EPA-440/2-79-027
November 1979
ECONOMIC ANALYSIS OF
PROPOSED REVISED EFFLUENT
STANDARDS AND LIMITATIONS FOR
THE PETROLEUM
REFINING INDUSTRY
QUANTITY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Water Planning and Standards
Washington, D.C. 20460
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This document is available in limited quantities
through the U.S. Environmental Protection Agency,
Economic Analysis Staff (WH-586), 401 M Street, S.W.,
Washington, D.C. 20460, (202) 755-2484.
This document will subsequently be available
through the National Technical Information Service,
Springfield, Virginia 22151.
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50272 -101
REPORT DOCUMENTATION
PAGE
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 indusrty.
1. RETORT NO.
EPA 440/2-79-027
3. Recipient's Accession Ho.
4. Title end Subtitle
Economic Analysis of Proposed Revised Effluent Standards and
limitations for the Petroleum Refining Industry
7. Aythorfs)
9. Performing Organization Name and Address
12. Sponsoring Organization Nam* and Address
Office of Water Planning and Standards
U.S.EPA
Washington, DC 20460
MS 2 S 3 13 8W
5. Report Date
November 1979'
8. Performing Organization Rept No.
EPA 440/2-79-027 _
10. Project/Task/Work Unit No.
11. Contract(C) or Grant(G) No.
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PREFACE
This document is a contractor's study prepared for
the Office of Water Planning 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 Dev-
elopment 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 invest-
ment and operating costs associated with various control and
treatment technologies. The attached document supplements this
analysis by estimating the. broader economic effects which might
result from the application of various control methods and tech-
nologies. 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 Planning and Standards of EPA.
This report was submitted in fulfillment of Contract Nos.
68-01-3968, 68-01-4398, and 68-01-4886 by Sobotka & Company, Inc.
This report is being released and circulated at ap-
proximately the same time as publication in the Federal
Register of a notice of proposed rule making. The study is not
an official EPA publication. It will be considered along with
the information contained in the Development Document and any
comments received by EPA on either document before or during
final rule making proceedings necessary to establish final
regulations. Prior to final promulgation of regulations, the
accompanying study shall have standing in any EPA proceeding
or court proceeding only to the extent that it represents the
views of the the contractor who studied the subject industry.
It cannot be cited, referenced, or represented in any respect
in any such proceeding as a statement of EPA's views regarding
the petroleum refining industry.
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TABLE OF CONTENTS
Page
CHAPTER I Executive Summary 1
A. Introduction 1
B. Structure of the Industry 1
C. Methodology 3
D. Costs of Conforming to Revised
Existing and New Source Standards 3
E. Impact Analysis 4
1. Price Impacts 4
2. Financial Impacts 4
3. Production Impacts 5
4. Employment Impacts 5
5. Community Effects 6
6. Balance of Trade Effects 6
F. Limitations of the Analysis 6
CHAPTER II Structure of the Petroleum
Refining Industry 9
A. Principal Statistics of the Industry 9
B. Coverage of the Analysis 11
C. Economic and Financial
Structure of the Industry 13
1. Exogenous Economic Factors 13
2. Price Determination 15
3. Industry Segmentation 21
4. Financial Status of
Industry Segments 26
CHAPTER III Methodology 28
A. Price Analysis 28
B. Quantity Analysis 29
CHAPTER IV Costs of Conforming Petroleum Refineries
to Revised BATEA Guidelines, New Source
Performance Standards, Pretreatment
Guidelines, and Pretreatment Standards 31
A. Existing Sources 31
B. New Sources 35
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PAGE
CHAPTER V Economic Impact Analysis with
High Level of Protection Against
Petroleum Product Imports 52
A. Price Effects of Revised Guidelines 52
B. Financial Effects 53
C. Production Effects 54
D. Employment Effects 55
E. Community and Balance of Trade Effects 55
CHAPTER VI Economic Impact Analysis with
Low Level of Protection Against
Petroleum Product Imports 56
A. Price Effects 56
B. Financial Effects 56
C. Production Effects 57
1. Values of Existing Refineries 62
2. Guidelines Cost Versus
Refinery Value 67
3. Evaluation of High Cost Refineries 67
D. Summary of Economic Impacts
of Revised Guidelines 77
1. Production Effects 77
2. Employment Effects 78
3. Community Effects 78
4. Balance of Trade Effects 78
CHAPTER VII Limitations of the Analysis 79
A. Limitations 79
B. Sensitivity Analysis 80
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LIST OF EXHIBITS
Page
A. Summary of Costs of Conforming Petroleum
Refineries to Revised Effluent Discharge
Standards 7
B. Costs of Conforming a New Petroleum
Refinery to Revised Effluent Discharge
Standards 8
1. Summary of Responses to 1976 Petroleum
Refining Industry Section 308 Questionnai
re 12
2. Schematic Diagram of the Effect of
Product Import Tariffs on Consumption,
Domestic Manufacture and Imports
of Petroleum Products 22
3. Costs of Conforming Directly Discharging
Petroleum Refineries to
Revised BATEA Guidelines 36
4. Costs of Conforming Indirectly Discharging
Petroleum Refineries to Revised
Pretreatment Guidelines 46
5. Summary of Costs of Conforming
Petroleum Refineries to Revised Effluent
Discharge Guidelines 50
6. Costs of Conforming a New Petroleum Refinery
to Revised Effluent Discharge Guidelines 51
7. Existing Refineries With Annualized Costs
to Conform to Revised Guidelines of More Than
4.1 Cents per Barrel Crude Oil Processed 59
8. Comparison of Process Unit Values Versus
Cost to Conform to Revised Guidelines 68
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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 tech-
nology economically achievable" (BATEA) limitations and "pre-
treatment" standards for aqueous effluents discharged by existing
petroleum refineries, and revised new source standards for to-be-
built refineries. The standards and limitations will be issued
in accordance with Sections 301, 304, 306 and 307 of the Clean
Water Act. The purpose of this study is to analyze the economic
impacts that could result from the implementation of revised
limitations and standards.
This study is restricted to 212 U.S. refineries that
operated in 1976 and will discharge aqueous effluents in 1984
into receiving bodies or publicly/jointly owned treatment plants.
(Fifty refineries will discharge no effluent; twenty-one, in-
cluding eight known dischargers, did not respond to EPA's Section
308 Survey Questionnaire and are 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 about the size
and process unit configuration of each discharging refinery and
about the estimated capital and operating costs that may be
required to bring each refinery into conformance with revised
guidelines.
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2.
B. Structure of the Industry
The petroleum refining industry is currently subject
to a set of raw material and refined product price controls that
severely distorts competition. It is useful to assume that these
controls will have lapsed by 1984 when the revised guidelines
will become effective.
In the absence of price controls, the market for
refined petroleum products is competitive. Product prices are
determined by the marginal costs of the highest cost supply
needed to clear the market. The existing domestic industry has
insufficient capacity to clear the market (except at very high
prices). So prices are necessarily determined by either new
domestic capacity or imports (including any tariff or quota
costs).
For several reasons, e.g., preferentially-priced raw
materials and/or fuel, advantageous tax treatment, less severe
environmental requirements, 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 current size requires that some
protection be afforded against unrestricted competition from
imported products.
For the purpose of economic analysis it is useful
to segregate the industry on the basis of four characteristics:
1. Disposition of aqueous effluent. Refineries
discharge directly, indirectly to publicly or jointly owned
treatment plants, or not at all.
2. New or existing source of effluent.
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.
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3.
4. Geographical location. Because transporta-
tion is an important component 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.
C. Methodology
The price analysis, described below, was simple.
For the quantity analysis, 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 limitations exceeding 4.1 cents per barrel
of crude oil processed.! por 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 con-
siderable 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 infor-
mation about refinery process unit replacement costs, and raw
material and refined product transportation costs.
D. Costs of Conforming to Revised Existing
and New Source Standards
Costs of conforming existing refineries to revised
limitations will apparently range from zero to 42 cents per
barrel 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
barrel is 42 U.S. gallons.
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4.
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 A and B.
E. Impact Analysis
1. Price Impacts. It was discussed above that market-
clearing prices of petroleum products are determirled by either
the long-run cost of products manufactured in new capacity
or the short-run cost of imports plus tariff. Given a high
level of Federal protection against imports, product prices
would be higher due to revised new source standards by zero
to 0.15 cents per gallon. Given a low level of protection
prices will be determined by the costs of imports (including
tariff/quota costs). So revised guidelines would have no
price impact.
2. Financial Impacts. With a high level of Federal
protection, the financial effect for existing refineries of
revised new source standards and revised guidelines range
from a net cost to refiners of 81 million dollars per year
to a net benefit to refiners of 325 million dollars per year.
The range is because there are five possible new source stan-
dards that might be price-determining, and four combinations
of revised direct/indirect guidelines that may be imposed.
With a low level of Federal protection, and depending on which
combination of revised direct/indirect guidelines is imposed,
the costs to be absorbed by existing refineries 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. Alternatively, it is roughly one percent of
value added by refining.
Petroleum refineries face major business uncertainties
at the present time: The size of the "small refiner bias" in the
crude oil entitlements program is under review; price controls
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5.
on most products have been allowed to lapse, and further decon-
trol is under study; crude oil prices are being increased to
world levels by price decontrol; the long range level of pro-
tection against imports to be afforded U.S. refineries is unknown,
etc. Compared to the financial implications of these uncer-
tainties, the costs of conforming to revised guidelines are
inconsequential.
3. Production Impacts. Twenty-seven existing refineries
will face conformance costs exceeding 4.1 cents per barrel of
crude oil processed. With a high level of Federal protection
all of these are expected to be willing to undertake effluent
treating revisions and continue in operation. With a low level
of Federal protection, three refineries have been identified that
apparently are not worth the cost to conform them to revised
PSES Option 2 guidelines. These refineries account for only
0.1 percent of industry capacity. So their loss would have no
effect on overall industry outturn.
4. Employment Impacts. With a high level of Federal
protection, revised standards and limitations would lead to
roughly the following increases in industry employment:
New Jobs
Existing Direct Dischargers
BAT- Level 1
Level 2
40
600
Existing Indirect Dischargers
PSES- Option 1
Option 2
10
250
New Sources
NSPS - Level 1
Level 2
0
200
PSNS - Option 1
Option 2
No Discharge
20
1600
800
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6.
New employment could range from 50 to 2450 jobs, depending on
which combination of Level/Option is chosen for implementation.
With a low level of protection total industry employ-
ment would increase by about 50 people if Level 1 and Option 1
are implemented. If Level 2 and Option 2 are implemented in-
stead, employment in surviving refineries would increase by
about 850 jobs; but 100 to 150 jobs would be lost at the three
shut down refineries.
5. Community Effects. The three refineries that may
shut down are all small employers located in or near metro-
politan areas. Hence, no community impacts are expected if
the plants do shut down.
6. Balance of Trade Effects. There apparently will be
no balance of trade effects of revised guidelines.
F. Limitations of the Analysis
The analysis is based entirely on costs developed by
Effluent Guidelines 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.
