.
($3.00 per barrel x 365 days per year)/0.9 capacity utilization.
-------
VI-7
C.l.c Crude oil distillation. There existed in 1978 a large world-
wide surplus of crude oil distillation capacity.1 Consequently, in the absence
of tariff or quota protection, the only cash flow that would have been expected
from a large new crude unit would have been a reduction in company income
taxes due to tax depreciation of the new unit. This amounted to 3.5 percent of
capital cost, which was about fifteen dollars per year per barrel of calendar
day capacity (for a 150,000 barrel per day unit).2
Small crude oil distillation units owned by small refiners were in a
different situation in 1978. Such units received an outright subsidy from the
federal government via the "entitlements" system. The amounts of the subsidy
were:3
Company Refining Capacity Subsidy
(thousand barrels per day) (cents per barrel)
below 10 96
10 - 30 53
30 - 50 28
50 - 100 9
This study assumed that the subsidy would be negligible by 1984.
C.l.d Adjustments for size and age of process units. All else equal,
a small process unit would cost more to build, per barrel of capacity, than a
large unit. It follows that, if they were to be economical to build, small
units must also have generated more cash flow per barrel than large ones. But
this logic was overlooked here. Rather, all units of a given process, regard-
less of size, were assumed to generate the same annual cash flow per barrel of
capacity. This assumption may have understated the value of small units. But
1 Oil and Gas Journal, June 12, 1978, p. 40.
2 Capital cost about sixty million dollars.
3 Oil and Gas Journal, May 9, 1979, p. 48.
-------
VI-8
it seemed better to risk overstating the impact of revised guidelines (by
understating the value of affected refineries) than to risk understating
them.
All else equal, an old process unit was less valuable than a new one of
the same size and capability, both because a new unit was expected to generate
cash for more years than an old one, and because a new unit should have costed
less to maintain.
It was difficult to judge the remaining life of a process unit. For
example, there were more than a dozen catalytic cracking units that were first
built in 1944 and 1945 that had been so thoroughly rebuilt and modernized
that they were almost as efficient as brand new units, despite 33 years of
operation. Nevertheless, it was appropriate to recognize old units are not as
valuable as new ones. A useful way to account for this lower value was to
utilize lower values for the annual cash flow estimates that were tabulated in
Sections C.I.a and b. above. A reasonable factor is one-half. That is, the
average annual cash flow expected from an "old" unit over the next, say, thirty
years was one-half that expected from a new unit.^
From the above and, for convenience, averaging the costs of processes of
nearly equal value, the following estimates were used for computing the value
of an existing refinery:
1 This is equivalent to estimating that the old unit will last for six
years and the new unit for thirty: The present value of an annuity of $1 per
year for 6 years at 12 percent per year is $4.3. The present value of an
annuity of $1 per year for 30 years at 12 percent per year is $8.5.
-------
VI-9
Process Expected Annual Cash Flow,
($/barrel/day capacity)
Lubricating oil 600
Alkylation 300
Hydrocracking 300
Catalytic reforming
(including naphtha
desulfurizatlon) 250
Catalytic cracking 250
Delayed coking 200
Thermal cracking 150
Crude oil distillation 10
C.l.e Asphalt manufacture. This process was not Included in the
above table, because in contrast to other refinery processes, the value of
most asphalt manufacturing facilities was determined predominantly by the level
and relative location of roadbuilding activity. If roadbuilding activity was
strong.(so that the asphalt plant is operating near capacity) and located
nearby (so that the plant has a shipping cost advantage over its competitors)
the plant generated a high cash flow. On the other hand, sporadic roadbuild-
ing activity located well away from the plant might have led to essentially no
cash flow.
For these reasons, the asphalt refinery listed in Exhibit VI. 1 was evalu-
ated on the basis of implied roadbuilding activities rather than on process
unit value.
C.2 Guidelines Cost Versus Refinery Value. In Exhibit VI.2, the values
and revised guidelines compliance costs for the 26 non-asphalt refineries
listed in Exhibit 7 were compared. Costs and values were stated on an annual
basis. Compliance costs are from Exhibit IV.1; values were computed by multi-
plying process unit capacities reported by the refineries in their replies to
the "Section 308 Questionnaire" times the estimated annual per-barrel cash
flows tabulated in Section C.l.d. above.
-------
VI-10
Exhibit VI.2 has shown that nineteen refineries had expected cash flows from
their process units that were substantially greater than the cash flows required
to meet revised guidelines. These plants clearly would have been willing to
conform to revised guidelines in order to preserve their cash flow. The remain-
ing seven (non-asphalt) refineries had Level 2 or Option 2 compliance costs
greater than their process unit values. All of these refineries were of "top-
ping" configuration.
C.3 Evaluation of High Cost Refineries. The seven topping refineries
are discussed individually in order of refinery code number. Then the asphalt
refinery is discussed.
C.3.a Refinery 110 was located in Michigan about 125 miles north-
west of Detroit. This plant faced revised guideline costs (indirect, Option
2) of six cents per barrel crude oil processed, compared to an estimated pro-
cess unit value of six cents per barrel.
