EPA-440/1 -77-002
APRIL 1977
ECONOMIC ANALYSIS OF
INTERIM FINAL PRETREATMENT
STANDARDS FOR THE
Petroleum Refining Industry
QUANTITY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Water Planning and Standards
Washington, D.C. 20460
\
UJ
C3
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EPA-440/1-77-002
ECONOMIC ANALYSIS OF INTERIM FINAL PRETREATMENT
STANDARDS FOR THE PETROLEUM REFINING INDUSTRY
Contract No. 68-01-4316
OFFICE OF WATER PLANNING AND STANDARDS
ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D. C. 20460
April 1977
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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) 755-6906.
This document will subsequently be available
through the National Technical Information Service,
Springfield, Virginia 22151.
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This report has been reviewed by the Office of Water
Planning and Standards, EPA, and approved for publication.
Approval does not signify that the contents necessarily
reflect the views and policies of the Environmental Pro-
tection Agency, nor does mention of trade names or com-
mercial products constitute endorsement or recommendation
for use.
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PREFACE
The attached document is a contractor's study pre-
pared 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 pretreatment standards to be estab-
lished under section 307(b) of the Federal Water Pollution
Control Act, as amended.
The study supplements the technical study (EPA
Development Document) supporting the issuance of interim
final regulations under section 307(b). The Development
Document surveys existing and potential waste treatment
control methods and technology within particular industrial
source categories and supports certain pretreatment standards
based upon an analysis of the feasibility of these standards
in accordance with the requirements of section 307(b) of the
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 technologies. This study investigates the effect
in terms of product price increases, effects upon employment
and the continued viability of affected plants, effects upon
foreign trade and other competitive effects.
The study has been prepared with the supervision and
review of the Office of Water Planning and Standards of EPA.
This report was submitted in fulfillment of Contract No. 68-01-
4316 by Sobotka & Company, Inc. Work was completed as of
February 1977.
This report is being released and circulated at
approximately the same time as publication in the Federal
Register of a notice of interim final rule making under
section 307(b) of the Act for the subject point source
category. 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 interim 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 contractor who studied the subject industry. It can-
not be cited, referenced, or represented in any respect in
any such proceeding as a statement of EPA's views regarding
the subject industry.
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TABLE OF CONTENTS
Page
I. EXECUTIVE SUMMARY
A. Introduction 1
B. Data and Methodology 2
C. Results and Conclusions 3
II. INDUSTRY DESCRIPTION
A. Overview of the U.S. Petroleum Refining
Industry 6
B. Determinants of U.S. Petroleum Product
Prices 16
III. METHODOLOGY
A. Basis of Plant Segmentation 21
B. Method of Determining Impact 21
IV. ESTABLISHMENT OF PRETREATMENT STANDARDS
A. Pollutants Considered 24
B. Technology to Remove Pollutants 24
V. EFFLUENT PRETREATMENT COSTS
A. Capital and Annual Costs 26
B. Segmentation of Indirect Dischargers 31
VI. IMPACT ANALYSIS
A. Impact with Growth in U.S. Refining
Capacity 33
B. Impact without Growth in U.S. Refining
Capacity 36
VII. LIMITS OF THE ANALYSIS 39
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EXHIBITS
Page
1. INDUSTRY SUMMARY 4
2. SCHEMATIC FLOW DIAGRAM OF PETROLEUM REFINERY
A. PETROLEUM PRODUCT MANUFACTURING 10
3. SCHEMATIC FLOW DIAGRAM OF PETROLEUM REFINERY
B. POLLUTANT COLLECTION AND TREATMENT 12
4. GROWTH OF REFINING CAPACITY AND CHANGES IN
NUMBERS OF REFINERIES 1968-1974 14
5. REFINERY INVESTMENTS REQUIRED TO MEET PRE-
TREATMENT STANDARDS 27
6. ANNUAL COSTS REQUIRED TO MEET PRETREATMENT
STANDARDS 29
7. MAXIMUM POTENTIAL COSTS OF SEGMENT "Y" 35
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CHAPTER I
EXECUTIVE SUMMARY
A. Introduction
Pretreatment standards are applicable to petroleum
refinery waste waters which are discharged to Publicly Owned
Treatment Works (POTW). Refineries that discharge to POTW
are called indirect discharging refineries. This study
identified 26 petroleum refineries, out of a total of about
270 in the U.S., which produce waste water discharge that is
processed by POTW. These 26 represent about 10 percent of
domestic crude oil processing capacity. A total of 13
different POTW receive water effluents from these refineries.
The Federal Water Pollution Control Act Amendments
of 1972 contain two sections which address pretreatment. Section
307(b) requires the Administrator of the Environmental Protection
Agency (EPA) to promulgate regulations establishing pretreatment
standards for existing refineries for those pollutants which are
determined not to be susceptible to treatment by POTW or which
would interfere with the operation of POTW. Section 307(c)
provides that the Administrator shall promulgate similar pre-
treatment standards for new refinery sources.
EPA commissioned Burns and Roe Industrial Services
Corp., an engineering contractor, to perform a study to determine
the technology and associated costs of pretreatment and to
recommend a set of pretreatment standards to be promulgated.
Sobotka & Company, Inc. (SCI) was retained by EPA to perform
an analysis of the economic impact on the petroleum refineries
which would be affected by implementation of the recommended
standards.
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2.
B. Data and Methodology
The principal data source for the SCI analysis was
the work product of Burns and Roe1'. This document contains
recommendations for final pretreatment standards, a technical
profile of the specific refineries which would be impacted by
each pollutant considered in the recommended standards, and the
capital and annual costs for pretreatment in these refineries.
Because the data base and analyses incorporated in the Burns
and Roe draft report were subject to minor revision during the
period that the SCI analysis was made, SCI made some adjustments
to certain values that appear in the Burns and Roe draft. These
adjustments are noted in the appropriate places of this report.
Other sources of data for this analysis include SCl's
previous study of the impact of all Federal environmental
regulations on the U.S. petroleum refining industry. In addition,
SCI staff had oral and written communications with Burns and Roe
and with several POTW.
The impact on indirect discharging refineries of pre-
treatment costs was determined by comparison with direct discharging
refineries. In our previous study,3' SCI developed waste water
effluent treatment costs for 89 small existing direct discharging
refineries. These costs were used as a standard against which
the indirect discharging refineries' waste water treatment costs
were compared. Indirect discharging refinery costs include pre-
treatment costs and POTW user charges. Pretreatment costs were
taken from Burns and Roe's work. User charges were furnished by
several POTW which we contacted.
1) "Draft - Supplement for Pretreatment to the Development Docu-
ment for the Petroleum Refining Industry, Existing Point Source
Category" EPA 440/1-76/083, December 1976.
2) "Economic Impact of EPA's Regulations on the Petroleum Refin-
ing Industry", EPA 230/3-76-004, April 1976.
3) Ibid.
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3.
C. Results and Conclusions
It was found that for every category of refineries
there were more than ten direct discharging plants which will
incur effluent treatment costs more than three times as large
as those incurred by the most affected indirect discharging
refinery in the group. Given this fact, it is clear that pre-
treatment costs, in themselves, will not adversely affect the
competitive position of indirect discharging refineries. It is
also clear that the absolute levels of pretreatment costs that
would be experienced by the most affected indirect discharging
refineries represent small fractions of the value of those plants.