There is no existing Federal policy for protecting
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 there is no such
actual policy. Nor is there any clear indication of what the
refinery protection policy will eventually be, or when it might
become effective.
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7.
EXHIBIT A
SUMMARY OF COSTS OP CONFORMING
PETROLEUM REFINERIES
TO REVISED EFFLUENT DISCHARGE STANDARDS
Crude Oil
Distillation
Capacity, Operating Annualized Costs
Thousand Capital Costs Cents per
Barrels Costs Thousand Thousand $ Barrel Crude
per Day Thousand $ per Year per Year Oil Processed
DIRECTLY DISCHARGING REFINERIES
14,142 19,281 3,678 7,730 0.2
14,142 112,956 24,985 48,703 1.0
INDIRECTLY DISCHARGING REFINERIES
PSES-
Option 1 2,402 9,591 3,163 5,175 0.7
Option 2 2,402 84,807 14,432 35,267 4.1
BAT-
Level 1
Level 2
According to the Development Document:
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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8.
EXHIBIT B
COSTS OF CONFORMING
A NEW PETROLEUM REFINERY1
TO REVISED EFFLUENT DISCHARGE STANDARDS
Capital
Cost
Thousand $
Operating
Cost
Thousand $
per Year
Annualized Cost
Thousand $
per Year
Cents per
Barrel Crude
Oil Processed
DIRECT DISCHARGE (NSPS) 2
Level 10 0
Level 2 75 218
0
234
0
0.4
INDIRECT DISCHARGE (PSNS} 3
Option 1 260 140
Option 2 5,800 2,230
195
3,450
0.3
5.5
NO AQUEOUS DISCHARGE 2
9,500 1,880
3,875
6.2
1 200,000 barrels per stream day capacity, equipped for high
conversion.
2 Costs are additional above current NSPS (BADT).
3 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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9.
CHAPTER II
STRUCTURE OF THE PETROLEUM REFINING INDUSTRY
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.2 The refineries had
a replacement value in excess of 40 billion dollars. The
industry employed about 160,000 persons in 1977^.
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 its major activity.
Refinery investment is less than 15 percent 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.^
And complexity (total refinery replacement value per barrel of
^-Petroleum Refineries in the United States and Puerto Rico,
January 1, 1978, U.S. Department of Energy, July 1978.
2lbid. (One hundred barrels is 42 U.S. gallons.)
-*Basic Petroleum Data Book, Petroleum Industry Statistics,
American Petroleum Institute, October 1975 et. seq.
41bid.
^Op. cit., U.S. Department of Energy.
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10.
crude oil distillation capacity) varies fifteen fold.^ Conse-
quently, the replacement value of refineries ranges from roughly
one million dollars to perhaps two thousand million 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 is anticipated that crude oil imports will
account for about forty-three percent of crude oil intake by U.S.
refineries in 1979, and product imports will account for about
ten percent of product consumption.3
Average wholesale prices for refined petroleum fuel
products in December 1978 were^:
Motor gasoline
Kerosene
Distillate fuel oil
Residual fuel oil
42 cents per gallon
3 9.5
3 8 " H H
25 " " "
-^-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
^Chase Manhattan Bank, The Petroleum Situation - February 1979
^Oil and Gas Journal, May 14, 1979, p. 86
4Chase Manhattan Bank, op.cit.
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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
Total domestic gasoline supplied was greater than gasoline
manufactured from crude oil. The difference, roughly ten
percent, was supplied predominantly by natural gas liquids.2
Also, natural gas processing 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 Lav; 95-217. A total of 299 question-
naires were issued; responses are summarized in Exhibit 1.
•!• Department of Energy, Crude Petroleum, Petroleum Products,
and Natural Gas Liquids: 1977, DOE/EIA - 0108/77, December 8, 1978
2lbid.
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12.
EXHIBIT 1
SUMMARY OF RESPONSES TO
197 6 PETROLEUM REFIMIMG INDUSTRY
SECTION 308 QUESTIONNAIRE
Forecast 1984
Waste Water
Discharge Mode
No waste water discharge
Direct discharge to
receiving body
Indirect discharge to
publicly or jointly
owned treatment plants
Facility not refinery
Refinery did not operate
in 1976
No response
Number of
Refineries
50
165
47
12
4
211
Reported 1976
Crude Oil Processing
Capacity, Thousand
Barrels per Day
846. 3
14,141.3
2,401.5
219.02
Total
299-
17,389.6
^-Includes nine v/ith known discharge modes -
6 indirect, 1 direct, 1 both direct and indirect, 1 zero.
^Estiraated
-^Includes all refineries reported by the Bureau of Mines
as existing in 1976.
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C. Economic and Financial Structure of the Industry
Revised effluent guidelines require compliance by
July 1, 1984. Consequently, the economic structure of the
industry in 1978 or 1979 is not necessarily relevant 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 will be the resultant of endogenous and ex-
ogenous influences on the current structure during the next
five years.
The current financial status of the industry is not
a good base from which to forecast the 1984 status because
current conditions will not exist in 1984. The industry is
currently subject to price controls and allocation rules for
both raw materials and some refined products. Product price
controls have been in effect since 1971, and crude oil price
controls and allocation rules since 1973/74. The controls work
in two directions. On the one hand, the costs of raw materials
to U.S refineries are lower than the costs faced by essentially
all of the rest of the free world's non-OPEC refiners. On the
other hand, product prices in the United States are controlled at
levels lower than in most of the rest of the world. The balance
of this Chapter will be devoted to developing a reasonable esti-
mate of the structure of the industry in 1984.
1. Exogenous Economic Factors. The legislation which
established crude oil and product price controls and allocations
is scheduled to lapse before 1984. Crude oil price controls
are now scheduled to be lifted by 1981. Several major product
classes, notably distillate fuel oil, have already been price
de-controlled. In fact motor gasoline is the only major product
still controlled. Based on the foregoing, it seems useful to
assume that the markets for crude oil and for refined petroleum
products in 1984 will not be subject to price controls.
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The quality of some refined products is forecast to
change over the next five years. The predominant change will
be in gasoline. By 1984, at lease three-fourths of motor gas-
oline will contain no lead anti-knock additive. In 1978 about
one-third of gasoline was unleaded.1 Additionally, the average
sulfur content of fuel oils will decrease steadily in response
to State Implementation Plans for sulfur oxide 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. refineries is likely 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 manufacturing refined petroleum products.
The structure of U.S. domestic demand will also change
by 1984.2 it has been widely forecast that, because of federally
mandated efficiency rules, domestic gasoline consumption will
reach a peak around 1980 and stay at that level for four to five
years before resuming growth. Conversely, the consumption of
distillate fuel oil is forecast to increase slowly rather than
to follow the pattern of gasoline. The manufacture of residual
fuel oil may grow even if consumption were to stagnate since
a large fraction of the present supply is imported.
As current natural gas price controls and allocations
lapse, energy consumed by refineries (except purchased elec-
tricity) will come to cost about the same per BTU, regardless
of its form. This is not now the case, because some refineries
are cost advantaged by being able to use as plant fuel natural
gas which was contracted several years ago at low prices, or
is price controlled.
-^-Hydrocarbon Processing, April 1979, p. 13.
^Projections of Energy Supply and Demand and Their Impacts,
Annual Report to Congress 1977, Volume II, Energy Information
Administration, April 1978, page 115.
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Outside the U.S., it is forecast that OPEC will con-
tinue as an effective cartel, maintaining crude oil prices at
the current real price or higher. Additionally, because all
OECD countries are reducing the allowable sulfur content of
fuel oils,-*- and low sulfur crude oil reserves account for only
about one-fifth of total free world reserves^, low sulfur crude
oils currently command premiums more than justified by the costs
of desulfurization. Consequently substantial construction of
fuel oil desulfurization facilities can be expected. It is
reasonable to forecast that the price difference between high
sulfur and low sulfur crude oils will eventually reach an equi-
librium which reflects the long run full cost of desulfurization.
That is, the difference between high sulfur and low sulfur crude
oil prices will be such that a refinery owner will be indifferent
between his two options - purchasing high priced lov; sulfur
crude oil, or purchasing low priced high sulfur crude oil and
installing desulfurization equipment.
There exists today a large worldwide excess of crude
oil distillation capacity.3 This surplus capacity means that
hiyh 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.
2. Price Determination. The petroleum refining industry
has been subject to product price controls since 1971. Before
that time the domestic market for wholesale oil products
•^0j 1 and Gas Journal, November 28, 1977, page 56
^International Petroleum Encyclopedia 1975, page 296
^Oil and Gas Journal, June 12, 1978, page 40
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16.
was competitive in the economists' meaning of the term.1 That
is, the price elasticity of demand facing individual firms was
high.
Despite a strong and continuing industry effort to
establish brand differentiation for retail consumers, the whole-
sale 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 business exists. Non-brand marketers maintain aggres-
sive 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.3 This indicates that the industry was highly
competitive and that refinery gate (wholesale) product prices
were based on short-run marginal costs. Because of this,
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^
^-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.
^So-called "unbranded" sales at retail by independent
oil companies, commercial sales direct to users and sales
to government aggregate to somewhat over 30 percent of total
gasoline sales.
^Stephen Sobotka & Company, The Impact of Costs Associated
With New Environmental Standards Upon the Petroleum Refining-
Industry, Council on Environmental Quality unnumbered contract,
November 23, 1971, p. 37.
4Short-run marginal costs always include raw materials,
purchased power and fuel, and chemicals. In some cases
labor and materials will also vary with output.
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Short-ran 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, capa-
city is the last to be brought into operation. So increased
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
sufficiently high that investment in new refining capacity
becomes attractive, that is, a desireable 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. The reason for this is that the new capacity neces-
sarily 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 investment.
The above reasoning applies to effluent water treating
costs faced by new refinery capacity, and also to other environ-
mental 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 is substantial unutilized crude oil distil-
lation capacity in the world today.1 Despite this spare capacity,
large new refineries are under construction or planned in several
F4iddle East petroleum exporting countries.2 From a world point-
of-view these refineries are economically unjustified. They
apparently are being constructed for strategic reasons^ and to
provide employment for nationals. Regardless of cause, the
effect of this construction is likely to be to perpetuate a
low utilization rate for world refineries, particularly those
in Europe.
It is currently less expensive to manufacture products
in U.S. refineries than in most foreign plants because of domes-
tic crude oil price controls. However, this crude oil price
advantage is to be phased out and U.S. crude oil is to be priced
at world prices. Therefore, by 1984 all refineries in the world
can be considered to have approximately identical crude oil
acquisition costs.
Note: Refineries controlled oy petroleuxn exporting
countries do not necessarily face the sarue
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
^Oil and Gas Journal, June 12, 1978, p. 40
^Ibid.
-*Crude oil exporting countries that own refineries have
more pricing freedom than do countries that are restricted
to selling crude oil at prices fixed by the cartel.
-------
tariff protection, a substantial portion
of world refining capacity could be
acquired by crude oil exporting countries
through use of preferential crude oil pricing.