Refinery 110 began operating before 1970.* The plant sold one-tenth of
its 1976 output as gasoline, and one-quarter as military jet fuel.2 The
principal competition for gasoline and fuel oil sales comes from a forty thou-
sand barrel-per-day cracking refinery located about fifteen miles away.
It appeared that the future of Refinery 110 was independent of revised
guideline costs. If a small refiner subsidy had been maintained, even at a low
level, this plant most probably would have been willing to incur revised guide-
line costs and keep operating. But, without such a benefit, the refinery had
little or no value and might have chosen to shut down. (However, the plant
operated in the early 1970s without subsidy.) Revised guideline costs did not
appear to be large enough to significantly influence the decision of whether
or not to shut down.
1 U.S. Bureau of Mines, Petroleum Refineries jLn the United States and
Puerto Rico, published annually.
2 Reply to Section 308 questionnaire.
-------
VI-11
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VI-13
C.3.b Refinery 128 was located in Northeastern Montana. This plant
faced revised guideline costs (indirect, Option 2) of ten cents per barrel
crude oil processed, compared to an estimated process unit value of six cents
per barrel.
Refinery 128 began operation before 1970. It changed ownership in 1977*
and the new owners Increased capacity from 3,000 to 4,500 barrels per day
during 1978.2 During 1976, forty percent of the refinery's outturn was military
jet fuel. No gasoline was manufactured.3 Principal competition for residual
fuel oil sales came from another small refinery located about 100 miles east;
jet fuel, diesel fuel, and distillate fuel oil competition also arises from a
pipeline terminal located about 100 miles south.
This plant was located in a crude oil producing area. The local crude oil
gave high yields of jet and diesel fuels. Operations associated with
crude oil production and transportation consumed diesel fuel.
It was concluded that this refinery was viable without subsidy. And its
strong location, adjacent to both its crude oil supply and markets, made it
probable that the owners would have been willing to absorb guideline conform-
ance costs and to continue operations. It was also possible that they might
have persuaded their crude oil suppliers to share some of the costs.
C.3.c Refiner 145 was located in Southwest North Dakota. It faced
revised guideline costs (indirect, Option 2) of seven cents per barrel of crude
oil processed, compared to an estimated process unit value of six cents per
barrel.
Refinery 145 began operations in 1974, after the small refiner subsidy
program went into effect. The plant processed crude oil produced nearby. It
1 Bureau of Mines/Department of Energy, Petroleum Refineries, op. cit.
2 Oil and Gas Journal, March 26, 1979, p. 129.
3 Reply to Section 308 Questionnaire.
-------
VI-14
manufactured no gasoline or jet fuel In 1976. Principal competition came
from a fifty thousand barrel-per-day refinery located about eighty miles east,
and from a products pipeline terminal located about ninety miles northwest.
Because of its location, Refinery 145 appeared to be viable as a diesel
fuel and fuel oil manufacturer without federal subsidy or tariff protection.
It would probably not have been economic to build without subsidy. But, once
built, its transportation cost advantage relative to its competition should
have enabled it to continue in business. Revised guideline costs did not ap-
pear to be high enough to jeopardize its viability.
C.3.d Refinery 193 was located in the Houston, Texas, metropolitan
area. It faced revised guideline costs (indirect, Option 2) of eleven cents
per barrel crude oil processed, compared to an estimated process unit value of
six cents per barrel.
This refinery began operations before 1970. It expanded by about fifty
percent after the small refiner subsidy program went into effect. The plant
reported an outturn of fifty percent gasoline in 1976. Since it had neither
cracking nor reforming facilities, it was assumed that much of the gasoline,
perhaps as much as two-thirds, was high-octane blending stocks purchased from
nearby refineries. Competition arose from these same refineries; over one
million barrels per day of refining capacity was located within thirty miles of
Refinery 193.
The estimated conformance costs for this plant included no provision for
land. It was understood informally that the plant had such severe space re-
strictions that the installation of a water treatment facility that required
any significant land area could be accomplished only by removing some existing
tankage or by purchasing expensive adjacent land. If this information was cor-
rect, Refinery 193 was facing higher conformance costs than eleven cents per
barrel.
-------
VI-15
It was not possible to estimate the actual cost for this plant without
engineering and real estate data. However, it appeared that this refinery
might have chosen to shut down rather than incur revised guideline costs.
C.S.e Refinery 195 was located near San Antonio, Texas. It faced
revised guideline costs (indirect, Option 2) of 36 cents per barrel of crude
oil processed, compared to an estimated process unit value of six cents per
barrel.
Refinery 195 began operations before 1970. The plant manufactured no
gasoline or jet fuel in 1976. Principal competition came from two small
nearby refineries, and from five nearby pipeline terminals that distributed
products refined along the Texas Gulf Coast.
Refinery 195 and its neighbors appeared to have a significant transporta-
tion advantage compared to their competitors. Texas crude oil flowed past San
Antonio on its way east to Gulf Coast refineries and products flowed back west
to San Antonio. However, it seemed doubtful that the advantage was enough to
compensate for the high revised-guideline costs.