An industry summary of the results of these analyses
is presented in Exhibit 1. As shown in the Exhibit, the economic
impacts of pretreatment standards on the affected plants will be
small. The 26 refineries which discharge waste waters to POTW
are subdivided into three segments. Capital expenditure require-
ments represent 0.7 percent of the total replacement value of
the plants within the most severely impacted segment (segment "Y").
And the total capital expenditures for pretreatment facilities
for all indirect dischargers as a group represent 0.2 percent of
replacement value of the entire group.
The aggregate annualized costs for all the plants within
segment MY" represent 0.3 percent of sales within that segment
and total annual costs for all indirect dischargers represent less
than 0.1 percent of sales within the entire category.
There are no price changes anticipated within the U.S.
petroleum refining industry as a result of imposition of pre-
treatment standards. There should be no effects on industry
growth or U.S. balance of payments. Furthermore, SCI does not
believe that any of the impacted plants would close as a result
of imposition of pretreatment standards.
The U.S. petroleum refining industry presently employs
about 150,000 people. We expect that imposition of pretreatment
standards would result in the employment of an additional 10 to
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EXHIBIT 1.
INDUSTRY SUMMARY
Industry
SCI Code 2911
Number of plants in segment
Percent of total plants in industry
Number of plants indirect discharging
Percent of total indirect discharging plants
Number of plants wi-h complete pretreatment in place
Percent of total plants in segment
COST OF POLLUTION ABATEMENT2'
(Millions of Dollars)
Capital costs for segment
Total capital cost
Total capital expenditures as percent of average annual
investment
Total capital expenditures as percent of replacement value
Annualized costs for segment
Total incremental increase including capital charges
Total incremental increase excluding capital charges
Total incremental increase including capital charges as
percent of sales
1) Segment Definition
HV"
A
3
1%
3
12%
3
100%
0
0
0
0
0
0
Segments
"Y"
5
2%
5
19%
0
0%
$2.8
17%
0.7%
$1.7
$1.0
0.3%
_ _ _ j_
;
"Z"
18
7%
18
69%
0
0%
$4.6
3%
0.1%
$1.7
$0.7
<0.1%
Total of
Indirect
Dischargers
26
10%
26
100%
3
12%
$7.4
5%
0.2%
$3.4
$1.8
<0.1%
2)
"Y" Indirect Discharger - five most severely impacted plants as measured by unit capital
requirements for pretreatment facilities
"Z" Indirect Discharger - balance of category
Includes costs not yet incurred to meet pretreatment standards controlling sulfides,
ammonia, and oil and grease.
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5.
50 people to operate and maintain new facilities; depending on
whether phenol and/or chromium standards are also included.
This level of employment change (which will be scattered through-
out the U.S.) will have negligible community impacts. We do not
believe that any plant affected by pretreatment standards would
forego any other investment opportunity due to the capital require-
ments for pretreatment equipment. Hence, there is no offset
against the above estimate of employment increase.
To summarize, the combination of pretreatment costs
plus POTW user charges will be significantly less than the water
effluent treatment costs that will be experienced by a large
fraction of direct discharging refineries. Thus, imposition on
the petroleum refining industry of water effluent treatment
standards will, in most cases, improve the competitive position
of indirect discharging plants.
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6.
CHAPTER II
INDUSTRY DESCRIPTION
A. Overview of the U.S. Petroleum Refining Industry
Introduction
The economic well-being of the petroleum refining
industry is influenced by United States and foreign government
policies unrelated to environmental considerations. These
policies have been in a state of flux for some years.
Until recently, the output of the refining industry
had grown at a fairly steady rate. This would not have happened
in the absence of economic incentives necessary to attract
capital to the industry. As long as normal market incentives
prevailed, the viability of firms within the industry was governed
by their relative economic efficiency. With the imposition of
price controls, and mandatory product and crude oil allocations,
normal economic incentives ceased functioning. Also the Congress
is now considering legislation which would significantly restrict
petroleum companies' allowed areas of operations. For example,
proposals which would prohibit crude oil producers from marketing
oil products have been made.
The economic impact of the non-market rules now in
effect is very large. For example, a refiner who, under the
current crude oil entitlement program, is granted a substantially
larger quota of lower priced lower tier crude oil than he would
be able to purchase on the open market is given a great deal of
assistance by government. On the other hand, a refiner who,
because of price controls, cannot charge market clearing prices -
even if the effect of price controls is to hold average prices
only a few percentage points below equilibrium levels - may have
his income reduced substantially below the levels that would
prevail in a free market.
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7.
The present regulatory government programs imposing
price controls and crude oil allocations are scheduled to end
in 1979. At that time, a protective tariff or subsidy program
may be instituted as a replacement because otherwise U.S.
refineries would be at a competitive disadvantage relative to
plants located abroad. The level of tariff or other support
will determine if the U.S. refining industry will grow, will
maintain present operating levels or will experience attrition.
If the industry as a whole is growing, and capital is
being invested in new or growth facilities, then it is reasonable
to expect that aggregate product prices (and hence, refiner's
margins) must be sufficiently high to attract capital to the
industry. And, a normal rate of return must be earned on the
environmental capital invested as a necessary part of the growth
facilities. Because products from new or existing facilities are
indistinguishable, their prices must be the same. So that portion
of product price that reflects the full cost (including return on
investment) of environmental control in new growth facilities
will partially or totally offset the costs of environmental control
in existing facilities.
However, if the industry is not growing and no capital
is required for the expansion of existing facilities or the con-
struction of new plants, full recovery of the costs of environ-
mental capital may not take place. Under these conditions a
portion of the environmental expenditures to bring existing
facilities into conformance with environmental standards might
have to be absorbed by the refining industry, which would tend
to magnify the economic difficulties of those refiners who al-
ready are at a cost disadvantage due to size, location or type
of equipment.
This study is limited to assessing the economic
impact of pollution abatement costs to meet effluent pretreat-
ment standards in those petroleum refineries which discharge
waste water to Publicly Owned Treatment Works (POTW). Only a
small fraction of refineries discharge to POTW. None of the new
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8.
large refining capacity built in the U.S. over the last ten years
does so. So it appears that petroleum product prices will be
determined by the costs of direct discharging refineries. Con-
sequently, refineries that discharge to POTW will be better off
or worse off than direct discharging refineries depending on
whether the sum of pretreatment costs plus POTW user charges are
less or greater than the costs of water treatment incurred by
direct dischargers0
Industry Operations
The petroleum refining industry in the United States
and its possessions consists of about 270 plants, owned by about
140 firms, and located in 40 of the 50 states, Guam, Puerto Rico,
and the Virgin Islands. The refineries have a replacement value
in excess of 35 billion dollars. The U.S. refining industry
employed about 154,000 persons in 1975.^'
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. The industry manu-
factures hundreds of distinguishably different products which,
from the viewpoint of environmental control, may be grouped into
four broad product classes: gasoline, middle distillates (distillate
fuel oil, diesel fuel, jet fuel, etc.), residual fuel oil, and
all other (LPG, lubricants, coke, asphalt, etc.).