The National Energy Plan implies, but does not
specifically state, that maintenance of a viable U.S. petroleum
refining industry is a part of the Plan. For example, the stra-
tegic petroleum reserve program is currently 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".1 These observations establish that it is
prudent to assume that a viable refining industry will be main-
tained in the United States.
The industry may require protection against imports
from oil exporting companies if it is to remain viable. Pro-
tection can take many forms: domestic crude oil price controls,
quotas on imported finished products, and tariffs on imported
finished products are all obvious methods of providing protection.
Each of the methods can be used to achieve a desired size for
the domestic industry. The balance of this report will be
written as if tariffs will be the method utilized to protect the
domestic industry. This is because product tariffs are the most
straightforward and easiest to understand protection method.
However, other alternatives are available and might, in practice,
be utilized.2
Ipil Daily, June 22, 1978.
^In practice, an import quota is likely to be most effective
if protection is desired against excessive product imports
from petroleum exporting countries.
-------
Of the possible levels of tariff that could be imposed,
four are of particular interest:
a. No tariff. In this case, industry capacity would
gradually decline if OPEC nations engage iri 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.I 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. Conse-
quently, in the absence of tariff protection, U.S. crude oil
prices would adjust to protect enough domestic refining capacity
to process all domestic production.
b. A tariff designed to iuaintain industry capacity
at approximately the current level. Such a tariff would lead
to attrition of the least efficient refineries that currently
exist in the U.S., offrset by "debottlenecking" expansion of
efficient existing refineries. The average differential oetween
product prices and crude oil acquisition costs resulting from
the tariff would probably be greater than the average differ-
ential experienced today. This observation is based on an FTC
analysis^ 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
U.S. average price differentials.
c. A tariff designed to encourage construction of
enough new domestic refinery capacity to equal the growth in
J-The most economic location for refining Alaskan North Slope
oil is Japan. However, legislation requires this oil to be
domestically refined.
^Federal Trade Commission, op. cit.
-------
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.
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 resid-
ual fuel oil than other products/ the tariff on residual fuel oil
would need to be higher than in the preceding case.
Of the four tariff levels just discussed, the second
(hold constant capacity) and the third (encourage refinery capa-
city growth equal to product consumption growth) are of interest.
The no tariff case seems to be inconsistent with U.S. energy pol-
icy. The highest tariff case (phase out residual imports) would
lead to substantial windfall profits for existing refineries and
does not seem to be necessary for strategic reasons.! Consequently
the economic impact analysis to be performed in this study will
include tariff level as a parameter to be evaluated at two levels.
The effects of differing tariff levels are depicted in Exhibit 2.
3. Industry Segmentation. The proper basis upon which to
segment the petroleum refining industry for an economic impact
analysis of effluent guidelines is the individual refinery,
including its raw material acquisition and wholesale product
shipping activities. There are several reasons for this
conclusion:
^Most residual fuel oil imports come from refineries located
in the Caribbean. In the event of an embargo these same refin-
eries would be available to process crude oil stored in the U.S.
Strategic Petroleum Reserve.
-------
EXHIBIT
Schematic Diagram of the Effect of Product Import
Tariffs on Consumption, Domestic
Manufacture and Imports of Petroleum Products
a)
o
•r\
PU
o
0
T)
o
»-<
PH
Supply
£—
0
Supply curve Segments
1. Refineries existing in 1978
2. Expansion of 1978 refineries
3. New refineries
U.S. Product Consumption
Consumption
Domestic Manufacture
Price of imported
products, includ-
ing tariff of:
2x C per gal.
x C per gal.
zero
Demand
Imports
—&
Tariff
H-t-
C EE
Zero
X
2x
OE
on
UU
OA
OB
OC
AE
BD
—
n;-
-------
a. Revised effluent guidelines will be established
for each individual refinery, not for refining companies, or
for subdivisions of refineries.
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 saine quality at that location. Conse-
quently/ a decision to abandon a refinery will disadvantage its
crude oil suppliers only by the amount of additional transpor-
tation expense they may have to incur to deliver the material
to a different location.
NOTE: If the locational disadvantage is
severe, it may be cheaper for crude
oil suppliers to reduce their price
to the existing nearby refinery to
enable it to keep going rather than
to absorb substantial additional
transportation costs.
c. Most refined petroleum products are fungible and
widely available 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 brand identi-
fication. 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 decision 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 value as salvage, it
would be better to scrap the refinery than to keep it going.
There are no unusual or hidden profits of integration that need
to be considered.!
The preceding discussion shows that refineries rather
than companies are the proper entities for which to analyze the
impact of effluent guidelines. It is next necessary to identify
refinery characteristics that will oe similarly affected by
revised effluent guidelines.
a. 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 unaf-
fected by effluent guidelines. 2) Several refineries discharge
their effluent to publicly owned treatment works (POTi'J) for
treatment. Such arrangements will be regulated by revised pre-
treatment guidelines. 3) A few refineries, notably in the San
Joaquin Valley in California and along the Houston ship channel,
discharge effluent to jointly owned industrial treatment plants.
It is, at the moment, unclear whether such refinery/treatment
plant combinations will be governed by a combination of revised
pretreatment guidelines and municipal secondary treatment regu-
lations, or by revised BATEA guidelines. At this writing, it
^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 and, it is alleged, may not now be equally
accessible to all refiners and marketers.
-------
is assumed that these refineries are not subject to revised
BATE& guidelines. 4) All other refineries discharge directly
to 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 1.
'o. New or existing source. New refineries will be
subject to new source performance standards (NSPS or PSNS).
New 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. Refinery process unit configuration. Refinery
configuration is a good proxy for 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:
a) The simplest 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 oils and naphtha (for either military jet fuel or feedstock
for other refineries or chemical plants}. b) Slightly more
complex refineries consist of topping plus vacuum distillation
of residual fuel oil. Such refineries process high sulfur crude
oils into asphalt, high sulfur distillate and naphtha.
c) Refineries equipped with topping and catalytic reforming
are able to process crude oils into gasoline and fuel oils.
d) Refineries equipped with topping and catalytic reforming
plus cracking (catalytic, hydro or thermal) are able to "convert"
into gasoline 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 com-
mercial aircraft) and low sulfur fuel oils; e) Refineries
equipped for the manufacture of lubricating oils are hi'jhly
-------
complex, requiring large investment per unit volume of finished
lubricating oil. Small lubricating oil refineries typically
include only catalytic reforming in addition to topping and
lubricating oil processes.
d. Geographical location. Location is important
for judging a refinery's competitive position. The least advan-
tageously 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
impacted by revised guidelines it was not necessary to develop a
formal methodology for describing the competitive strength or
weakness of geographical locations. Rather, this factor is
evaluated on an individual basis.
4. Financial Status of Industry Segments. As was dis-
cussed in the first part of this section the current financial
status of the petroleum refining industry is probably not
relevant for judging the impacts in 1984 of revised guidelines.
Instead, a better assessment of impact is 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: 1) Low protection. A level of protection is assumed
that would hold industry capacity roughly constant. Some capa-
city increase would take place in refineries that are competi-
tively well situated and can be inexpensively "debottlenecked",
and some abandonment of inefficent facilities would take place.
With this level of protection the industry would be financially
marginal. 2) High protection. A level of protection is 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 protect ion the industry would be finan-
cially strong. The difference in price between crude oil and
finished products would have to be significantly greater than
it is currently to attract new refining investments. So now-
existing refineries would experience greatly increased cash
flows.
-------
CHAPTER III
METHODOLOGY
The purpose of this Chapter is to outline the method-
ology used in the economic analysis of revised effluent
guidelines for the petroleum refining industry. The economic
impact analysis includes two key steps - determination of the
price effects of the revised guidelines, and determination
of quantity and employment effects associated with price and
with shutdown of plants faced with high cost-to-conform. It
is assumed throughout that there are no U.S. price controls on
crude oil or refined petroleum products, and that there are no
subsidies for any U.S. refineries.
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 20 and 21.
The price in the market of any manufactured pro-
duct is determined by the cost of the highest cost supplier whose
output is needed to clear the market. In the case of petroleum
products in the U.S. market, there is not enough existing domes-
tic refinery capacity to clear the market for most products.
So the market clearing supply must come from either imports or
domestic capacity expansions.
Foreign refineries have substantial idle capacity that
can be operated at lower costs than can many existing U.S. refin-
eries. So, in the absence of crude oil price controls the U.S.
market price will, up to a point, be determined by foreign
refining costs, plus U.S. import tariff or quota costs. However,
at some level of tar iff/quota, the cost of imports will become
greater than the cost of products manufactured in new U.S.
facilities.
The price of imports is not affected at all by re-
vised guidelines. So revised guidelines will have no impact
-------
on market prices of petroleum products at all tariff/quota
levels below that necessary to encourage construction of new
domestic equipment.
At tariff/quota levels sufficiently high to encourage
new domestic refinery construction, revised guidelines for new
plants (NSPS or PSNS) will have a price effect. This is because
U.S. market prices for petroleum products will have to fully
reflect the full long run cost of installing more stringent
treatment facilities, or the new construction wouldn't be eco-
nomically attractive and, hence, would not take place.
B. Quantity Analysis
At high tariff/quota levels where revised NSPS and
PSNS do have a price effect, there will be an associated quan-
tity effect. The quantity is determined by the price elasti-
city of demand for petroleum products. However, at that over-
all market price level, no existing refineries will be forced
by revised guidelines to shut down.
At low levels of tariff/quota, there will be no
quantity effects due to price. But there may be shutdowns of
existing refineries with high cost-to-conform to revised guide-
lines. The shutdown analysis entails comparing the value of
each existing discharging refinery with the costs of conforming
it to revised guidelines. The value of the existing refinery
is 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 are irrelevant.
The only criterion that establishes value is the amount and
timing of future cash to be returned to the investor. The
analysis, then, consists of two steps - estimation of future
cash flows from the refineries, and comparison of these cash
flows with the costs of conforming effluent qualiity from these
refineries to the requirements of revised guidelines.
Since product prices and consumption will not be
affected by the costs of conforming existing refineries to
revised guidelines, the shutdown analysis is straightforward:
-------
The cost to conform each refinery to revised guidelines is
compared with the value of each refinery as defined above.
Refineries which face conforming costs greater than their value
will shut down. All others will continue to operate, though
their value will be diminished by the capitalized value of the
costs to conform.
Note: It is conceivable that the salvage value of
a plant could be 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 is
predominantly based on its usefulness to
other refiners. Prices for salvaged refin-
ery equipment are high when it is profitable
to construct and operate new refineries.
Conversely, when refinery operations are
marginal, salvage values are low. Also,
land values are assumed to be a small part
of refinery assets.
The balance of trade effects of revised guidelines
will reflect only the necessity to replace voluiue from the very
few refineries that will choose to shut down rather than conform
to the guidelines. Employment effects of revised guidelines
will reflect the number of new employees required to operate
and maintain the new effluent treating equipment offset by the
number of employees losing work due to refinery shutdowns.
-------
31.