It was concluded that Refinery 195 would have incurred revised-guideline
costs only if federal subsidies to small refiners continued at fairly high
levels. Without subsidy, revised guidelines costs apparently would have caused
it to choose to shut down.
C.3.f Refinery 231 was located near Salt Lake City, Utah. It faced
revised guideline costs (indirect, Option 2) of twenty cents per barrel crude
oil processed, compared to an estimated process unit value of six cents per
barrel.
This plant began operations in 1973, and expanded from one thousand to
ten thousand barrels per day capacity in 1974, after the small refiner subsidy
program went into effect. Forty percent of outturn in 1976 was motor gasoline.
As was the case for Refinery 193, it could be assumed that much of this product
-------
VI-16
was high octane blending components procured from one or more of six nearby
refineries. These plants were equipped with catalytic cracking and catalytic
reforming. Competition for Refinery 231 arose from these same plants.
It appeared that Refinery 231 was an "entitlements refinery," i.e., its
existence was dependent on federal subsidy.1 It was likely that this plant's
outturn could have been more economically supplied by minor expansion of one
or more of the nearby refineries. If this analysis was correct, the refinery's
future was determined by federal subsidy policies rather than revised guide-
lines.
However, even if the refinery was competively viable without subsidy,
revised guideline costs probably would have caused it to shut down. Revised
guideline costs faced by every neighboring refinery were less than four cents
per barrel.^ The revised guideline cost disadvantage of over one-half million
dollars per year,3 and the capital requirement of 1.1 million dollars4 appeared
to be too large to face.
C.3.g Refinery 266 was located in Southwestern Michigan, roughly
equidistant from Chicago, Detroit, and Toledo, where the nearest refineries
were located. This plant faced revised guideline costs (direct, Level 2) of
six cents per barrel crude oil processed, compared to an estimated process unit
value of six cents per barrel. In 1976 the plant processed mostly Canadian
crude oil (transported in the nearby lakehead pipeline) and some local crude
oil.5
1 However, it must be noted that Refinery 193 in Houston has even less
reason to exist, but has been in business for over a decade.
2 Exhibits IV.1: Refinery 288.
3 (0.2 - 0.035 cents/barrel) x (10,000 barrels/day capacity) x (0.9 utili-
zation factor) x (365 days/year) « $0.54 million/year.
4 Exhibit VI.1.
5 Reply to Section 308 questionnaire.
-------
VI-17
Refinery 266 began operation before 1970. It expanded to its 1978 capac-
ity, 5,600 barrels per day, during 1974. Refinery 266 manufactured military
jet fuel, fuel oils, and a small quantity of leaded motor gasoline.1 Principal
competition was from two pipeline terminals, each located about fifty miles
away.
The area around Refinery 266 was well populated and industrialized. It
appeared that all of the plant's output was delivered within a radius of twenty
or thirty miles. The refinery appeared to have a significant transportation
cost advantage over other refineries, perhaps twenty cents per barrel of pro-
duct. This would have been true regardless of the level of federal protection
against imports. So the revised guideline cost was not enough to cause this
refinery to cease operation.
C.3.h In summary, the impact of revised guidelines on topping re-
fineries would have depended strongly on the future level of federal subsidies
for small refiners. The subsidy level in 1978 for firms processing less than
ten thousand barrels per day was about 95 cents per barrel crude oil processed.
If the subsidy had continued at even a fraction (one-third?) of this level,
revised guideline costs probably would not have caused any refineries to shut
down.
If, however, the small refiner subsidy was eliminated, it was anticipated
that the following topping refineries might choose to shut down rather than
incur revised Option 2 PSES costs. (They would not have been affected by
Level 1, Level 2, or Option 1 revised guideline costs.)
Refinery
Code Capacity Located Near
(thousand barrels per day)
193 3.2 Houston
195 1. San Antonio
231 10.2 Salt Lake City
Total 14.2
1 Ibid.
-------
VI-18
C.3.1 The asphalt refiner, Code 52, was located at the east end of
the panhandle of Florida. It faced revised guideline costs (direct, Level 2)
of six cents per barrel crude oil processed.
Refinery 52 began operation before 1970 and increased its capacity from
3,000 barrels per day in 1970 to 5,000 barrels per day by 1974 and to 9,000
barrels per day by 1979. Almost half of 1976 product outturn was asphalt.
Some military jet fuel was also manufactured, but no gasoline. Imported
Venezuelan crude oil accounted for all raw material requirements.
Because Refiner 52 was located on the Gulf of Mexico, it faced competi-
tion from all other Gulf Coast asphalt manufacturers. And when U.S. refiners'
crude oil acquisition costs were allowed to equalize with offshore refiners'
costs, this plant would again face competition from Caribbean refiners, as it
did before the OPEC price increase of late 1973. However, it was important to
point out that finished asphalt was much more expensive to ship and to store
than asphaltic crude oil. So relatively short distances created significant
transportation/storage cost advantage in the asphalt manufacturing industry.
It seemed highly unlikely that Refiner 52 would have been unwilling to
incur revised guideline costs. The costs were moderate, the refinery appeared
to be well located, and it had sufficient confidence to triple its capacity over
the last eight years.