Foreign, Federal, state and local governments all
influence the oil product market. In recent years the Federal
government's major influence has been through taxes, price
controls and tariffs (fees) on imports of crude oil and products.
Price controls hold prices down and discourage investment. In
the absence of price controls tariffs have the opposite effect.
Government also influences the market for petroleum
products through the imposition of environmental standards. This
1) "Basic Petroleum Data Book. Petroleum Industry Statistics",
American Petroleum Institute,July iy/b.
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9.
can take the form of direct specification of product character-
istics; e.g., sulfur content in residual oil. Or it may take
the form of imposing environmental standards on petroleum
product users which affect the nature of the products they
demand. For example, the need to reduce auto emissions has
resulted in a requirement for unleaded gasoline.
The Manufacturing Process
Although a typical oil refinery is technically complex,
the manufacturing process is conceptually simple.
Crude oil is the primary raw material used in refining.
Crude oils are liquid mixtures of many carbon-containing chemical
compounds. Crude oils differ from one another in the con-
centration of the various compounds. In refining, crude oil
is first separated into several fractions of varying molecular
sizes. The chemical composition of some of these fractions is
then altered by changing their average molecular size. Other
fractions are further processed to alter the shape or structure
of the molecules. Most of the original and the altered fractions
are "treated" to make innocuous or to remove impurities, notably
sulfur. Treated fractions are blended to produce finished products,
To these may be added various substances, known as additives,
to impart certain desirable properties. A schematic flow
diagram of a typical refinery is shown in Exhibit 2.
In refinery operations, certain polluting materials
may be released into the environment. The pollutants are by-
products of the various refinery processes.
The principal pollutants arise as follows:
a. Hydrogen sulfide (H~S) is present in some crude
oils and is formed in hydroprocessing (catalytic
reforming, hydrotreating, and hydrocracking) and
cracking. H^S is either recovered and converted to
elemental sulfur,or burned. Burning forms sulfur
oxides (primarily 802) which are air pollutants.
Sulfur oxides are also formed in the combustion
of sulfur-containing liquid refinery fuels. If these
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SCHEMATIC FLOW DIAGRAM OF PETROLEUM REFINERY
A. PETROLEUM PRODUCT MANUFACTURING
LUBRICATING
Oil
MANUFACTURE
RUN NAPHTHA
LIGHT STRAIGHT
— HEAVY STRAIGHT RUN GAS OIL
HYDRO-
CRACKING
J—> TO CATALYTIC REFORMItW
VACUUM
DISTILLATION
NAPHTHA
CAT CRACKED
VACUUM
BOTTOMS
CAT. CRACKED
HEAVY 6AS OIL
COKING
OR
THERMAL i
TO NAPHTHA HYDROGEN TREATER
TO CATALY TIC O« HYDRO CRACKER
COKE OR RESIDUAL FUEL OIL
LCRACKJNGJ
1
X
K
M
W
M
H
ro
TREATING PROCESSES
(1) AQUEOUS LIQUID
(2) AQ. LIQ. OR HYDROGEN
REFINERY
FUEL GAS
PROPANE (LPG)
PREMIUM
GASOLINE
REGULAR
GASOLINE
KEROSENE &
JET FUEL
•DIESEL FUEL
•HEATING OIL
RESIDUAL
FUEL OIL
ASPHALT
LUBRICATING OILS
• OPTIONAL PRODUCTS
i
; OPTIONAL PROCESSES
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11.
fuels also contain nitrogen compounds, the formation
of NO is enhanced. This NO , when combined with the
x x
small amount of SOo formed from burning sulfur com-
pounds in the fuel, tends to be the principal cause
of stack plumes from refinery furnaces.
b. Hydrocarbon vapors can escape from refinery tanks
containing crude oil, gasoline, and volatile inter-
mediate products. Other sources of hydrocarbon vapor
emissions are tank truck and tank car loading, volatiles
unloading facilities, and oil separators in the waste
water effluent treating system.
c_. Substances which create a biological oxygen demand
(BOD) in waste water are formed in catalytic and
thermal cracking. One class of these substances is
phenolic compounds. Also most of the solvents
(phenol, furfural, etc.) used in manufacturing solvent-
refined lubricating oils create BOD.
d. Entrained hydrocarbons (oil and grease) and dis-
solved contaminants such as ammonia, sulfides, light
mercaptans and salts (from crude oil and cooling water
treatment) are found in refinery waste water streams.
Also trace metals such as chromium may be present in
refinery boiler and cooling water blowdown. Some con-
taminants may cause the pH (acidity) of refinery
waste water to be outside permissible limits.
Various processes are used to control the emission of
pollutants. The schematic flow diagram in Exhibit 3. shows
the collection and treatment of pollutants produced in each
process.
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SCHEMATIC FLOW DIAGRAM OF PETROLEUM REFINERY
B. POLLUTANT COLLECTION AND TREATMENT
SOUR GAS
SULFUR
LEGEND
WASTE WATER
SOUR WATER
SOUR GAS
•• HYDROGEN SUIFIDE (HjS)
UJUIINO «______4i
TOWER SLOWDOWN^ WASTE
~~~~WAfE~R~* '
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13.
Industry Structure
Crude oil is by far the most important raw material
used by the refining industry. Natural gasoline and butanes,
liquid products of the natural gas industry, furnish about 6%
percent of refinery intakes. There are no other significant
raw materials. Currently about 60 percent of industry raw
material is of domestic origin; 40 percent is imported.
Oil refineries are categorized by size and by the range
of their products. There is also considerable variation in age
of refineries. But additions to and modifications of plants are
the industry's principal form of expansion.
The Exhibit on the following page shows the growth of
refining capacity and the changes in the number of refineries
in the period 1968-1974.
Multiple plant operations are commonplace in the
industry. As of December 1, 1974, the 19 largest firms, each
of which has a total refinery capacity of over 200,000 barrels
per day, operated 111 refineries. These 111 plants accounted for
79 percent of the industry's capacity. Half of all industry
refineries are smaller than 26,000 barrels per day. They
account for only 8 percent of industry capacity.
Smaller refineries are frequently located within isolated
crude oil producing areas and/or they serve local, moderately-
sized marketing areas far from alternate product supply sources.
A common technology is used throughout the industry.
The differences that do exist are small and probably rot signi-
ficant in terms of a plant's ability to meet waste water quality
standards economically. However, there are differences in the
extent to which environmental control equipment has been installed
to date.
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Growth of Refining Capacity and Changes
in Numbers of Refineries
1968 - 1974
Refineries Operating
1/1/68
Refineries Operating
1/1/68 & 12/1/74
9T3
10764.5
sanded Capacity
'68 - 12/74
3316.8
773
11345.0
233
14081.3
•i & Reactivated
Refineries
41 >
960.2
U.S. &
Puerto Rico
ied Data Base
•^
784.3
1
274
15041.5
^
All Refineries
Plants Closed Closed
Since 1/1/68 Since 1/1/68
—5— 4Q ami
580.5
36
580.5
i • v
4
No Capacity
9
28.8
Plants Merged Asphalt &
Into Other Lube Plants
Refineries Closed
KEY
27?