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 furnished for 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
Division, Office of Water and Hazardous Materials, U.S. Environ-
mental Protection Agency; and Burns and Roe Industrial Services
Corp.l All costs are stated in dollars of 1977 purchasing
power. These costs have been approved by EPA for use in this
report. The contractor was instructed to use the cost data as
they were given to him, except that estimates of insurance
and local taxes were added to the given operating costs.
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 Supplement for Pre-
treatment 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
^The data for direct dischargers were reported in a letter
from Burns and Roe to Office of Analysis and Evaluation, U.S.
Environmental Protection Agency, dated September 13, 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.
-------
reduction, biological treatment, equalization and filtration
that is intended to bring pollutant mass discharge into confor-
mance with revised PSES.l
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 BPT quality. For both levels the
flow is based on 73 percent of the "model flow" computed for
that refinery. Details of the model flow equation are 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. Level 2 - Level 1 flow plus
installation of either powdered activated carbon addition faci-
lities or rotating biological contactors.
The cost data are presented for direct and indirect
dischargers in Exhibits 3 and 4, respectively. Exhibit 5 con-
tains a summary of costs for these refineries.
A term appears in Exhibits 3, 4, and 5 that may require
explanation. "Annualized cost" combines capital cost and oper-
ating cost into a single value that represents average annual
disbursements required to finance, operate, and amortize a
facility. The "annualized costs" presented in the exhibits are
the sum of two components:
1. The first component is annual cash operating costs
for labor, materials, chemicals, energy, insurance, and ad
valorem taxes. To the costs provided in the Cost Manual and
Burns and Roe's letters were added the estimated costs of
iThe revised PSES definition used for Option 2 is not the
same as the revised BAT guideline for direct dischargers.
The Option 2 definition is associated with a version of the
Cost Manual that was issued in April 1978.
-------
33.
insurance and ad valorem taxes. The latter costs together
amount annually to about four percent of original capital
investment.1
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, nil work-
ing capital, nil salvage value, and construction funds spent
over a two year period - thirty percent in the first year and
seventy percent in the second.
The foregoing parameters lead to an annual before tax
cash flow requirement of twenty-one percent of capital cost.
In other words the owners of such an asset can, on average, take
this much cash out of the business each year of its useful life.
Some of it, of course, must be 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 amortization allowed for
pollution control facilities would have led to lower annual
charges. On the other hand, inclusion of land costs (assumed
nil) and of "sustaining" investments3 would have led to higher
^Sobotka & Company, Inc., Economic Impact of EPA's
Regulations on the Petroleum Refining Industry, April, 1976,
EPA 230/3-76-004, Part Two, p. II-2. The data were obtained
by Turner, Mason & Solomon from a sample of Gulf Coast refiners.
^Gerald A. Pogue, Estimation of the Cost of Capital for
Major U.S. Industries, November, 1975, EPA 230/3-76-001
^Replacement of worn out equipment; installation of facilities
required to meet new and/or revised environmental, safety and
health regulations; replacement 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.
David F. Hart, Harvard Business Review, Vol. 46, No. 5,
p. 32; September-October, 1968.
-------
charges. The excluded factors roughly offset each other. The
effect of higher annual charges is 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 is noted that such a rate of capa-
city utilization may not be achievable by 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 avail-
able, it would have been better to use an 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 model-'- is sized for a capacity of 190,000 barrels per cal-
endar day of Arabian Light crude oil. The model was configured
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 dis-
charging refineries correspond closely to revised Level 1 NSPS
guidelines. So there is no cost for conforming the model to
this level. Revised Level 2 NSPS guideline costs represent
addition of a powdered activated carbon facility to the (assumed)
existing activated sludge unit.
Current guidelines for new indirectly discharging
(PSNS) refineries are the same as current guidelines for existing
-^-Memorandum of February 14, 1979 from Sobotka & Co., Inc.,
to Office of Analysis and Evaluation, HSPS Refinery Configuration.
2Energy Information Administration, Annual Report to Congress
1977, Volume II - Projections of Energy Supply and Demand
and Their Impacts, DOE/EIA-0036/2, April 1978, Chapter 5.
-------
35.
indirectly discharging refineries.1 Level 1 revised guideline
PSNS costs are based on chromium removal from cooling tower
blowdown. Level 2 revised PSNS costs are based on installing
BPT technology, including activated sludge treatment, filtration,
and appropriate in-plant controls.
Costs of conforming the model new refinery to revised
NSPS and PSNS are presented in Exhibit 6. Also shown are costs
for achieving no aqueous discharge^.
1Qp.Cit., EPA 440/1-76/083
^EPA Internal Memorandum from Effluent Guidelines Division
to Office of Analysis and Evaluation, Compliance Cost for
Achieving No Discharge - New Petroleum Refineries, 5 June 1979.
These 1972 costs were inflated to 1977 with cost indices
published in the Oil and Gas Journal.
-------
36.
EXHIBIT 3
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery
Code
Barrels
per Day Lev 1
Lev 2
Lev 1
Lev 2
Lev 1
Lev 2
Lev
1
Lev 2
TOPPING
CONFIGURATION
2
20.0
0
50
0
11
0
22
0
0. 3
6
22.0
0
85
0
11
0
29
0
0.4
70
13.0
12
160
9
33
12
67
0.
3
1.6
100
11.0
0
35
0
11
0
18
0
0.5
189
5.0
0
53
0
8
0
19
0
1.2
197
4.4
0
50
0
8
0
18
0
1.3
199
9.7
125
197
13
23
39
64
1.
2
2.0
255
29.5
0
115
0
15
0
39
0
0.4
266
5.9
130
190
13
74
40
114
2.
1
5.9
292
1.0
0
0
0
0
0
0
0
0
SubTotal
121.5
267
935
35
194
91
390
ASPHALT
CONFIGURATION
3
1. 2
0
35
0
6
0
13
0
3.4
9
3. 5
0
52
0
8
0
19
0
1.6
19
2. 5
0
0
0
0
0
0
0
0
52
4.0
0
240
0
26
0
76
0
5.8
53
14.0
0
35
0
19
0
26
0
0.6
54
3.0
0
35
0
12
0
19
0
2.0
-------
37.
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery
Code
Barrels
per Day Lev 1
Lev 2 Lev
1
Lev 2
Lev 1
Lev 2
Lev
1
Lev 2
ASPHALT CONFIGURATION
(CONTINUED)
72
8.5
0
35
0
18
0
25
0
0.9
108
13.8
0
35
0
9
0
16
0
0.4
118
6.0
0
55
0
9
0
21
0
1. 0
119
11.0
0
115
0
15
0
39
0
1.1
120
4. 2
0
100
0
13
0
34
0
2.5
236
4.5
0
35
0
14
0
21
0
1.4
237
5. 0
0
35
0
7
0
14
0
0.9
260
3.0
0
58
0
9
0
21
0
2. 2
SubTotal
84.2
0
865
0
165
0
344
TOPPING PLUS CHEMICALS
109
23.5
0
40
0
27
0
35
0
0.5
REFORMING
CONFIGURATION
1
30.0
0
50
0
23
0
34
0
0.3
7
38.0
0
70
0
10
0
25
0
0.2
24
53.3
0
240
0
26
0
76
0
0.4
30
22.8
180
230
18
44
56
92
0
.7
1.2
87
5.2
125
220
13
26
39
72
2
.3
4.2
-------
38.
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery
Code
Barrels
per Day
Lev 1
Lev 2 Lev
1
Lev 2
Lev 1
Lev 2
Lev
1
Lev 2
REFORMING CONFIGURATION (CONTINUED)
88
45.0
0
175
0
20
0
57
0
0.4
91
3.9
0
35
0
5
0
12
0
1.0
93
6.5
0
35
0
7
0
14
0
0.7
103
36.0
0
78
0
11
0
27
0
0.2
112
12. 5
160
330
16
36
50
105
1.
2
2.6
190
9.0
0
60
0
9
0
22
0
0.7
210
18.1
0
35
0
6
0
13
0
0.2
213
21.6
0
73
0
10
0
25
0
0.4
239
22.7
0
35
0
18
0
25
0
0.3
259
655.0
0
75
0
172
0
188
0
0.1
265
200. 0
0
48
0
53
0
63
0
0.1
SubTotal
1179.6
465
1789
47
476
145
850
CRACKING
CONFIGURATION
11
47.0
0
60
0
70
0
83
0
0.5
20
100.0
0
75
0
153
0
169
0
0.5
32
110.0
0
4000
0
352
0
1192
0
3.3
37
103.0
0
1600
0
148
0
484
0
1.4
40
405.0
435
555
35
550
126
667
0.
1
0.5
-------
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels
Code per Day Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2
CRACKING CONFIGURATION (CONTINUED)
41
365.0
0
6400
0
546
0
1890
0
1.6
43
80.0
0
2100
0
186
0
627
0
2.4
46
65. 5
0
60
0
75
0
88
0
0.4
49
33.5
0
120
0
15
0
40
0
0.4
50
21. 5
0
565
0
57
0
176
0
2.5
51
150.0
865
3140
602
1030
784
1689
1.6
3.4
56
40.0
195
1100
22
106
63
337
0.5
2.6
57
107.0
530
630
112
678
223
810
0.6
2.3
59
57.0
0
75
0
88
0
104
0
0.6
60
195.0
0
75
0
148
0
164
0
0.3
61
200. 0
0
80
0
208
0
225
0
0.3
62
295.0
0
100
0
377
0
398
0
0.4
63
91.0
0
1900
0
125
0
524
0
1.8
64
78.0
235
310
25
221
74
286
0.3
. 1.1
65
154.0
370
470
42
328
120
427
0.2
0.8
67
380.0
2610
5860
379
869
927
2100
0.7
1.7
68
140.0
385
485
54
434
135
536
0.3
1.2
71
21.0
0
200
0
230
0
65
0
0.9
74
22. 5
0
170
0
20
0
56
0
0.8
-------
40.