D. Summary of Economic Impacts of Revised Guidelines on Existing Plants
D.I The analysis indicated that no petroleum refineries were likely to be
shut down under the Level I/Option 1 guidelines. It also identified three
small petroleum refiners that, in the absence of a small refiner subsidy,
might have elected to shut down rather than to incur revised Option 2 PSES
costs. However, if a small refiner subsidy was continued they would have
probably incurred the costs and continued operations.
-------
VI-19
These refineries accounted for one-thousandth, i.e., 0.1 percent, of total
industry capacity. Industry output would not have been affected if they shut
down.
D.2 Employment Effects. Under Level I/Option 1 there would have been
no employment effects because no petroleum refineries were likely to shut
down. It was estimated that 100 to 150 persons were employed in the three
small refineries that may have shut down under the Option 2 guidelines.
New jobs would be created by revised guidelines in existing refineries.
The new effluent treatment facilities would need to be operated, maintained,
and supervised. It appeared that about 50 to 850 jobs would have been created.1
A net increase of 50 (Level I/Option 1) to 725 (Level 2/Option 2, net of three
shut down refineries) was expected.
D.3 Community Effects. The three refineries that may have shut down
were all small employers located in or near metropolitan areas. Hence, no
community impacts were expected if the plants did shut down.
D.4 Balance of Trade Effects. No balance of trade effects of revised
guidelines were expected.
E. Impacts on New Plants
With no tariff protection compliance costs for new sources (NSPS and PSNS)
would have to be absorbed by new sources. However, the magnitude of compliance
costs would have negligible impact on the economic viability of new plants.
1 Chapter V, Section D.
-------
Chapter VII
LIMITATIONS OF THE ANALYSIS
There are two principal limitations to the analysis presented in this
report, the cost data, and the necessity of assuming future federal govern-
ment policy for protecting domestic refineries.
The estimated costs of conforming refineries to revised guidelines were
based on a survey that was conducted in 1976. Twenty-one refineries did not
respond to the survey, and several refineries might have altered their actual
or planned effluent treatment and flow since then, as well as their size and
configuration.
Estimated costs for conforming directly-discharging refineries to revised
BAT guidelines, and indirectly-discharging refineries to Option 2 pretreatment
guidelines, were based on a flow model. The flow model was derived by statis-
tical analysis of a nonhomogeneous universe: two different types of refineries
were subjected to a single analysis: those that complied with existing BPT
regulations and those that did not. Moreover, the resulting model stated
that the following important refining processes discharge no effluent water at
all: catalytic reforming, alkylation, delayed coking, fluid coking, and hydro-
desulfurization. Finally, it was assumed by Effluent Guidelines Division
that land costs were negligible for all refineries. This probably is not the
case.
If costs to conform were increased by twenty percent, the number of re-
fineries with compliance costs greater than 4.1 cents per barrel crude oil
processed (Exhibit VI.1) would have increased from 22 to 40. And the number of
(non-asphalt) refineries with compliance costs greater than process unit values
(Exhibit VI.2) would have increased from five to eight. Two of the added three
refineries had already been analyzed in detail because compliance costs and
process unit values were equal. The third - Refiner 130 - was quite well
located and appeared to enjoy a significant transportation advantage relative
to its competition.
-------
VI1-2
At the time this study was made, it was not possible to foresee the dramatic
changes that eventually took place in the world and the U.S. petroleum market
places. Large price increases significantly reduced consumption. In January
1981, all U.S. petroleum price controls were removed, small refiner subsidies
were rescinded and the U.S. industry was given essentially no tariff protection.
U.S refining utilization decreased from 89.4 percent of capacity in 1977 to
below 70 percent in 1981. Currently (July 1982), the utilization rates is about
71 percent. More than fifty U.S. refineries have discontinued operations since
decontrol. Except for modifications in refineries to change output states and
to enhance their capabilities to process low valued crude oils, little new pro-
cess capability is under construction.
If the economic impact analysis were redone in the context of the current
economic environment, some changes would be noted. But the impacts on the
existing industry would be small. Except as noted above, there currently is
essentially no construction of new refining facilities. Consequently, BAT and
PSES compliance costs would have to be absorbed by existing refineries.
These costs were generally small compared to the capital values of most
existing plants. (The methodology and results of the capital values for exist-
ing refineries that were computed in this study are still valid. At that time,
crude distillation capacity was assigned little capital value. But most refin-
ing downstream processing capability was quite valuable.) This study determined
that only three U.S. plants might experience compliance costs that exceeded
residual capital values and thus might discontinue operations. All of these
were simple refineries not equipped with much downstream processing capability.
Of the fifty or so U.S. plants that have shutdown since decontrol, by far the
largest number are plants of this type. It is quite likely that the three
plants identified as candidates for closure as a result of PSES rules, have
already discontinued operations for economic reasons other than PSES compliance
costs.