15825.8
Np,, of Rpfjn
Combined Cap
Thousand Bar
Per Calendar
All Fuel Simple Fuel
Refineries Refineries
Closed Closed
•— 27 ,> 11
** 551.7 29.0
\
16 11
522.7 471.0
Fuel Refiner
•' Closed by Si
t- Large birm
51 .7
Other Fuel
Refineries
Closed
__-,—.. M
M
IPT-f pg H
acity 4>
rels
Day
(—•
-f>
*
Guam, Hawaiian FTZ,
Virgin Islands
Refineries Operating
12/1/74
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15.
Refinery employment as a whole has been fairly stable.
In 1964, there were 150,000 employees and in 1975, 154,000.*'
The imposition of environmental regulations tends to increase
the industry's demand for labor.
It is impossible to analyze the financial structure of
the petroleum refining industry using published data. Only a few
firms, and none that are typical of the industry, are exclusively
or even primarily in the refining business. However, it is im-
portant to note that capital has been attracted to the industry
to finance growth and replacement. This indicates that earnings
in the past were at an adequate level.
Due to uncertainties about future demands and price
controls, it is not possible to make a useful estimate of the
refining industry's capital requirements for expansion and plant
modernization in the years to come. In 1973/75, petroleum com-
panies invested about 1.5 billion dollars per year in refineries
2)
in the U.S. x Roughly 10 percent of domestic capital expendi-
tures in 1973/1975 by oil companies was for refineries. Total
domestic refinery investment in those years by these companies
was about 22 percent of worldwide refining investment.
Were it not for price controls, the domestic market
for wholesale oil products would be competitive in the economist's
meaning of the term. Prices on the various unbranded markets in
the absence of effective price controls typically are close to
short-run marginal costs. This indicates that the industry is
highly competitive. But price controls have been in effect on
domestic products most of the time since 1971.
T)American Petroleum Institute, op. cit.
2) Chase Manhattan Bank, Capital Investments of the World
Petroleum Industry, December, 1976.
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16.
Prior to the oil embargo, the industry was in transi-
tion from a quota system to a tariff system via a price control
system. As a result of domestic price control, a significant
disparity between world and average domestic prices now exists.
And the combination of a three-price crude oil market (upper
and lower tier domestic, and foreign), with a system of entitle-
ments to purchase lower-priced, lower tier crude oil, makes it
impossible to generalize about current market conditions.
B. Determinants of U.S. Petroleum Product Prices
As stated in the previous section of this chapter,
price controls have regulated the U.S. refining industry with
various degrees of severity since 1971. However, during the
periods prior to any price controls (and for those specific
products that have been unregulated in the 1970*s) the domestic
market for wholesale oil products was competitive in the econo-
mist's meaning of the term: Long term contracts were consummated
at prices reflecting fully allocated costs of product supply from
new facilities (long run marginal costs). Prices in the various
unbranded and/or spot markets were close to short run marginal
costs which may be higher or lower than long run costs.
Thus, product prices have been cost-based. And they
were determined by marginal increments of supply - both for the
short run and over the longer term as well. Regional product
price differences exist in the U.S. which primarily reflect
transportation costs to ship products and/or crude oils via pipe-
line, marine, rail or truck. Also, within any specific product
category price differences may exist which reflect the costs of
increasing product qualities. Examples of this are octane
numbers of gasolines or sulfur contents of fuel oils.
Several exogenous factors are important determinants
of future U.S. refined oil product prices. First, both the
short and the long run supply curves for oil products are upward
sloping. So, higher prices will result if the demand for products
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17.
increases over the years than if demand remains static or
decreases. Second, because product prices are cost-based,
controls on crude oil prices will lead to lower product prices.
Controls on refiners'margins or finished product prices may or
may not affect prices, depending on when, at what level, and by
what formulae they are set. As of early 1977, industry sources
indicate that the prices of some products (e.g., LPG) are being
held down by controls, while others (e.g., regular grade gasoline)
reflect market conditions. Third, offshore refineries might be
able to supply products to the U.S. market at lower prices than
U.S. plants. This could be for a variety of reasons; e.g., off-
shore refining costs could be lower than U.S. costs; offshore
refineries located in OPEC countries could be given a price
concession for indigenous crude oil (to enable the crude oil
producing country to "cheat" on its "fair share" of cartel
production); etc. Fourth, the U.S. market could be protected
from offshore competition by tariffs or similar measures; e.g.,
domestic crude oil price controls.
Three levels of protection for domestic refineries are
of analytical interest. A level of protection can be designed
that would be just high enough to preserve the industry at
about its current size. This level would equalize the costs of
imported product with the out-of-pocket costs of marginal; i.e.,
least efficient, U.S. refineries.
The next interesting level of protection would be that
designed to encourage growth of the U.S. refining industry at a
rate sufficient to supply the total growth of the demand schedule
for refined products. The last, and highest, level of protection
would encourage refinery capacity to grow more rapidly than
product demand so as to eventually eliminate the importation of
petroleum products. This highest level of protection will not
be considered further for we know of no responsible advocate for
a policy of eliminating current product imports.
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18.
It is reasonable to premise that the demand for oil
products in the U.S. will grow for at least the next decade1',
and that the U.S. refining industry will be protected (by tariff
or domestic crude oil price controls) from major attrition due
to import competition. The determination of future oil product
prices under conditions of growth and of no growth will be
discussed below.
Price differentials between products reflect two factors;
first between those products among which substitution is possible
(such as kerosene, distillate fuel oil and various grades of
residual fuels) form value premiums will exist in the market
place to reflect differential costs associated with handling and
consumption. Second, differential prices between non-substitutable
products reflect refining costs to upgrade product quality (such
as catalytic reforming of naphtha to produce motor gasoline) or
to chemically convert from one class of petroleum products to
another (such as catalytic cracking of residual and/or heavy
distillate oils to produce motor gasolines and lighter distillates)0
Complex refinery simulation computer models are often used to
perform product value or cost calculations.
Price Determinations With Growth in U.S. Refining Capacity
If new refinery capacity is to be built, investors must
be reasonably confident of earning a satisfactory return on their
investments for this capacity. We believe that a 12 percent after-
2)
tax rate of return ' is an appropriate nominal value to use for
petroleum refining investments. So, product prices in aggregate
must be at a level that covers raw material acquisition costs,
operating and maintenance costs, environmental control costs,
taxes, and other cash costs; plus recovery of, and return on,
capital. (it is useful to state again that new refineries will
not be built unless product prices reflect full effluent control
costs.)
1) Federal Energy Administration, 1976 National Energy Outlook,
page xxv.
2) Gerald A. Pogue, Estimation of the Cost of Capital for Major
U.S. Industries, November 1975, EPA~230/3-/b-001.
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19.
Price Determination Without Growth in U.S. Refining
Capacity
In the usual case, "no growth" means that there is no
year-to-year increase in the demand schedule. In such a situation,
the price of products equilibrates at a level equal to the per-
unit revenue required to just barely keep the marginal (least
efficient, highest cost) manufacturing plant in business. This
price is slightly above the cash-out-of-pocket cost necessary to
procure raw materials and operate the plant. A minimum level of
cash flow is required for investment in new equipment to replace
worn out parts within the facility and/or to meet safety or
environmental standards that might be imposed. SCI has made a
previous internal study to determine this minimum level of cash
needs. Results indicated that on average, a typical firm must
generate an annual after-tax cash flow of about four percent of
its replacement value to permit continued operation.