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating
Distillation Capital Costs
Capacity, Costs Thousand $
Thousand Thousand $ per year
Refinery Barrels
Code per Day Lev 1 Lev 2 Lev 1 Lev 2
CRACKING CONFIGURATION (CONTINUED)
Annualized Costs
Cents per
Thousand $ Barrel Crude
per Year Oil Processed
Lev 1 Lev 2 Lev 1 Lev 2
76
42. 5
180
1430
19
135
57
435
0.4
3.1
77
23.2
0
40
0
30
0
38
0
0.5
80
52.0
0
90
0
13
0
32
0
0.2
81
57.0
160
1040
16
99
50
317
0.3
1.7
83
90.0
0
85
0
195
0
213
0
0.7
84
80.0
0
75
0
142
0
158
0
0.6
85
138.0
0
95
0
268
0
288
0
0.6
92
270.0
480
2810
50
479
151
1069
0.2
1.2
94
85.0
228
303
22
169
70
233
0.3
0.8
96
528.0
0
2480
0
442
0
963
0
0.6
97
50.0
0
35
0
12
0
19
0
0.1
98
202.3
0
1600
0
144
0
480
0
0.7
99
28. 7
0
83
0
11
0
28
0
0.3
102
90.0
230
305
23
45
71
109
0.2
0.4
104
298.0
0
4100
0
344
0
1205
0
1.2
105
89.0
305
380
34
218
98
298
0.3
1.0
106
154.9
0
1100
0
104
0
335
0
0. 7
113
42.0
0
330
0
34
0
103
0
0.7
-------
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels
Code per Day Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2
CRACKING CONFIGURATION (CONTINUED)
115
131.9
0
90
0
220
0
239
0
0. 6
116
68.0
0
900
0
84
0
273
0
1.2
117
30.0
355
945
23
80
98
278
1.0
2. 8
121
295.0
0
3100
0
275
0
926
0
1.0
122
107.0
520
4920
104
485
213
1518
0.6
4.3
124
42.0
0
365
0
38
0
115
0
0.8
125
56. 0
0
340
0
35
0
106
0
0.6
126
46.0
260
4660
36
422
91
1400
0.6
9.3
127
6. 5
0
150
0
18
0
50
0
2. 3
129
5.0
120
220
13
26
38
72
2.3
4.4
131
168.0
0
90
0
240
0
259
0
0. 5
132
300.0
740
3070
138
577
293
1222
0.3
1.2
133
100.0
660
785
161
767
300
932
0.9
2.8
134
103.0
350
450
48
366
122
460
0.4
1.4
144
49. 9
0
113
0
14
0
38
0
0.2
146
4.9
125
220
13
26
39
72
2.4
4.5
147
65.0
0
40
0
53
0
61
0
0.3
149
44. 0
170
970
18
92
54
296
0.4
2.0
-------
42.
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels
Code per Day Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2
CRACKING CONFIGURATION (CONTINUED)
150
51.0
0
52
0
83
0
94
0
0.6
151
177.0
330
3030
32
272
101
908
0.2
1.6
152
120.0
630
745
143
760
275
916
0.7
2.3
153
125.0
0
100
0
304
0
325
0
0.8
155
14. 5
0
95
0
13
0
33
0
0. 7
156
55.0
0
475
0
48
0
148
0
0.8
157
130. 3
0
75
0
164
0
180
0
0.4
158
54.6
0
40
0
51
0
59
0
0.3
159
19.0
0
225
0
24
0
71
0
1.1
160
23.5
0
35
0
22
0
29
0
0.4
161
51.0
0
275
0
29
0
87
0
0.5
162
90.0
0
75
0
201
0
217
0
0.7
163
52.0
0
700
0
70
0
217
0
1.3
165
60. 0
0
234
0
26
0
75
0
0.4
167
195. 0
575
675
82
482
203
624
0.3
1. 0
168
170.0
0
80
0
231
0
248
0
0.4
169
188.0
720
845
125
799
276
976
0.4
1.6
176
52.0
0
285
0
30
0
90
0
0.5
-------
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels
Code per Day Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2
CRACKING CONFIGURATION (CONTINUED)
179
26.0
0
225
0
25
0
72
0
00
.
o
180
80.0
315
390
41
261
107
343
0.4
1.3
181
363.0
980
3540
145
590
351
1333
0.3
1.1
183
63.0
0
420
0
42
0
130
0
0.6
184
67.0
0
75
0
103
0
119
0
0.5
186
185.0
0
75
0
149
0
165
0
0.3
194
405.0
750
10100
74
945
232
3066
0.2
2. 3
196
319.0
1280
4380
244
724
513
1644
0.5
1.6
201
66.0
0
60
0
82
0
95
0
0.4
204
103.0
268
358
29
297
85
372
0.3
1.1
205
103.4
270
1970
27
180
84
594
0.2
1.8
208
310.0
0
100
0
394
0
415
0
0.4
211
125.0
0
60
0
71
0
84
0
0.2
212
60.0
0
50
0
63
0
74
0
0.4
216
476.0
0
3250
0
488
0
1170
0
0.7
219
80.7
0
850
0
82
0
260
0
1.0
221
129. 5
300
390
34
297
97
379
0.2
0. 9
222
13.5
155
430
16
45
49
135
1.1
3.1
-------
44.
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery
Code
Barrels
per Day
Lev 1
Lev 2
Lev 1
Lev 2
Lev 1
Lev 2
Lev
1
Lev 2
CRACKING
CONFIGURATON (CONTINUED)
226
7. 5
0
65
0
10
0
24
0
1.0
227
45.0
0
60
0
98
0
111
0
0.8
230
25. 0
0
520
0
52
0
161
0
2.0
232
55.0
0
60
0
92
0
105
0
0.6
233
100.0
0
60
0
87
0
100
0
0.3
234
75.0
0
60
0
87
0
100
0
0.4
235
94.0
0
75
0
123
0
139
0
0.4
238
78.0
243
318
27
181
78
248
0.
3
1.0
243
42.0
0
145
0
17
0
47
0
0.3
252
10.6
0
115
0
15
0
39
0
1.1
256
40. 0
0
285
0
30
0
90
0
0.7
257
150.0
0
1400
0
128
0
422
0
0.9
261
40.0
180
228
18
59
56
107
0.
4
0.8
SubTotal 12568.9
106094
17504
3026
22935
6704
45217
LUBRICATING OIL CONFIGURATION
10
6. 0
0
70
0
10
0
25
0
1.3
12
4.5
0
441
0
45
0
138
0
9.3
89
4.0
0
77
0
12
0
28
0
2.1
-------
45.
EXHIBIT 3 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels •
Code per Day Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2 Lev 1 Lev 2
LUBRICATING OIL CONFIGURATION (CONTINUED)
90
2. 2
0
60
0
9
0
22
0
3.0
154
5.5
0
700
0
68
0
215
0
11.9
172
12.0
185
235
22
88
61
137
1.5
3.5
173
3.5
160
200
16
61
50
103
4.3
9.0
174
7.1
135
565
13
57
41
176
1.8
7.5
177
7.6
175
225
19
86
56
133
2.2
5.3
240
5.5
0
40
0
26
0
34
0
1.9
241
12.0
0
45
0
42
0
51
0
1.3
242
5. 2
0
40
0
30
0
38
0
2. 3
258
85.5
0
60
0
86
0
99
0
0.4
SubTotal
160.6
655
2758
70
620
208
1199
PLANT DOES NOT :
PROCESS CRUDE OIL1
295
0.0
170
210
18
44
54
88
309
0.0
220
265
482
524
528
o
CO 1
in '
SubTotal
o
•
o
390
475
500
568
582
668
GRAND
TOTAL
14141.8
19281
3678
7730
DIRECT 112956 24985 48703
^No entry for item II.A in reply to Section 308 Questionnaire.
-------
46.
EXHIBIT 4
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery
Code
Barrels
per Day
Opt 1
Opt 2
Opt 1
Opt 2
Opt 1
Opt 2
Opt 1
Opt 2
TOPPING
CONFIGURATION
23
16.0
0
315
0
73
0
139
0
2.7
110
6.0
0
250
0
67
0
120
0
6.1
128
3.8
0
277
0
41
0
99
0
10.0
145
5.2
59
247
9
65
21
117
1.3
6.9
193
3.2
59
247
9
65
21
117
2.0
11.1
195
1.0
0
247
0
65
0
117
0
35.7
206
36.5
70
437
11
113
26
205
0.2
1.7
231
10.0
0
1110
0
422
0
655
0
20.0
264
23. 0
0
250
0
66
0
119
0
1.6
305
13.0
103
277
15
41
37
99
0.9
• 2.3
SubTotal
116.9
291
3657
44
1018
105
1787
ASPHALT
CONFIGURATION
8
5. 0
63
0
10
0
23
0
1.4
0
18
19.5
145
495
19
78
49
182
0.8
2.8
31
12.0
100
247
14
65
35
117
0.9
3.0
79
3.0
0
0
0
0
0
0
0
0
107
17.0
100
255
14
68
35
122
0.6
2.2
-------
EXHIBIT 4 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery
Code
Barrels
per Day
Opt 1
Opt 2
Opt 1
Opt 2
Opt 1
Opt 2
Opt 1
Opt 2
TOPPING CONFIGURATION (CONTINUED)
148
20.0-
0
493
0
131
0
235
0
3.6
166
14.0
118
273
17
108
42
165
0.9
3.6
90.5
526
1763
74
450
184
821
TOPPING PLUS CHEMICALS
207
46.0
166
375
23
108
58
187
0.4
1.2
REFORMING
CONFIGURATION
16
48. 0(
188
826
28
169
67
342
0.4
2.2
21
20.0
102
373
14
78
35
156
0.5
2.4
291
15. 2
202
250
39
61
81
114
1.6
2.3
SubTotal
83. 2
492
1449
81
308
183
612
CRACKING
CONFIGURATION
13
193.0
620
5800
211
858
341
2076
0.5
3.3
14
12.4
114
315
12
64
36
130
0.9
3.2
25
53.8
232
375
51
70
100
149
0.6
0.8
29
131.1
357
4650
88
707
163
1684
0.4
3.9
-------
EXHIBIT 4 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels
Code per Day Opt 1 Opt 2 Opt 1 Opt 2 Opt 1 Opt 2 Opt 1 Opt 2
CRACKING CONFIGURATION (CONTINUED)
33
44.0
206
1090
37
196
80
425
0.6
2.9
38
93.0
425
4350
152
629
241
1542
0.8
5.1
45
111.0
480
3900
176
575
277
1394
0.8
3.8
58
70.0
284
1900
74
235
134
634
0.6
2.8
73
44.5
225
915
45
121
92
313
0.6
2.1
78
30.0
143
1390
17
175
47
467
0.5
4.7
86
25.0
211
800
44
136
88
304
1.1
3.7
111
66.0
470
2450
213
309
312
824
1.4
3.8
114
24.0
0
683
0
130
0
273
0
3.5
130
5.4
0
1310
0
473
0
748
0
42.2
142
63.0
216
2450
38
309
83
824
0.4
4.0
143
44.0
0
2190
0
262
0
744
0
5.2
175
165.0
972
13300
701
2892
905
5685
1.7
10.5
182
324.5
1000
7000
354
1061
564
2531
0.5
2.4
188
100.0
500
3660
202
486
307
1255
0.9
3.8
200
29.3
285
1150
91
152
151
394
1.6
4.1
203
335.0
1062
13800
382
2062
605
4960
0.6
4.5
224
20.0
0
655
0
138
0
276
0
4.2
-------
49.
EXHIBIT 4 (CONTINUED)
COSTS OF CONFORMING
DIRECTLY DISCHARGING PETROLEUM REFINERIES
TO REVISED BATEA GUIDELENES
Crude Oil Operating Annualized Costs
Distillation Capital Costs Cents per
Capacity, Costs Thousand $ Thousand $ Barrel Crude
Thousand Thousand $ per year per Year Oil Processed
Refinery Barrels
Code per Day Opt 1 Opt 2 Opt 1 Opt 2 Opt 1 Opt 2 Opt 1 Opt 2
CRACKING CONFIGURATION (CONTINUED)
225 40.4 0 2220 0 266 0 732 0 5.5
228 25.0 216 710 40 140 85 289 1.0 3.5
229 5.6 98 242 13 35 34 86 1.8 4.7
SubTotal 2055.0 8116 77305 2941 12481 4645 28739
LUBRICATING OIL CONFIGURATION
220 10.0 0 258 0 67 0 121 0 3.7
GRAND — _ ____ _ _ _ __
TOTAL 2401.6 9591 84807 3163 14432 5175 32267
INDIRECT
-------
50.