-------
Appendix A
PETROLEUM REFINING PROCESSES AND THE REFINING INDUSTRY
A. Types of Refineries
Crude oils, the primary raw material used in refining, are liquid mixtures
of many hydrocarbon-containing chemical compounds. Crude oils differ from one
another in the relative concentrations of the various compounds. The physical
characteristics of a given crude oil can range from an almost colorless liquid
similar to gasoline to a dark viscous material Which must be heated to be
pumped. Crude oils also contain varying concentrations of nonhydrocarbons,
including compounds of sulfur, nitrogen, oxygen and heavy metals. These com-
pounds create problems in the refining process and with product contamination.
Sulfur is of principal concern because sulfur compounds can cause severe corro-
sion to refinery equipment and can be a major source of air pollution.
The purpose of an oil refinery is to process crude oil into various refined
fractions and blend those components into the desired finished products. Al-
though a typical oil refinery is technically complex, the manufacturing process
is conceptually simple. A refinery consists of a number of modules or units
integrated into a processing sequence. Each unit contains equipment to perform
a refining or petrochemical operation on crude oil, or on a fraction of the
crude, or on a similar substance derived from natural gas. These operations
include: separation by fractionation; conversion by chemical reaction, often in
the presence of a catalyst, to higher valued products; product treating; and
auxiliary support facilities for such purposes as utility generation, pollution
control, and storage. The actual processing configuration will depend on the
characteristics of the crude oil processed and on the desired final product
mix. Exhibits A.I through A.4 show flow charts and product yields of increas-
ingly complex refinery configurations processing a typical light, low sulfur
crude.
The configurations are chosen to show that gasoline yield can be increased
from zero to at least seventy percent of crude oil processed. Process
-------
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A-6
units are successively added to the simplest possible "topping" configuration
(Exhibit A.I) as follows:
o Exhibit A. 2 (hydroskimming configuration): Catalytic reforming is
added to upgrade naphtha from military jet fuel and/or petrochemical
feedstock to gasoline.
o Exhibit A.3 (fuels configuration): Catalytic cracking is added to
convert about one-half of the Exhibit A.2 residual fuel oil outturn
to gasoline. A further fraction of residual fuel oil is converted in
catalytic cracking to olefins (propylene and butylenes). These com-
pounds are reacted (alkylated) with isobutane (partly derived from
refinery processing and partly purchased from the natural gas process-
ing industry) to make additional gasoline.
o Exhibit A.4 (high conversion configuration): More catalytic cracking
and alkylation are added. This increment converts about half of dis-
tillate fuel oil to gasoline. Also, coking is added to convert remain-
ing residual fuel oil to coke and (mostly) catalytic cracking feedstock.
And catalytic, reforming is expanded to accommodate naphtha from coking.
This configuration represents a practical maximum of gasoline manu-
facture. Additional increments are feasible, but uneconomic except in
unusual cases.
In addition to configuration, oil refineries can be categorized by size,
product mix and type of feedstock which can be processed (high or low sulfur).
Exhibit A.5 shows the distribution of U.S. refineries by size and configuration
as of January 1, 1982. Refineries with capacity over 120,000 barrels per day
account for nearly 60 percent of total U.S. refinery capacity. However, only
44 plants (16 percent) of the total 273 plants are in this size group. The
large number of small refineries is comprised of two groups: those located
near isolated producing areas or small markets far from alternate product
sources; and those which have been built in recent years in response to the
government's small refinery subsidy programs and still continue to operate.
During 1981 roughly 50 refineries, mainly small inefficient plants, discon-
tinued operations.
-------
A-7
Exhibit A.5
U.S. REFINERY CRUDE DISTILLATION CAPACITY AND OPERATIONAL ABILITY MATRIX
(number of plants in each category and
their combined crude distillation capacity)
CRUDE DISTILLATION
CAPACITY
(barrels per
stream day)
SIZE 1
(0 - 20,000)
SIZE 2
(20,0001 -
50,000)
SIZE 3
(50,001 -
120,000)
SIZE 4
(120,001 -
250,000)
SIZE 5
(250,001+)
TOTALS
OPERATIONAL ABILITY*
A
Topping
I/
63 plants
(599,830)
V - 44%
H - 59%
T - 3%
23 plants
(692,485)
V - 50%
H - 271
T - 4%
1 plant
(80,000)
V - 67.