The case of interest here is not a usual "no growth"
case. Here, the demand schedule for petroleum products is
increasing from year to year. But there is no growth in refinery
capacity because product prices are too low to justify invest-
ments in new capacity. Prices will be low if no (or low) import
protection (tariff, domestic crude oil price controls, etc.) is
afforded to U.S. refiners. This is because existing offshore
refining capacity is much larger than is needed to meet offshore
consumption for several years. ' Consequently, world prices
will reflect short run supply conditions. That is, world prices
will apparently remain at a level only slightly above cash-out-
of-pocket costs. '
In the absence of import protection, U.S. refiners would
face the world price. If offshore refinery (cash) costs are even
slightly lower than U.S. refinery costs, substantial attrition of
the U.S. industry would be expected. Of course, if offshore
1) Citibank, Monthly Economic Letter, September 1976, page 7.
2) Despite this unattractive price prospect, Persian Gulf countries
are building new refineries. This additional capacity will
prolong the time of low prices.
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20.
costs are slightly higher than U.S. costs, the U.S. industry
would be expected to maintain its capacity at near the current
level.
Administration and Congressional policy and actions
over the past three years make it very clear that significant
attrition of the U.S. industry would not be permitted. So
the appropriate no growth case to assume for this study is one in
which only nominal attrition of existing U.S. refineries takes
place.
Capital expenditures for environmental facilities in
those plants barely remaining in operation must generate new
product revenues sufficient to justify their installation. Thus,
product prices are expected to increase to cover essentially
the full ' environmental costs for those plants remaining in
business. Since industry prices will be predominantly set by
direct dischargers, refinery prices are expected to increase to
reflect most of the costs required to meet future waste water
standards imposed on direct dischargers.
1) Conceptually, higher product prices will result in reductions
in quantities consumed which will cause further attrition in
the number of plants continuing operation. The relevant
environmental costs to consider are those of the least
efficient plants remaining in business after consideration
of the reduced volumes consumed.
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21.
CHAPTER III
METHODOLOGY
A. Basis of Plant Segmentation
This study identified 26 U.S. petroleum refineries '
which discharge into Publicly Owned Treatment Works (POTW).
Three of these will experience no new capital investment require-
ments or increase in operating costs upon implementation of
pretreatment standards controlling sulfides, ammonia and oil and
grease. So these three plants will be unaffected by the imposi-
tion of pretreatment standards. The other 23 refineries comprise
the plants that will be impacted by pretreatment standards. For
purposes of analysis these can be divided usefully into two
segments on the basis of severity of the impact.
It was found that five of the refineries discharging
to POTW will experience capital costs of greater than ten dollars
2 )
per barrel of daily crude oil processing capacity to meet pre-
treatment standards for sulfides, ammonia and oil and grease.
These five most affected plants comprise the segment that was
examined in the most detail.
B. Method of Determining Impact
It was discussed in Chapter II that growth in refinery
capacity is expected to take place if cash flow per barrel of
crude oil processed (product revenue less cash costs) is high
enough to generate an adequate return on investments in new
capacity. The required value of cash flow per barrel can be
derived from data about new refinery construction costs, the
income tax level and the cost of capital. SCI derived the unit
cash flow required for growth in our earlier study of the impact
1) The Development Document published by Burns and Roe identifies
27 indirect discharging plants, but one of these was later
determined to be using deep well injection for effluent disposal,
2) A barrel is 42 U.S. gallons (159 liters).
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22.
of EPA's regulations on refineries. ' Using the new refinery
unit cash flow as a starting point, estimates of unit cash
flow were derived for 89 small refineries. (In essence, the
new refinery value was adjusted to reflect the different product
mix, operating costs and crude oil costs that will be faced by
the small refineries.)
It was determined that the unit cash flow of the
indirect discharging refineries most highly impacted by pre-
treatment standards would lie within the range of cash flows
i.stiu.aLed for the 89 small refineries. The unit costs of meeting
^it-treatment standards were then compared against the unit cash
flow estimates to determine the impact of the standards in a
growth environment.
A different comparison was used to judge the impact
in a no growth environment. In this case the impact of pre-
treatment standards on indirect discharging refineries was
determined by comparing the waste water effluent treatment costs
to be incurred by these plants with the treatment costs to be
incurred by direct discharging refineries. Direct discharging
refineries became subject to BPCTCA (best practicable control
technology currently available) regulations in 1977, and will
become subject to BATEA (best available technology economically
achievable) regulations in 1983. Direct discharger costs for the
2 ^
89 small refineries were developed in our earlier study. ' As will
be shown in Chapter VI, the costs of meeting direct discharge stand-
ards could be as high as 45 cents per barrel of crude oil processed,
Pretreatment costs were taken from the Burns and Roe
3)
report. ' The charges levied by POTW on their users were
ascertained by SCI through telephone calls and letters. These
T)Op. cit.
2) Ibid.
3) Op. cit.
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23.
data were combined to yield total pretreatment plus POTW costs
for each of the five most affected refineries.
The combined total water effluent treating costs to
be faced by the five highest cost indirect discharging refineries
were compared to the costs that will be faced by direct discharging
refineries. These latter costs were developed by SCI as part of
our April 1976 study for EPA. '' Costs of refineries with similar
processing configurations were compared because configuration is
a useful proxy for value added by refining,
As will be discussed in Chapter VI, it was found that
at least 35 direct discharging refineries will have waste water
effluent treating costs at least three times greater than that
of the highest cost indirect discharging refinery. Given this
finding, it was evident that the implementation of effluent
treatment standards will tend to improve the competitive position
of indirect discharging refineries. And since all 26 indirect
discharging refineries represent only about ten percent of
industry capacity, it was also obvious that pretreatment standards
would have neither price nor balance of payment effects,
1) Op. Git.
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24.
CHAPTER IV
ESTABLISHMENT OF PRETREATMENT STANDARDS
A. Pollutants Considered
The Burns and Roe report identified five pollutants
in refinery effluent waste water which may be incompatible
with POTW operations. These are:
sulfide,
ammonia,
oil and grease,
phenol, and
chromium.
Burns and Roe recommended that final U.S. pretreatment standards
should currently be established only for the first three pollu-
tants. They consider specific numerical U.S. phenol standards
to be inappropriate at this time because of the capability of
many POTW plants to satisfactorily treat phenolic waste waters,
particularly if the activated biological sludge has been acclimated
to this material. Burns and Roe indicate that some individual
POTW may wish to consider implementation of a local phenol standard.
Burns and Roe also recommend that it is inappropriate
at this time to set any specific numerical pretreatment standard
for chromium because of insufficient data available on the
technology to remove this pollutant and contradictory information
in the literature as to interference with POTW operation.
B. Technology to Remove Pollutants
Analysis of the data collected in the Burns and Roe
study shows that the major sources of sulfides and ammonia are
refinery sour waste water streams. Therefore, segregation and
treatment of sour waters represents the most efficient way to
meet these standards. Sour water stripping in an acid mode
(solution pH less than 7) readily removes sulfides; while
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25.
operating in an alkaline mode (solution pH greater than 7)
readily removes ammonia. In some circumstances a single properly
designed and operated sour water stripper can achieve both
objectives. In other circumstances two strippers operating in
series are required.