EXHIBIT 5
SUMMARY OF COSTS OF CONFORMING
PETROLEUM REFINERIES
TO REVISED EFFLUENT DISCHARGE GUIDELINES
Crude Oil
Distillation
Capacity,
Thousand
Barrels
per Day
Capital
Costs
Thousand $
Operating Annualized Costs
Costs Cents per
Thousand $ Thousand § Barrel Crude
per Year per Year Oil Processed
DIRECTLY DISCHARGING REFINERIES
Level 1 14,142 19,281 3,678
Level 2 14,142 112,956 24,985
7,730
48,703
0.2
1.0
INDIRECTLY DISCHARGING REFINERIES
Option 1 2,402 9,591 3,163
Option 2 2,402 84,807 14,432
5,175
32,267
0.7
4.1
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51.
EXHIBIT 6
COSTS OF CONFORMING
A NEW PETROLEUM REFINERY
TO REVISED EFFLUENT DISCHARGE GUIDELINES
Capital
Cost
Thousand $
Operating
Cost
Thousand $
per Year
Annualized Cost
Thousand $
per Year
Cents per
Barrel Crude
Oil Processed^
DIRECT DISCHARGE (NSPS) 2
Level 1
Level 2
0
75
0
218
0
234
0
0.4
INDIRECT DISCHARGE (PSNS) 3
Option 1 260 140
Option 2 5,800 2,230
195
3,450
0.3
5.5
NO AQUEOUS DISCHARGE 2
9,500 1,880
3,875
6.2
1 Based on 171,000 barrels per day annual average throughput.
2 Costs are additional above current NSPS (BADT).
3 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 may reasonably be expected to be in place in 1984.
In this Chapter, a high level of protection is assumed.
Specifically, the level is hicjh 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 will clear 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 bo 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^:
Directly discharging refineries (NSPS)
Level 1 no cost
Level 2 0.009 cents per gallon refined product
Indirectly discharging refineries (PSNS)
Option 1 0.007 cents per gallon refined product
Option 2 0.13 " " " " "
Mo aqueous discharge 0.15 cents per gallon refined product
-^•Costs are from Chapter IV, Exhibit G divided by 0.94,
the approximate fractional yield of products from crude oil
in new refineries.
-------
There is no way to estimate which of the above four
options would, in fact, turn out to be associated v/ith the price-
determining (market clearing) refinery at any specific time.
All that can be concluded is that the price effect of revised
new source guidelines will be zero to 0.15 cents per gallon of
product manufactured (stated in cents of 1977 purchasing power).
B. Financial Effects
It is the premise of this Chapter that new refineries
will be fully compensated for all costs by tariff/quota pro-
tection. Consequently, revised new source guidelines must, by
premise, have no financial effect on new refinery capacity.
For existing refineries, the financial impact of
revised guidelines will be 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 bene-
fits may be as low as zero or as high as .15 cents per gallon
of refined product. Existing refineries will process roughly
5435 million barrels per year of crude oil.l So the annual
benefit to existing refineries from revised new source guide-
lines may be as low as zero or as high as 340 million dollars
per year.2
The total annualized cost to existing refineries of
revised guidelines for existing sources will range from 13
million dollars per year (BATEA Level 1 and PSES Option 1) to
81 million dollars per year (BATEA Level 2 and PSES Option 2)3.
So the net financial effect on existing refineries of revised
lChapter III, Exhibit 5: (14.142 + 2.402) million
barrels per day x 0.9 operating ratio x 365 days per year.
2 5435 million barrels per year x 0.062 dollars per barrel
crude oil processed = 340 million dollars per year.
^Chapter III, Exhibit 5.
-------
guidelines may be as adverse as a cost of (zero minus 81 =)
81 million dollars per year or as beneficial as a revenue
increase of (340 minus 13 =) 325 million dollars per year.
C. Production Effects
This Chapter is based on a premise of protection
against imports sufficiently high to support growth of U.S.
domestic refinery capacity. Hence "by definition" there can
be no production impacts of revised new source guidelines on
new refineries. Whether or not revised existing source guide-
lines will have an impact depends 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 capacityl requires a difference between
product sales revenue and raw material acquisition cost of about
three dollars per barrel of crude oil processed2 to justify its
construction. During 1978 the difference between revenue and
raw material cost approximated 2.3 dollars per barrel3. Thus,
the gap between 1978 conditions and a high protection policy
is 0.7 dollars per barrel crude oil processed. This improvement
in condition is greater than the highest cost estimated for con-
forming an existing refinery to revised guidelines - 0.42 dollars
per barrel4. So the combination of high protection and revised
guidelines would have the highest cost-to-conform refinery better
off than it is today by roughly 0.28 dollars per barrel crude
oil processed. Clearly, there will be no production effects of
revised guidelines if a high protection policy is implemented.
ISize and configuration as outlined in Chapter IV, Section B
2Sobotka & Co., Inc., Capital and Operating Costs for Grass
Roots Refineries with Several Different Process Unit Config-
urations , Department of Energy Contract No. EJ-78-C-01-2834,
Task No. 10, April 12, 1979
3Chase Manhattan Bank, The Petroleum Situation, March 1979
4Chapter IV, Exhibit 4, Refinery 130.
-------
D. Employment Effects
Given high protection, no jobs will be lost in the
U.S. petroleum refining industry because of revised effluent
guidelines. New jobs will be created by revised guidelines.
New effluent treating facilities will need 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 are:
Mew Jobs
Existing Direct Dischargers
Level 1 40
Level 2 600
Existing Indirect Dischargers
Option 1 10
Option 2 250
New Sources*
NSPS - Level 1 0
Level 2 200
PSNS - Option 1 20
Option 2 1600
No Discharge 800
Hence, new employment could range from 50 to 2,450 jobs,
depending on which combination of Level/Option is chosen
for implementation.
E. Community and Balance of Trade Effects
Given high protection, revised effluent guidelines
will have no community or balance of trade effects.
lBased on 36 new refineries required between 1977 and
1990 - Op. Cit., DOE/EIA - 0036/2, p.138.
-------
56.
CHAPTER VI
ECONOMIC IMPACT ANALYSIS WITH
LOW LEVEL OF PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS
It was established in Chapter II that either of two
levels of protection against refined product imports may reason-
ably be expected to be in place in 1934. in this Chapter, a
low level of protection is assumed. Specifically the level is
such that the capacity of the industry will remain roughly con-
stant duriny the period 1970-1990. Of course there would be
some shifting of capacity as inefficient and/or poorly located
plants are 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 or quotas,
if any).
A* Price Effects
Market prices for petroleum products will be determined
by the costs of imports. Import costs are unaffected by U.S.
effluent guidelines. So there will be no price effects of
revised guidelines.
B. Financial Effects
Because petroleum product prices will be unaffected
by revised guidelines, the costs of revised guidelines will
have to be absorbed by the petroleum refining industry. The
total costs of revised guidelines to the industry that will
have to be absorbed were shown in Exhibit 5 of Chapter IV.
-------
They are:
Operating
Costs
Annualized Costs
Capital Costs Cents per
Costs Thousand $ Thousand $ Barrel Crude
Thousand $ per Year per Year Oil Processed
Directly Discharging Refineries
Level 1 19,281 3,678 7,730
Level 2 112,956 24,905 48,703
0. 2
1.0
Indirectly Discharging Refineries
Option 1 9,591 3,163 5,175
Option 2 84,807 14,432 32,267
0.7
4.1
These are small costs compared to other cost elements incurred
by refineries, e.g., raw material cost is about fourteen hundred
cents per barrel, cash operating costs range from fifty to two
hundred cents per barrel, and capital charges range from fifty
to three hundred cents per barrel. It can be concluded that
revised guidelines will have a negligible impact on the financial
status of the industry as a whole.
C. Production Effects
Although the average cost of revised guidelines
will be small, there are some refineries that will face signi-
ficant cost increases. If such costs are sufficiently high,
refiners will be better off to shut down than to incur the costs.
It is the purpose of this Section to identify high cost refin-
eries and to judge whether or not they are likely to shut down.
-------
h reasonable minimum value for judging the significance
of conformance cost is one-tenth cent per gallon, or 4.2 cents
per barrel. This is the smallest amount by which price quotes
for almost all products are changed; one-fourth cent is the
usual change increment. Also, it is essentially impossible
to measure unit manufacturing costs within one-tenth cent per
gallon, because product volume measurement isn't sufficiently
accurate.
The 27 refineries with revised guideline costs greater
than 4.1 cents per barrel are listed in Exhibit 7.
-------
59.
EXHIBIT 7
EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
TO REVISED GUIDELINES OF MORE THAN 4.1
CENTS PER BARREL OF CRUDE OIL PROCESSED
Refinery
Code
Crude Oil
Distillation
Capacity,
Thousand
Barrels Per
Day
Config-
uration^)
Discharge
Mode2)
Compliance Costs,
Cents per Barrel
Crude Oil Processed
Lev/Opt Lev/Opt 2
130
5.4
C
I
42.2
195
1.0
T
I
35.7
231
10.0
T
I
20.0
154
5.5
L
D
11.9
193
3.2
T
I
2.0
11.1
175
165.0
C
I
1.7
10.5
128
3.0
T
I
10.0
12
4.5
L
D
9.3
126
46.0
C
D
0.6
9.3
173
3.5
L
D
4.3
9.0
As defined in Chapter III: T = topping, A = asphalt,
R = reforming, C = cracking, and L = lube.
2) Direct or Indirect
-------
60.
EXHIBIT 7 CONTINUED
EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
TO REVISED
GUIDELINES
OF MORE THAN
4.1
CENTS PER i
BARREL OF CRUDE OIL PROCESSED
if inery
Crude Oil
Distillation
Capacity,
Thousand
Barrels Per
Config-
uration^)
Discharge
Mode^/
Compliance Costs,
Cents per Barrel
Crude Oil Processed
Code
Day
Lev/Opt 1
Lev/Opt 2
174
7.1
L
D
1.8
7.5
145
5.2
T
I
1.3
6.9
110
6.0
T
I
6.1
266
5.9
T
D
2.1
5.9
52
4.0
A
D
5.8
225
40.4
C
I
5.5
177
7.6
L
D
2.2
5.3
143
44.0
C
I
5.2
38
93.0
C
I
0.8
5.1
78
30.0
C
I
0.5
4.7
As defined in Chapter III: T = topping, A = asphalt,
R = reforming, C = cracking, and L = lube
2) Direct or Indirect
-------
61.