H - 2*
T - 0.41
85 PLANTS
(1,372,315)
V - 100Z
H - 7%
T - 7%
B
Hydro-
Skimming
21
26 plants
(255,051)
V - 32%
H - 25%
T - 1Z
11 plants
(369,205)
V - 46*
H - 14Z
T - 2%
3 plants
(183,526)
V - 232
H - 4%
T - 1Z
40 PLANTS
(807,782)
V - 100%
H - 4Z
T - 4Z
C
Medium
Conversion
3/
11 plants
(124,760)
V - 1%
H - 12Z
T - 0.7Z
32 plants
(1,177,342)
V - 13Z
H - 46Z
T - 6%
32 plants
(2,419,693)
V - 27Z
H - 57%
T - 13Z
12 plants
(1,971,142)
V - 22%
H - 44%
T - 11%
9 plants
(3,219,948)
V - 36%
H - 51%
T - 17%
96 PLANTS
(8,912,885)
V - 100%
H - 48%
T - 48%
D
High
Conversion
4/
2 plants
(37,814)
V - 1Z
H - 4%
T - 0.2%
9 plants
(317,447)
V - 4%
H - 12Z
T - 2Z
18 plants
(1,572,323)
V - 21%
H - 37%
T - 8%
15 plants
(2,510,537)
V - 33%
H - 56%
T - 13%
8 plants
(3,074.684)
V - 41%
H - 49%
T - 17%
52 PLANTS
(7,512,805)
V - 100%
H - 40%
T - 40%
TOTALS
102 PLANTS
(1,017,455)
V - 5%
H - 100%
T - 5%
73 PLANTS
(2,556,479)
V - 14Z
H - 100%
T - 14%
54 PLANTS
(4,255,542)
V » 23%
H - 100%
T - 23%
27 PLANTS
(4,481,679)
V - 24%
H - 100%
T - 24%
17 PLANTS
(6,294.632)
V - 34%
H - 100%
T - 34%
273 PLANTS
(18.605,787)
V - 100%
H - 100%
T - 100%
II Topping (no further processing)
21 Hydroskimming (Category 1 plus reforming but no conversion)
2/ Medium conversion (Category 2 plus cracking or coking)
kj High conversion (Category 2 plus cracking and coking)
Within each category, three capacity percentages are given:
V » capacity as percent of total vertical column (operation category)
H « capacity as percent of total horizontal column (size category)
T » capacity as percent of total U.S. refinery crude distillation capacity
SOURCE: Oil and Gas Journal, March 22, 1982
-------
A-8
The total sulfur content and hydrogen sulfide contained in the crude oil
are important determinants of the configuration of a refinery, the equipment
metallurgy and the size of the pollution control units needed to control sulfur
emissions. In comparing high and low sulfur refineries, the major difference is
that the distillate fractions of the high sulfur refineries must be desulfurized
prior to blending or further processing. For plants of equal total crude pro-
cessing capacity, high sulfur refineries will require more capacity in such
units as hydrotreating, sour water strippers, acid gas treating plants, sulfur
recovery plants and tail gas treating units.
The categorization of U.S. plants in Exhibit A.5 does not reflect dif-
ferences in sulfur content of crude oils processed. Within most of the size and
operational-ability categories distinguished in the exhibit, there are refine-
ries that process exclusively low-sulfur crudes and refineries that process
essentially all high-sulfur crudes. But most U.S. refineries process a mix
of both low-sulfur and high-sulfur crude oils, so it is difficult to quantify
feedstock differences as a useful parameter for categorization.
B. Location of Refineries
As of January 1, 1982, there were 273 refineries in the United States
located in 41 states. A large number, however, are concentrated in a few major
refining centers located along the California Coast, the Gulf Coast, the East
Coast, the Washington Coast and the Chicago area.
Exhibit A.6 provides a summary of the geographic distribution of domestic
refineries. Approximately 37 percent of all refineries are located in six
major refining centers. Refineries in these areas tend to be large complex
facilities with a full complement of downstream processing facilities. These
six refining areas provide approximately 64 percent of total crude distillation
capacity and 67 percent of cracking capacity.
-------
Location
Chicago Area
Washingto
All Other
TOTAL
A-9
Exhibit A. 6
GEOGRAPHIC DISTRIBUTION OF REFINERIES AND
as of January 1, 1982
Number of
Refineries
Coast 34
lulf Coast 21
Coast 27
, Philadelphia, Delaware 8
ea 5
Coast 7
171
REFINING CAPACITY
Distillation
Capacity
(thousand barrels
4,457
2,679
2,327
1,194
842
412
6,690
Cracking
Capacity*
per day)
1,501
968
877
465
348
141
2,122
273
1J8,601
6,422
* Includes catalytic cracking, hydroeraeking and coking.
SOURCE: Oil and Gas Journal, March 22, 1982.
-------
A-10
For the most part, the major refinery centers are located in highly indus-
trialized areas with numerous air emission sources. Many of the large refine-
ries, particularly those along the Gulf Coast, are integrated with or adjacent
to petrochemical and chemical plants which rely on the refineries for feedstock.
Some major utilities are located near refineries; fuel and utilities are ex-
changed between nearby plants.
C. Financial Structure of the Industry
It is difficult to analyze the financial structure of the petroleum re-
fining industry using published data. Most major refining firms are part of
larger enterprises which are not exclusively, or even primarily, in the re-
fining business. Many of the smaller firms are privately held. Those for
which published refining profitability data are available are not typical of
the industry.
While profitability of the business as a whole has been subject to some
variability, industry earnings have been adequate to attract capital to finance
growth and replacement. In recent years about 80 percent of capital require-
ments of the industries have been met from internal sources. Record profits
resulting from rising oil and gas prices have greatly increased resources
available to the industry. But U.S. refineries were operating at about 65
percent of capacity in early 1982, a lower capacity utilization level than
ever before. At these operating levels, refineries by themselves are not
profitable. Several large and small plants have closed recently or have an-
nounced plans to do so.