The control and treatment technology for oil and grease
removal is well known and has been widely demonstrated through-
out the industry. Gravity separation is the primary process,
the most common facility for this service being the API separator,
Secondary oil and grease removal is usually achieved by dissolved
air flotation.
Biological treatment is the most likely technology
for phenol removal from refinery sour water, should
such be required. The most effective configuration appears to
be a completely mixed activated sludge process with a detention
time of about 24 hours in the aeration tanks. Biological
treatment for phenol removal is practiced in a number of direct
discharging refineries, in which effluent from oil and grease
removal is treated biologically for removal of oxygen demand as
well as for phenol reduction.
Chromium appears in refinery waste waters when it is
used as a corrosion inhibitor in cooling water. ' The chromium
is present in both the trivalent and hexavalent forms. Ideally,
if chromium control is required, many refineries will be able
to change to environmentally acceptable organic-based corrosion
inhibitors which eliminate the need for end-of-pipe treating.
Hexavalent chromium must be reduced to the trivalent state
before it can be removed. Trivalent chromium removal technology
consists of adding lime or caustic to the waste water to promote
the precipitation of chromium under alkaline conditions.
1) Burns and Roe, Op. cit.
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26.
CHAPTER V
EFFLUENT PRETREATMEKT COSTS
A. Capital and Annual Costs
In this chapter we shall consider three pollutants
which will be subject to pretreatment standards. Facilities
needed to control the three pollutants include:
1. Installation of a sour water stripper capable
of meeting sulfide standards
2. Modification of an existing sour water stripper
to meet ammonia standards
3. Installation of dissolved air flotation (DAF)
facilities to meet oil and grease standards.
As was discussed in Chapter IV, costs to meet phenol
or chromium standards will not be developed in detail.
Not all of the above pretreatment standards will
impact every refinery that discharges to a POTW. The draft
development document prepared by Burns and Roe ' provides the
specific impacts of each pollutant standard on each plant.
Results are summarized in Exhibit 5. Therein we list the
refinery code identification numbers used by Burns and Roe
and the associated crude oil processing capacity. Next we
tabulate the capital costs required to meet pretreatment
standards by each refinery for each of the three pollutants.
Although Table VIII-1 in the Burns and Roe report
indicates Refinery Code No. 11 to require new facilities for
ammonia control, we were later advised to assign no ammonia
control cost. Also, Refinery Code No. 6 was found to discharge
waste water only to evaporating ponds or as injection to crude
oil wells and hence, was deleted from further consideration in
this analysis.
1) Ibid.
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EXHIBIT 5.
REFINERY INVESTMENTS1^ REQUIRED TO MEET PRETREATMENT STANDARDS
Crude Oil
Refinery Processing Capacity
Code (Thousand Barrels
Number Per Day)
1 15.0
2 111.0
3 75.0
4 101.0
5 44.0
7 123.5
8 12.2
9 5.0
10 53.8
11 15.0
12 20.0
13 30.0
14 46.5
15 12.4
16 186.4
17 24.0
18 39.0
19 27.7
20 44.5
21 38.0
22 29.7
25 103.0
26 233.5
27 70.0
28 21.0
30 44.8 - 161 - 161 3.6
Capital Costs to Meet
(Thousands
Sulfide
Control
_
-
M
-
-
-
_
-
-
-
-
-
-
-
-
-
-
580
-
-
-
785
Ammonia
Control
^
260
212
243
158
273
_
176
-
-
130
162
338
115
149
126
-
146
130
250
385
203
Pre treatment Standards
of Dollars)
DAF
Facilities
85
-
-
-
190
-
65
-
65
85
107
-
_
130
-
-
220
110
263
320
465
270
Total
85
260
212
243
348
273
65
176
65
85
237
162
338
245
149
126
220
836
393
570
850
1258
Unit Cost
(Dollars Per Barrel
Daily Crude Oil
Processing Capacity
5.7
2.3
2.8
2.4
7.9
2.2
13.0
3.3
4.3
4.3
7.9
3.5
1.8
10.2
3.8
4.6
5.0
22.0
12.9
5.5
3.6
18.0
U.S. Totals 1,526 1,365 3,617 2,375 7,357 4.8
1) "Draft - Supplement for Pretreatment to the Development Document for the Petroleum Refinin«
Industry, Existing Point Sourcp. Category" EPA 440/1-76/083, December 1976. (Minor modifica-
tions as noted in the text have been made.)
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28.
The aggregate U.S. investment cost to meet pretreat-
ment standards for sulfides, ammonia and oil and grease, is
shown in Exhibit 5. to be about $7.4 million. The Burns and Roe
development document ' noted that the aggregate investment costs
to meet a phenol pretreatment standard would be about $5.5 million
(after deleting Refinery Code Number 6) if all 26 refineries
required new facilities. Burns and Roe also submitted to the
EPA under covering letter dated January 5, 1977, cost data for
chromium removal in indirect discharge refineries. Aggregation
of the unit data presented therein yields a total investment
estimate for the overall U.S. of about $8.0 million. Thus, the
maximum potential capital investments required by U.S. petroleum
refineries to control all the pollutants considered for pretreat-
2)
ment standards is about $21 million. '
Annual costs to meet sulfide, ammonia and oil and
grease standards for all impacted indirect dischargers are
presented in Exhibit 6. Except for the following adjustments,
3)
the data were taken from the Burns and Roe report. '
o Capital investment costs were converted to an
annual basis using an annual capital charge
rate ' of 25.82 percent of the capital invest-
ment. This value provides a 12 percent
after-tax rate of return on investment.
o Full operating costs for sour water stripping
were charged only in the circumstances when a
new unit had to be constructed to meet sulfide
standards (Refinery Code Numbers 21 and 27).
T) Ibid.
2) 7.4 + 5.5 _ 8.0 = 20.9
3) Op. cit.
4) Annual capital charge is the quantity of cash (product revenues
less cash-out-of-pocket operating costs) that must be generated
by a project each year to enable it to pay Federal and local
taxes plus insurance, and to return to its owners their invest-
ment plus a return thereon.
5) Sobotka & Company, Inc., op. cit., Part Two, page II-2.
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EXHIBIT 6.
:D
ANNUAL COSTS•L/ REQUIRED TO MEET PRETREATMENT STANDARDS
Refinery
Code
Number
1
2
3
4
5
7
9
10
11
12
13
14
16
17
18
19
20
21
22
25
26
27
30
Crude Oil
Processing Capacity
(Thousand Barrels
Per Day)
15.0
111.0
75.0
101.0
44.0
123.5
5.0
53.8
15.0
20.0
30.0
46.5
186.4
24.0
39.0
27.7
44.5
38.0
29.7
103.0
233.5
70.0
44.8
Annual Costs to Meet Pretreatment Standards
(Thousands of Dollars)
Sulfide
Control
_
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
_
427
_
-
-
696
—
Ammonia
Control
.