EXHIBIT 7 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
Distillation
Capacity,
Thousand
Refinery Barrels Per Config-
Code Day uration-*-)
229 5.6 C
146 4.9 C
203 335.0 C
129 5.0 C
122 107.0 C
87 5.2 R
224 20.0 C
Compliance Costs,
Cents per Barrel
Discharge Crude Oil Processed
Mode^J Lev/Opt 1 Lev/Opt 2
I 1.8 4.7
D 2.4 4.5
I 0.6 4.5
D 2.3 4.4
D 0.6 4.3
D 2.3 4.2
I 4.2
1) As defined in Chapter III: T = topping, A = asphalt,
R = reforming, C = cracking, and L = lube
2) Direct or Indirect
-------
1. Values of Existing Refineries
As was stated in Chapter II, 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 cer-
tainty because all the facts required for the computation lie
in the unknown future. But it is possible to imply present
values from actions that informed investors are taking. For
example, if several informed investors decide independently to
invest in new catalytic cracking capacity, it is reasonable and
useful to assume that they expect the present value of future
cash flow from new catalytic cracking units to equal (or exceed)
the cost of such units. Conversely, if existing crude oil dis-
tillation capacity in the world is more than adequate to meet
forecast 1990 needs, it is reasonable and useful to assume that
competition will restrict cash flow from less efficient crude
units to zero; and no unit will come anywhere near generating
a cash flow commensurate with its replacement cost.
In the following paragraphs, estimates of the values
of new processing units will be developed. Except where other-
wise indicated, evidence of new construction is based on listing
in Hydrocarbon Processing, February 1979, and/or Oil and Gas
Journal, May 7, 1979. Construction costs of new processing unit
(stated in dollars of 1977 purchasing power), are from Sobotka
b Co., Inc., Op. Cit, April 12, 1979. Adjustments for unit
capacity and age are developed after unit values are derived.
a. Conversion processes and catalytic reforming.
Many units of each of these processes are under construction.
This establishes that many different investors have concluded
that acceptable rates of return can be expected from investments
in such units. For consistency with the annualized costs com-
puted for revised guidelines (Exhibit 3 in Chapter IV) it is
assumed that a discounted cash flow rate of return of twelve
percent per year is "acceptable". The expected annual before
-------
63.
tax cash flow from such new units, then, is 21 percent of capital
cost. Expected before tax cash flows from new large conversion
and reforming units are:
Process
Capacity,
Thousand
Barrels pet-
Calendar Day
Cost,
Million
1978 $ a
Expected Annual Cash Flo
$ per Barrel
Million
$
of Calendar
Day Capacity
Catalytic
cracking
Alkylation
55
20 b
127
61
26.7
12.8
485
640
Hydrocracking
Thermal
cracking c
Delayed
coking
45
20
20
Catalytic reforming
(including
naphtha
desulfurization) 35
126
27
40
26.5
5.7
8.4
590
285
420
83
17.4
500
a including offsite and associated costs
b product capacity
c estimated
-------
b. Lubricating oil raanuf acture. The operation of
this complex combination of processes creates substantial cash
flow. Since World War III, lubricating oil manufacture has
generated a before tax cash flow ranging between two and four
dollars per barrel manufactured2. Also, the demand facing U.S.
and Free World lubricating oil manufacturers is growing at least
as rapidly as is manufacturing capacity3. Consequently, a con-
tinuation of before tax cash flows at historical levels seems
assured for many years. On the same basis as tabulated above,
the expected annual cash flow from lubricating oil manufacture
is about 1200 dollars per barrel of calendar day capacity^.
c. Crude oil distillation. There exists today a large
worldwide surplus of crude oil distillation capacity.5 Conse-
quently, in the absence of tariff or quota protection, the only
cash flow that would be expected from a large new crude unit
would be a reduction in company income taxes due to tax depre-
ciation of the new unit. This amounts to 3.5 percent of capital
cost, which is about fifteen dollars per year per barrel of
calendar day capacity (for a 150,000 barrel per day unit).6
Small crude oil distillation units owned by small
refiners are currently in a different situation. Such units
lWith the exception of the Arab oil boycott of 1973 and 1974
2r.f. Somraerville, Hydrocarbon Processing, August 1977,
p. 127.
3ibid.
4 $3 per barrel x 305 days per year
0.9 capacity utilization
5oil and Gas Journal, June 12, 197U, p. 40
^Capital cost about sixty million dollars.
-------
65.
receive an outright subsidy from the Federal Government via
the "entitlements" system. The latest amounts of the subsidy
arel:
Company Refining Capacity, Subsidy, Cents per Barrel
Thousand Barrels per Day Crude Oil Processed
below 10 96
10 - 30 53
30 - 50 23
50 - 100 9
The subsidy is intended to disappear eventually. It appears
prudent for this study to assume that it will be negligible
by 1984.
d. Adjustments for size and age of process units.
All else equal, a small process unit will cost more to build,
per barrel of capacity, than a large unit. It follows that,
if they are to be economical to build, small units must also
generate more cash flow per barrel than lar
-------
66.
It is difficult to judge the remaining life of a
process unit. For example, there are more than a dozen catalytic
cracking units that were first built in 1944 and 1945 that have
been so thoroughly rebuilt and modernized that they are almost
as efficient as brand new units, despite 33 years of operation.
Nevertheless, it is appropriate to recognize tnat, necessarily,
old units are not as valuable as new ones. A useful way to
account for this lower value is to utilize lower values for the
annual cash flow estimates that were tabulated in Sections C.l.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 is one-half that expected from a new
unit.1
From the above and, for convenience, averaging the
costs of processes of nearly equal value, the following estimates
can be used for computing the value of an existing refinery:
Expected Annual Cash Flow, $ per
Process Barrel of Calendar Day Capacity
Lubricating oil 600
Alkylation 300
iiydroeracking 300
Catalytic reforming
(including naphtha
desulfurization)
Catalytic cracking
Delayed coking
Thermal cracking
Crude oil distillation
250
250
200
150
10
IThis is equivalent to estimating that the old unit will
last for six years anil the new unit for thirty: The present
value of an annuity of $1 per year for 0 years at 12 percent
per year is $4.3. The present value of an annuity of $1 per
year for 30 years at 12 per cent per year is $8.5.
-------
e. Asphalt manufacture. This process was not included
in the above table. This is because, contrary to other refinery
processes, the value of most asphalt manufacturing facilities
is determined predominantly by the level and relative location
of roadbuilding activity. On the one hand, if roadbuilding
activity is 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 will generate
a high cash flow. On the other hand, desultory roadbuilding
activity located well away from the plant might lead to
essentially no cash flov/.
For these reasons, the asphalt refinery listed
in Exhibit 7 will be evaluated on the basis of implied road-
building activities rather than on process unit value.
2. Guidelines Cost Versus Refinery Value
In Exhibit 3, the values and revised guidelines
compliance costs for the 26 non-asphalt refineries listed
in Exhibit 7 are compared. Costs and values are stated on
an annual basis. Compliance costs are from Exhibit 3; values
are computed by multiplying process unit capacities reported
by the refineries in their replies to the "Section 308 Ques-
tionnaire" times the estimated annual per-barrel cash flows
tabulated in Section C.l.d. above.
Exhibit 8 shows that nineteen refineries have ex-
pected cash flows from their process units that are substan-
tially greater than the cash flows required to meet revised
guidelines. These plants will clearly be willing to conform
to revised guidelines in order to preserve their cash flow.
The remaining seven (non-asphalt) refineries have Level 2 or
Option 2 compliance costs greater than their process unit
values. All of these refineries are "topping" configuration.
3. Evaluation of High Cost Refineries
The seven topping refineries will be discussed indi-
vidually in order of refinery code number. Then the asphalt
refinery will be discussed.
-------
f in<
God'
130
195
231
154
193
175
128
12
126
173
EXHIBIT 8
COMPARISON OF PROCESS UNIT VALUES
VERSUS COST TO CONFORM TO REVISED GUIDELINES
Process Unit Capacity, Thousand Barrels per Day Estimated Annual Cash Flow, Thousand $
From To Revised Value
Crude Lube Alkyl- Hydro Cat. Cat. Thrml. Process Unit Guidelines Minus
Oil Oil ation Crk'g Rfm'g Crk'g Cok'g Crk'g Values Cost Cost
5.4
1.0
2.1
883
748
135
1.0
20
117
(97)
10.0
200
655
(455)
5.5
1.0
710
215
495
3.2
64
117
(53)
165.0
17.0
12.0
45.0
75.0
47100
5685
41415
3.0
60
99
(39)
4.5
2.0
1290
138
1152
46.0
3.4
4.6 14.5
19.2 5.2
12785
1400
11385
3.5
1.7
1.2
1390
103
1287
-------
174
145
110
266
225
177
143
38
78
EXHIBIT 8 (CONTINUED)
COMPARISON OF PROCESS UNIT VALUES
VERSUS COST TO CONFORM TO REVISED GUIDELINES
Process Unit Capacity, Thousand Barrels per Day Estimated Annual Cash Flow, Thousand $
From To Revised Value
Crude Lube Alkyl- Hydro Cat. Cat. Thrml. Process Unit Guidelines Minus
Oil Oil ation Crk'g Rfm'g Crk'g Cok'g Crk'g Values Cost Cost
7.1 2.5
2.1
2167
176
1991
5.2
104
117
(13)
6.0
120
120
0
5.9
118
114
(4)
40.4
3.8
18.0
6448
732
5716
7.6 1.4
992
133
859
44.0
11.5
19.0
8505
744
7761
93.0
8.6
21.0
40.0
37.0
27090
1542
25548
30.0
2.6
5.0
11.5
4.0
6303
467
5836
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EXHIBIT 8 (CONTINUED)
COMPARISON OF PROCESS UNIT VALUES
VERSUS COST TO CONFORM TO REVISED GUIDELINES
Process Unit Capacity, Thousand Barrels per Day
Refinery Crude Lube Alkyl- Hydro Cat. Cat. Thrml.
Code Oil Oil ation Crk 'g Rfm'g Crk'g Cok'g Crk'g
Estimated Annual Cash Flow, Thousand $
From
Process Unit
Values
To Revised
Guidelines
Cost
Value
Minus
Cost
Value Minus
Revised Guide-
lines Cost,
Cents per
Barrel Crude
Oil Processed
229
5.6
4.6
1262
86
1176
64
146
4.9
2.0
1.1
763
72
691
43
203
335.0
8.8
12.0
29.0 102.0
140.0
27.0
90180
4960
85220
77
129
5.0
0.1
2.2
455
72
383
23
122
107.0
4.5
14.0
41.0
11.0
19440
1518
17922
51
87
5.2
1.0
354
72
282
17
224
20.0
3.5
1275
276
1000
15
o
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a. Refinery 110 is located in Michigan about 125 miles
northwest of Detroit. This plant faces revised guideline costs
(indirect, Option 2) of six cents per barrel crude oil processed,
compared to an estimated process 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^. The principal competition for gasoline
and fuel oil sales comes from a forty thousand barrel per day
cracking refinery located about fifteen miles away.