Uncertainties about future product demand make it impractical to provide
a detailed estimate of the refining industry's capital requirements for expan-
sion and modernization for the years to come. A review of spending plans
for 1982 however, provides some insight into the industry's capital require-
ments. In 1982 the U.S. petroleum industry plans to spend a record 95.3 billion
dollars in domestic activities, and 32 of these U.S. firms plan to spend another
-------
A-ll
16 billion dollars outside the U.S.* About 10 percent of the domestic capital
expenditures, roughly 9 to 10 billion dollars, represent planned investments in
refineries and chemical plants. A large portion of these expenditures are to
maintain the productive capacity of existing plants as they age, and much of
the rest will be used to change the mix of products made or to adjust the
industry's capacity to produce a mix of feedstocks that is gradually becoming
more difficult to process. Essentially no capital is being spent to increase
the industry's total capacity to process raw materials. By far the largest
portion of the industry's total capital expenditures, about 70 percent, is
budgeted for exploration and production.
Refinery employment as a whole has been fairly stable. In 1980 there were
approximately 154,000 employees; in 1975, about 153,000; and in 1970, 154,000.
About one-third of the people in the industry are skilled workers whose job
opportunities at a comparable skill level are dependent on employment in the
"process" industries. The other two-thirds are employable in other industries
at their present skill levels if job opportunities exist for them.
D. Refining Industry Growth
There are a number of factors which will have significant impacts on the
future of the domestic refining industry. The dramatic rise in crude oil prices
following the political disruptions in Iran has reduced the level of petroleum
demand worldwide from 1977 to 1982. Decontrol of U.S. crude and petroleum
products in early 1981 has increased the prices of oil products in the U.S.
and opened the domestic market to competition from foreign refineries. Finally,
the average world supply of crude oil will become heavier and higher in sulfur
content.
1 Oil and Gas Journal, Feb. 15, 1982, p. 59.
-------
A-12
These changes will tend to reshape the refining industry. Refinery
crude oil runs will be lower than previously projected because of declining
demand. At the same time, downstream processing will increase to keep pace
with changing demand patterns: total gasoline demand will decline but demand
for unleaded gasoline will increase; high quality middle distillate demand
(jet and diesel fuel) and certain petrochemical demands will increase; residual
fuel demand will decline at a greater rate than other products. While trying
to adapt to these changes, refiners will be faced with heavier and higher
sulfur crudes.
As a result of these changes refiners will be forced to shut down crude
distillation facilities. The refining industry will not require the construc-
tion of additional new grassroots plants over the next decade but will still
require downstream process expansion. U.S. refinery crude oil runs are pro-
jected to increase from current depressed levels (less than twelve million
barrels per day) to the intake levels which prevailed in the late 1970s (about
fourteen million barrels per day) over the next decade. At the same time,
downstream processing will increase to keep pace with changing demand patterns
which result in the output of larger percentage yields of light products and
the need to process higher sulfur crudes. As a result, refiners will invest in
additional facilities for heavy oil conversion, desulfurization and sulfur
recovery.
Future processing requirements will be satisfied through modification of
existing plants. No new refineries are now being built in the U.S., nor are
any likely to be built over the next decade. Very few new refineries have been
built in the last decade (except for "entitlement" refineries). This trend
should continue due to industry economic considerations and general community
resistance toward new refining centers.
Refinery expansions will involve revamping existing equipment, replacing
old units with larger more efficient ones, and adding new facilities into the
existing flow scheme. Expansions will tend to be concentrated in the larger
more efficient refineries, particularly those in major refining centers.
-------
A-13
E. Types of Refining Processes
In refining, crude oil is first separated by molecular size into fractions,
each of which can be blended directly into final petroleum products or processed
further. In the downstream processing operations, the molecular size and struc-
ture of petroleum fractions are altered to conform to desired characteristics
of refined products. Exhibit A.7 classifies the various refinery processes
according to their principal functions. These major processing steps are
described briefly below.
Fluid catalytic cracking uses high temperature in the presence of a cata-
lyst to convert or "crack" heavier fractions into lighter products, primarily
gasoline and distillates. Feed is brought to process conditions (1000°F and 20
pounds per square inch pressure) and then mixed with a powdered catalyst in a
reaction vessel. In the reactor, the cracking process is completed and the
hydrocarbon products pass to a fractionating section for separation. Coke is
formed on the catalyst as a by-product of the cracking reaction. Coked catalyst
is transferred from the reactor to a regenerator vessel where air is injected
to burn the coke to CO and CC^. The regenerator flue gases are passed through
cyclones and, sometimes, electrostatic precipitators, to remove entrained
catalyst. They are then vented to the atmosphere or sent to a CO boiler where
carbon monoxide is burned to C02- The regenerated catalyst is returned to the
reactor.
Hydrotreating (also known as hydrodesulfurization) is a catalytic process
designed to remove sulfur, nitrogen and heavy metals from petroleum fractions.
Feed is heated to process temperature (650° to 750°F), mixed with hydrogen and
fed to a reactor containing a fixed bed of catalyst. The primary reactions
convert sulfur compounds in the feed to hydrogen sulfide (I^S) and the nitrogen
compounds to ammonia. The I^S and ammonia are separated from the desulfurized
product; the H2S is sent to sulfur recovery facilities.