75
61
70
46
79
_
51
-
-
37
47
97
33
43
36
_
42
37
72
111
59
46
DAF
Facilities
30
—
-
-
69
—
25
-
25
30
40
-
_
48
_
—
92
41
121
188
357
126
™
Total
30
75
61
70
115
79
25
51
25
30
77
47
97
81
43
36
92
510
158
260
468
881
46
U.S. Totals 1,480.4
1,123
1,042
1,192
Unit Cost
(Cents Per Barrel
Total Crude Oil Processed)
.7
.2
.3
.2
.9
.2
1.7
.3
.6
.5
,9
.3
.2
1.1
.3
.4
.7
4.5
1.8
.9
.7
4.3
.3
.8
3,357
1) See text for source.
N>
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30.
o Only capital charges and maintenance costs were
considered in the annual cost determination when
an existing unit needed to be modified to achieve
ammonia control. SCI reasoned that no increase in
operating costs would be required for ammonia
control above those already being expended for
sulfide control.
o SCI changed the unit cost for steam consumption
used by Burns and Roe from $1.50 per thousand
pounds to $3.00. We believe that the latter value
more nearly reflects current energy replacement
costs, which should be the basis of this analysis.
o To convert the annual costs for each refinery to
a unit basis (cents per barrel crude processed)
SCI used a 0.81 factor to convert each individual
plant stream day capacity to annual volume of
crude oil processed. '
o As noted previously in this Chapter, SCI deleted
Refinery Code Number 6 from further analysis and
considered that Refinery Code Number 11 will riot
require facilities for ammonia control.
Exhibit 6. shows that in the highest cost refinery
(Code Number 21) unit costs for pretreatment control reach
4.5 cents per barrel of crude oil processed (about 0.12 cents
per gallon of products manufactured).
Exhibit 6. shows that total annual costs to meet pre-
treatment standards for sulfides, ammonia and oil and grease in
all indirect discharge refineries are about $3.4 million. If
facilities to meet phenol and chromiun standards also must be
added to each of the 26 plants, then the (otal annual cost
2)
increases to $8.4 million. '
1) Volume of crude oil processed per year =
(0.81) x (365) x (daily processing capacity).
2) Add $2.0 million for phenol and $3.0 million for chromium,
(Burns and Roe, op. cit.)
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31.
Burns and Roe estimate that pretreatment facilities
to control sulfides, ammonia and oil and grease will require
the cummulative employment of only about 5 new operators through-
out the entire U.S. If both phenol and chromium control facilities
are also needed, the number of new operators needed increases to
about 25. Total employment impacts are about double the number
of new operators added to reflect added maintenance, supervision,
etc.
B. Segmentation of Indirect Dischargers
Exhibit 5. indicates that only two refineries (Code
Numbers 21 and 27) require installation of sour water stripping
facilities to meet sulfide standards. Eighteen of the refineries
require modifications of existing sour water facilities to meet
ammonia standards, and thirteen require installation of DAF
facilities. Only three refineries (Code Numbers 8, 15 and 28)
do not require any new capital facilities to meet pretreatment
standards. These three will be defined as segment "X" for use
in the impact analysis. Combined crude oil processing capacity
of these plants is 45.6 thousand barrels per day.
Exhibit 5. also shows the total of the capital expendi-
tures required by each impacted refinery for the three pollutants
subject to pretreatment standards. Capital costs are also shown
on a unit basis (per barrel of daily crude oil processing
capacity). Unit capital cost is a useful criterion for segmenta-
tion in the detailed impact analysis. Five plants (Code Numbers
9, 17, 21, 22, and 27) will experience unit pretreatment capital
costs greater than ten dollars per barrel of daily crude oil
processing capacity (ranging from $10.2 to $22.0). These five
plants will be defined as segment "Y" in the impact analysis.
They have a combined crude oil processing capacity of 166.7
thousand barrels per day.
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32.
It is interesting to note that the five MY" plants
cover a fairly wide range in regard to size, processing con-
figuration, and location. Crude oil processing capacities of
the impacted plants within this segment range from less than 10
to 70 thousand barrels per day. Two plants are located in Texas,
one in California, one in the Rocky Mountains, and one in the
central U.S.
Refinery Code Number 21 is a simple topping plant with
no downstream processing facilities. Refinery Code Number 9 is
principally an asphalt producer. The other three refineries
contain catalytic cracking, alkylation, reforming and hydrotreat-
ing facilities. In addition, Refinery Code Number 27 contains a
hydrocracking unit and is involved in the production of petro-
chemicals.
The balance of the 26 plants which discharge to POTW
[_26 minus (X + Y) = 18j will be designated as segment "Z". Pre-
treatment capital requirements for these refineries range from
$1.8 to $7.9 per barrel of daily crude oil processing capacity.
The combined crude oil processing capacity of this segment is
1,313.7 thousand barrels per day.
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33.
CHAPTER VI
IMPACT ANALYSIS
It was discussed in Chapter II that the U.S. petroleum
refining industry is likely to develop along one of two paths.
The Federal government may adopt a policy that growth in U.S.
petroleum product consumption should be supplied from new or
expanded U.S. refineries. A relatively high product import
tariff (or subsidy or domestic crude oil price controls, etc,)
would be necessary to create a per-barrel refinery margin (product
unit revenue less crude oil unit cost) high enough to attract
capital investment in such new refinery capacity. Alternatively,
the Federal government may adopt a policy which calls for
approximately constant refinery capacity. Here, too, a (much
smaller) product import tariff would be needed to insure survival
of existing refineries.
A. Impact With Growth in U.S. Refining Capacity
The economic impact of pretreatment standards upon
the U.S. refining industry under this circumstance is straight-
forward to analyze. In order for refinery capacity to grow,
product prices must rise to a level that reflects the full
investment costs of constructing new refining capacity (including
associated environmental costs). Since prices will reflect new
refinery costs, the costs of waste water treatment in existing
refineries will have no effect on prices.
Because product prices in a growth environment will be
the same whether or not pretreatment standards are implemented,
the cost of conforming to these standards will show up as a lower
cash flow from existing refineries. In other words, pretreatment
costs will be paid for out of profits.
With the available data it was not possible to estimate
cash flows of the individual indirect discharging refineries. But
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34.
cash flow estimates are available for 89 small refineries. These
plants would be expected to have per-barrel cash flows about
equal to those experienced by the least complex indirect dis-
charging refinery (and lower than those experienced by the
more complex plants). Consequently, the small refinery cash
flow estimates can be used as proxies for the indirect dis-
chargers' cash flows.
In our previous impact study for EPA we determined that
the before tax cash flow (CFBT) needed to justify investments in
new refinery capacity was about $1.8 per barrel (1974 price level). 1-)
From this starting point, CFBT estimates were derived for the 89
small refineries. It was found that CFBT ranged from $1.05 to
$1.45 per barrel of crude oil processed before accounting for
the costs of conforming to EPA's effluent water quality stand-
2)
ards. The lower CFBT estimate of $1.05 per barrel is the
yardstick by which the impact of pretreatment costs can be
measured.