It appears that the future of Refinery 110 is inde-
pendent of revised guideline costs. If a small refiner subsidy
is maintained, even at a low level, this plant will most probably
be willing to incur revised guideline costs and keep operating.
But, absent such a benefit, trie refinery would have little or
no value and might choose to shut down. (However, the plant
operated in the early 1970's without subsidy). Revised guideline
costs do not appear to be large enough to significantly influence
the decision of whether or not to shut down.
b. Refinery 128 is located in northeastern Montana.
This plant faces 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 during 1977-*- and the new owners increased capacity
from 3000 to 4500 barrels per day during 19782. During 1976
forty percent of the refinery's outturn was military jet fuel.
No gasoline was manufactured.2 Principal competition for
lu.S. Bureau of Mines, Petroleum Refineries in the United
States and Puerto Rico, published annually.
2Heply to Section 308 questionnaire.
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residual fuel oil sales comes 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 is located in a crude oil producing area.
The local crude oil gives high yields of jet and diesel fuels.
And operations associated with crude oil production and trans-
portation consume diesel fuel.
It is concluded that this refinery is viable without
subsidy. And its strong location - adjacent to both its crude
oil supply and markets - makes it probable that the ov/ners will
be willing to absorb guideline conformance costs and continue
in operation. It is also possible that they may be able to
persuade their crude oil suppliers to share some of the costs.
c. Refinery 145 is located in southwest North Dakota.
It faces 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 processes
crude oil produced nearby. It manufactured no gasoline or jet
fuel in 1976. Principal competition comes 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 appe
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d. Refinery 193 Is located in the Houston, Texas,
metropolitan area. It faces revised guideline costs (indirect,
Option 2) of eleven cents per barrel crude oil processed, com-
pared to an estimated process unit value of six cents per barrel.
This refinery began operations before 1970. It ex-
panded 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 has neither crackiny
nor reforming facilities, it can be assumed that much of the
gasoline - perhaps as much as two-thirds - was high octane
blending stocks purchased from nearby refineries. Competition
arises from these same refineries - over one million barrels
per day of refining capacity is located within thirty miles
of refinery 193.
The estimated conformance costs for this plant include
no provision for land. It is understood informally that the
plant has such severe space restrictions that the installation
of a water treatment facility that requires any significant land
area could be accomplished only by removing some existing tankage
or by purchasing expensive adjacent land. If this information
is correct, refinery 193 is facing higher conformance costs than
eleven cents per barrel.
It is not possible to estimate the actual cost for
this plant without engineering and real estate data. However,
it appears that this refinery might choose to shut down rather
than incur revised guideline costs.
e. -Refinery 195 is located near San Antonio, Texas.
It faces 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.
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Refinery 195 began operations before 1970. The plant
manufactured no gasoline or jet fuel in 1976. Principal compe-
tition comes from two small nearby refineries, and from five
nearby pipeline terminals that distribute products refined along
the Texas Gulf Coast.
Refinery 195 and its neighbors appear to have a sig-
nificant transportation advantage compared to their competitors.
Texas crude oil flows past San Antonio on its way east to Gulf
Coast refineries and products flow back west to San Antonio.
However, it is doubtful that the advantage is enough to com-
pensate for the high revised guideline costs.
It is concluded that refinery 195 will be willing to
incur revised guideline costs only if Federal subsidies to small
refiners continue at fairly high levels. Without subsidy, re-
vised guideline costs will apparently cause it to choose to shut
down.
f. Refinery 231 is located near Salt Lake City, Utah.
It faces 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 can be assumed that much of this product
was high octane blending components procured from one or more
of six nearby refineries. These plants are equipped with cata-
lytic cracking and catalytic reforming. Competition for Refinery
231 arises from these same plants.
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It appears that Refinery 231 is an "entitlements
refinery", i.e., its existence is dependent on Federal subsidy.^
It is likely that this plant's outturn could be more economically
supplied by minor expansion of one or more of the nearby refin-
eries. If this analysis is correct, the refinery's future will
be determined by Federal subsidy policies rather than revised
guidelines.
However, even if the refinery is competively viable
without subsidy, revised guideline costs will probably cause
it to shut down. Revised guideline costs faced by every neigh-
boring refinery are less than four cents per barrel2. The
revised guideline cost disadvantage of over one-half million
dollars per year^, and the capital requirement of 1.1 million
dollarappear to be too large to face.
g. Refinery 266 is located in southwestern Michigan,
roughly equidistant from Chicago, Detroit, and Toledo, where
the nearest refineries are located. This plant faces revised
guideline costs (direct, Level 2) of six cents per barrel crude
oil processed, compared to an estiiaated 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.^
Refinery 266 began operation before 1970. It expanded
to its present capacity - 5,600 barrels per day - during 1974.
Refinery 266 manufactured military jet fuel, fuel oils, and a
^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.
^Exhibit 4 - Refinery 228
-*{.20 - .035 cents/barrel) x (10,000 barrels/day capacity) x
(0.9 utilization factor) x (365 days/year) = $ 0.54 million/year
^Exhibit 3
5Reply to Section 308 questionnaire.
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76.
small quantity of leaded motor gasoline 1. Principal compe-
tition is from two pipeline terminals, each located about
fifty miles away.
The area around Refinery 266 is well populated and
industrialized. It would appear that all of the plant's output
is delivered within a radius of twenty or thirty miles. The
refinery appears to have a significant transportation cost advan-
tage over other refineries - perhaps twenty cents per barrel
of product. This would be true regardless of the level of
Federal protection against iiaports. So the revised guideline
cost is not enough to cause this refinery to cease operation.
h. In summary, the impact of revised guidelines on
topping refineries will depend strongly on the future level of
Federal subsidies for small refiners. The current level for
firms processing less than ten thousand barrels per day is about
95 cents per barrel crude oil processed. If the subsidy con-
tinues at even a fraction (one-third ?) of this level, revised
guideline costs will probably cause no refineries to shut down.
If, however, the small refiner subsidy is eliminated,
it is anticipated that the following topping refineries might
choose to shut down rather than incur revised Option 2 PGES
costs. (They would not be affected by Level 1, Level 2, or
Option 1 revised guideline costs.)
Refinery Capacity, Thousand
Code Barrels per Day Located Near
193 3.2 Houston
195 1. San Antonio
231 10. Salt Lake City
Total 14.2
1 Ibid.
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i. The asphalt refinery, Code 52, is located at
the east end of the panhandle of Florida. It faces 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 3000 barrels per day in 1970 to 5000 barrels
per day by 1974 and to 9000 barrels per day by 1979. Almost
half of 1976 product outturn was asphalt. Some military jet
fuel was also manufactured, but no gasoline. Imported Vene-
zuelan crude oil accounted for all raw material requirements.
Because Refinery 52 is located on the Gulf of Mexico,
it faces competition from all other Gulf Coast asphalt manufac-
turers. And when U.S. refiners' crude oil acquisition costs
are allowed to equalize with offshore refiners' costs, this
plant will again face competition from Caribbean refiners, as
it did before the OPEC price increase of late 1973. However,
it is important to point out that finished asphalt is much
more expensive to ship and to store than is asphaltic crude
oil. So relatively short distances create significant trans-
portation/storage cost advantage in the asphalt manufacturing
industry.
It seems highly unlikely that Refinery 52 would be
unwilling to incur revised guideline costs. The costs are
moderate, the refinery appears to be well located, and it has
had sufficient confidence to triple capacity over the last eight
years.
D. Summary of Economic Impacts of Revised Guidelines
1. Production Effects
The analysis indicated that no petroleum refineries
are likely to be shut down under the Level 1, Level 2, or
Option 1 guidelines. It also identified three small petroleum
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refineries that, in the absence of a small refiner subsidy,
might elect to shut down rather than to incur revised
Option 2 PSES costs. However, if a small refiner subsidy
is continued they would probably incur the costs and continue
operation.
These refineries account for one-thousandth, i.e.,
0.1 percent, of total industry capacity. Industry output
would not be affected if they do shut down.
2. Employment Effects
Under Level 1, Level 2, or Option 1 there would be
no adverse employment effects because no petroleum refineries
are likely to shut down. It is estimated that 100 to 150
persons are employed in the three small refineries that may
shut down under the Option 2 guidelines.
New jobs will be created by revised guidelines in
existing refineries. The new effluent treatment facilities
will need to be operated, maintained, and supervised. It
appears that about 50 to 850 jobs will be created.1 Net,
an increase of 50 (Level 1/Option 1) to 725 (Level 2/Option
2, net of three shut down refineries) is expected.
3. Community Effects
The three refineries that may shut down under
PSES Option 2 are all small employers located in or near
metropolitan areas. Hence, no community impacts are expected
if the plants do shut down.
4. Balance of Trade Effects
There apparently will be no balance of trade
effects of revised guidelines.
-'¦Chapter V, Section D
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79.
CHAPTER Vll
LIMITATIONS OF THE ANALYSIS
A. Limitations
The conclusions of this report rest on four principal
foundations - assumptions about future Federal Government
policy, refiners' responses to the Section 308 questionnaire,
cost estimates, and the methodology utilized for the economic
impact analysis. If future Government policy turns out to be
substantially different than is assumed, the conclusions of this
report could be invalidated. But changes in the other three
areas are unlikely to substantively change the conclusions.
As was discussed in the text, there is no settled
Federal policy for protecting 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 there is no such actual policy. Nor is there any clear
indication of what the refinery protection policy will eventually
be, or when it might become effective.
The cost estimates depend significantly on refiners'
responses to the Section 308 questionnaire. As noted in the
text, twenty-one refineries did not respond to the questionnaire.
It is entirely possible that one or more of the non-responders
could be high cost plants that would have been forecast to be
shut down by the revised guidelines. Also, some discrepancies
were noted between data reported in answer to the questionnaire
and the same data reported to the Department of Energy and the
Oil & Gas Journal. However, none of the noted discrepancies
affected the analysis or conclusions. Finally, the data are
for 1976 - undoubtedly many refinery characteristics have changed
since then.
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The cost data used herein, like all cost data, are
only estimates based on (necessarily) incomplete information.
Additionally, these data are based on a statistical regression
model. All such models reflect errors in the data and, to some
extent, perceptions of the modeler - none can be "true". Finally,
land costs at all refineries were assumed to be negligible. It
is probable that some refineries face substantial costs for the
land needed for effluent treatment facilities.
B. Sensitivity Analysis
If costs to conform were increased by twenty percent,
the number of refineries with compliance costs greater than 4.1
cents per barrel crude oil processed (Exhibit 7) would increase
from 22 to 40. And the number of (non-asphalt) refineries with
compliance costs greater than process unit values (Exhibit 8)
would increase from five to eight. Two of the added three
refineries have already been analyzed in detail because compli-
ance costs and process unit values were equal. The third -
refinery 130 - is quite well located and appears to enjoy a
significant transportation advantage relative to its competition.
The preceding paragraph shows that the conclusions
of this report are not sensitive to moderate changes in cost
estimates.
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