Catalytic reforming is used to upgrade low-octane naphtha to produce
high-octane gasoline blending stocks. The flow pattern is similar to that of
-------
A-14
Exhibit A.7
FUNCTIONAL CHARACTERIZATION OF PETROLEUM REFINERY PROCESSES
SEPARATION
A. Separation on the Basis of Molecular
Weight
Distillation (atmospheric and
vacuum fractlonatlon of crude
oil, naphtha splitting,
depropanizing, stabilization)
Absorption (recovery of olefins
from catalytic cracked gas,
recovery of propane from natural
gas or hydrocracked gas)
Extraction (deasphalting of feed-
stock for lubricating oil manu-
facture or for catalytic
cracking)
B. Separation on Basis of Molecular
Structure
Extraction (recovery of benzene,
toluene and xylenes from catalytic
refornate, removal of aromatics
from lubricating oil feedstock)
Crystallization (dewaxing of lubri-
cating oils, recovery of para-
xylene from mixed xylenes)
ALTERATION (CONVERSION)
A. Conversion on the basis of Molecular
Weight
Thermal cracking
(visbreaklng, coking)
Catalytic cracking
Hydrocracking
Alkylation
Polymerization
B. Conversion on Basis of Molecular
Structure
Catalytic reforming (benzene, tol-
uene, and xylene manufacture; and
octane improvement)
Isomerization (normal butane to iso
for alkylation, normal pentane
and hexane to iso for octane
improvement)
TREATMENT TO REMOVE IMPURITIES
Hydrogen treatment (hydrotreating)
Caustic treatment (Herox, Bender)
Clay treatment (of lubricating oils)
Acid treatment
-------
A-15
hydrotreating except that several reactor vessels are used. The required
temperature is about 1000°F and pressure about 200 psi. Reforming catalysts
are readily poisoned by sulfur, nitrogen or heavy metals and therefore the
feed is normally hydrotreated before being charged to the reforming unit.
In hydrocracking the cracking reaction takes place in the presence of
hydrogen. The process produces high quality desulfurized gasolines and dis-
tillates from a wide variety of feedstocks. The process employs one or more
fixed bed reactors and is similar in flow to the hydrotreating process. Pro-
cess conditions are 800°F and 2000 psi. Like hydrotreating, hydrocracking
produces by-product l^S which is diverted to sulfur recovery.
Coking is another type of cracking which does not employ a catalyst or
hydrogen. The process is utilized to convert heavy fuel oils into light pro-
ducts and a solid residue (coke). Feed is brought to process conditions (900°F
and 50 psi) and fed to the coking vessel. Cracked products are routed to a
fractionation section. Coke accumulates in the vessel and is drilled out
about once every day. In one version of the coking process, fluid coking, a
portion of the coke is used for process fuel and the balance is removed as
small particles.
Acid gas treating and sulfur recovery units are used to recover hydro-
gen sulfide (H2&) from refinery gas streams and convert it to elemental sulfur.
Sour gas containing H2S is produced in a number of refinery units, particularly
cracking and hydrotreating. In the acid gas treating units, H2S is removed
from the fuel gas by absorbing it in an alkaline solution. This solution, in
turn, is heated and steam-stripped to remove the I^S which is sent to the
sulfur recovery unit. In the process, a portion of the H2S is burned to form
S02» This reacts with the remaining I^S to form sulfur and water. Sulfur
recovery is high but never 100 percent. The remaining sulfur is incinerated
and discharged to the atmosphere or removed by a tail gas treating unit.
The purpose of the tail gas treating unit is to convert any remaining
sulfur compounds from the sulfur recovery unit to elemental sulfur. There are
-------
A-16
several processes available, the most common of which are the Beavon and SCOT
processes. In both processes, sulfur compounds in the sulfur unit tail gas
are converted to H2S. The Beavon process converts l^S to sulfur through a
series of absorption and oxidation steps. The SCOT process concentrates the
H2S and returns it to the sulfur recovery facilities. In both processes,
the treated tail gas is virtually free of sulfur compounds when released to
the atmosphere.
-------
Appendix B
Cost per pound of pollutant removed
The exhibit below presents a summary of the cost per pound of pollutant
removed for each of the options considered. Note that the incremental
costs and loadings for existing dischargers are based on industry-wide
data, while the new source data is reported on a per plant basis. The
values are in dollars per pound of pollutant removed.
Cost per pound of pollutant
PETROLEUM REFINING
Control
Option
Proposed BAT1
Proposed BAT2
Revised BAT1 (BATS)
Revised BAT2 (BAT7)
PSES1A
PSES1B
PSNS
NSPS1
NSPS2
NSPS3
NSPS4
Annual
Cost
(000)
$ 7,730
48,703
25,000
37,000
5,180
32,300
195
284
284
3,875
3,875
Pounds
Removed
(per year)
73,000
114,000
75,000
112,000
90,000
333,000
90,000
807.5
807.5
1,552.9
1,146.5
($/pound removed)
$ 105.10
427.22
333.33
330.35
57.55
97.00
2.16
351.70
351.70
2,495.33
3,379.26
ftU.S. GOVERNMENT PRINTING OFFICE: 1982 381-082/331 1-3
-------
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