Exhibit 7. provides a tabulation of the costs of seg-
ment "Y" refineries (the most impacted indirect discharge plants)
to meet all possible elements of pretreatment costs. In order to
determine maximum possible impacts on the affected plants, we
have included the costs of potential phenol and chromium control
facilities plus an estimate of POTW user charges.3'1 It can be
seen that the maximum possible cost to be faced by any indirect
discharging refinery is $0.06 per barrel crude oil (by Refinery
Number 21). The impact of a $0.06 per barrel cost must be assessed
relative to the $1.05 per barrel CFBT yardstick. Although the im-
position of pretreatment standards will reduce the capital value^'
of indirect discharging refineries by almost 6 percent, the stand-
ards will clearly not jeopardize the viability of any indirect
discharging refinery.
^ °P» citt * Part Three, page 98.
2) Ibid., pages 94-97 and 101.
3) These estimates were derived from user charge forecasts furnished
by three of the involved POTW.
4) Discounted present worth of future cash flows.
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35.
EXHIBIT 7.
MAXIMUM POTENTIAL COSTS OF SEGMENT "v"
i
(Most Impacted Indirect Dischargers)
Refinery Code Number
Processing Configuration '
Crude Oil Processing Capacity
(Thousand Barrels Per Day)
Waste Water Effluent Flow
(Thousand Gallons Per Day)
Annual Costs to Meet Pretreatment
21
27
Itrpll llpll
38.0 70.0
140 1,
Standards
500
9
"A"
5.0
30
22
"c"
29.7
1,420
17
"C"
24.0
220
(Thousands of Dollars at 1976 Prices)
Sulfide Control
Ammonia Control
DAF Facilities
Phenol Control
Chromium Control
Total
Estimated Annual Charges by POTW
(Thousands of Dollars)
Total of Pretreatment Costs Plus
(Thousands of Dollars Per Year)
(Cents Per Barrel
Crude Oil Processed)
427
42
41
60
77
647 1,
5
POTW Charges
652 1,
5.8
696
59
126
93
147
121
70
191
5.7
-
-
25
19
35
79
2
81
5.5
-
37
121
50
103
311
70
381
4.3
-
33
48
44
95
220
10
230
3.2
1) Processing Configuration Categories:
"T" - topping plants processing low sulfur crude oils into low
sulfur residual and distillate fuel oils, and naphtha jet
fuel. (No downstream processing facilities utilized.)
"A" - topping plus vacuum distillation to process high sulfur
crude oils into asphalt, high sulfur distillates, and
naphtha jet fuel.
"C" - topping plus cracking (catalytic, hydro or thermal) to
process low and high sulfur crude oils into gasoline and
low sulfur fuel oils. (May also contain other processes
such as catalytic reforming.)
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36.
Exhibit 7. shows that POTW user charges represent
only small fractions of total annual waste water treatment
costs incurred by indirect dischargers. POTW effluent treat-
ing charges are based on volume and type of treatment. POTW
costs are low because of economies of scale and because the
cost of capital is lower for tax-exempt institutions than for
others. No fixed costs or throughput obligations are
required from most POTW users. Therefore, no capital impair-
ment is experienced by POTW users. In the case of only two
refineries the amount of effluent to be treated exceeds 5 per-
cent of their POTW plants' capacity and thus, is an important
element in the POTW plants' economic justification. It is clear
that there is substantial economic incentive for direct discharge
refineries to consummate indirect agreements with companion POTW.
B. Impact Without Growth in U.S. Refining Capacity
It is not possible to determine the exact level of
government protection against low priced imports that would be
needed to preserve refining industry capacity at precisely its
current level. But the effects of such a tariff would be two-
fold. First it would support expansion in a few refineries
that, for one reason or another possess unique low cost opportunities
for expansion ("debottlenecking"). Second, it would cause a few
refineries with unusually high cash costs to close. A reasonable
assumption of the desired level of tariff is that it will lead
to product prices of such a level that no more than ten refineries
will close.
Refinery costs vary for many reasons - complexity of the
product slate, fuel use efficiency, Labor productivity, climate,
to name some. Except for effluent water treatment costs, there is
no evidence to indicate that the 26 indirect discharging refineries
experience atypical operating costs, either high or low. Rather, the
available data imply that their costs lie within the "normal"
range.
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37.
Effluent treatment costs for indirect discharging refineries lie
near the low end of the effluent treatment cost spectrum.
The best yardstick to use for judging the impact of
pretreatment standards in a no growth environment is the effluent
treatment costs faced by direct discharging refineries. Such
costs were developed for 89 small ' refineries in our earlier
2)
EPA study J. (Larger refineries will mostly incur lower per
barrel costs than smaller plants because of scale economies.)
The following tables compare each refinery in pre-
treatment segment "Y" with direct discharging refineries of the
same processing configuration (as defined at the bottom of
Exhibit 7.).
Number of Direct Discharging Small Refineries
With Indicated Waste Water Treatment Costs
Processing Configuration
"rpM "A" "pM
Treatment Cost, Cents Per o\
Barrel Crude Oil Processed ^
40-50 357
30-50 7 10 8
20 - 50 10 13 12
Treatment Costs of Segment "Y" Refineries
Refinery Number Cents Per Barrel
21 6
27 6
9 6
22 4
" 3
1) Less than 20 thousand barrels per stream day crude oil processing
capacity.
°P* Git., pages 94-97.
Ibid' Costs reflect 1976 prices. The costs shown in Ibid were
increased by 16 percent (recommended by Burns and Roe) to account
for inflation from 1974 to 1976. These are BATEA costs. BPCTCA
costs are about 2/3 as high.
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38.
In each configuration class there are more than ten
direct discharging refineries that face waste water effluent
treating costs at least three times as high as those that will
be faced by the highest cost indirect discharging refinery.
Moreover, a product price level so low as to cause five to ten
refinery closures would still generate a significant before tax
cash flow for indirect discharging plants - on the order of
(46 - 6 =) 40 cents per barrel crude oil processed. It is
concluded that, as in the growth case, the imposition of pre-
treatment standards onto indirect discharging refineries would
have little economic impact compared to the imposition of effluent
quality standards on direct discharging refineries.
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39.
CHAPTER VII
LIMITS OF THE ANALYSIS
The conclusions of this study are not particularly
sensitive to variations in assumptions used in the analysis.
This is because the sum of pretreatment costs plus POTW user
charges for indirect discharge refineries will be much less
than the waste water effluent treatment costs that will be
experienced by a large fraction of direct discharging refineries.
The three areas in which variations in assumptions
might influence study results most significantly are:
1. Capital costs required for pretreatment
2. Crude oil prices which affect unit energy costs
3. The level of protection afforded to the U.S.
refining industry.
Even if capital expenditures (1976 dollars) for new
pretreatment facilities are double those estimated by Burns and
Roe, the total costs, including POTW fee experienced by indirect
dischargers would still be substantially below much of the
industry which must meet direct discharge water effluent require-
ments .
With the exception of the two plants which could require
steam stripping for sulfide control, incremental energy costs for
operating pretreatment facilities are trivial. And even for
these two plants energy costs will be much lower than the
water treatment energy costs which will be experienced by direct
discharging refineries.
This analysis has shown that even if significant
attrition of the U.S. refining industry takes place due to
inadequate tariff or subsidy protection, there will still be a
large number of plants that would be more severely disadvantaged
by direct discharge water treatment regulations than would be
the highest cost indirect discharging refinery.
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re HUE
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