United States
Environmental Protection
Agency
Office of Water
Regulations and Standards
Washington DC 20460
EPA-440/2-82-007
November 1982
Water
Economic Impact Analysis
of Effluent Limitations and
Standards for the
Petroleum  Refining Industry
            QUANTITY

-------
This document is available from the National Technical Information Service,
5282 Port Royal Road, Springfield,  Virginia 22161.

-------
       ECONOMIC IMPACT ANALYSIS OF
         EFFLUENT LIMITATIONS AND
            STANDARDS FOR THE
       PETROLEUM REFINING INDUSTRY
               PREPARED FOR
   U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF WATER REGULATIONS AND STANDARDS,
    OFFICE OF ANALYSIS AND EVALUATION
                C\'i~- .--'oO, iili.i


              NOVEMBER  1982
X

-------
Fnvfrc:
                        sgeney

-------
This document is an economic impact assessment of the recently-issued

effluent guidelines.  The report should be directed to the staff respon-

sible for writing industrial discharge permits.  The report includes

detailed information on the costs and economic impacts of various treatment

technologies.  It is should be helpful to the permit writer in evaluating

the economic impacts on an industrial facility that must comply with BAT

limitations or water quality standards.


If you have any questions about this report, or if you would like additional

information on the economic impact of the regulation, please contact the

Economic Analysis Staff in the Office of Water Regulations and Standards

at EPA Headquarters:

                       401 M Street, S.W.  (WH-586)
                       Washington, D.C.  20460
                       (202) 382-5397


The staff economist for this project is John Kukulka (202/382-5388).

-------
                                    PREFACE

This document is a contractor's  study  prepared  for  the  Office  of Water Regula-
tions and Standards of  the Environmental Protection Agency (EPA).  The purpose
of the  study is  to  analyze the  economic impact which  could  result  from the
application of  effluent  standards and  limitations  issued under  Sections  301,
304, 306 and  307 of the  Clean Water  Act to the petroleum refining  industry.

The study supplements the technical study (EPA Development Document) supporting
the issuance  of  these  regulations.  The  Development Document  surveys existing
and potential waste treatment  control  methods  and technology  within particular
industrial source  categories  and  supports  certain standards  and  limitations
based upon an analysis of the feasibility of these standards in accordance with
the requirements of the Clean Water Act.  Presented in the Development Document
are the investment and operating costs associated with various control and treat-
ment technologies.  The attached document supplements this analysis by estimat-
ing the broader  economic effects  which might  result  from the  application  of
various control methods  and technologies.  This  study  investigates  the effect
in terms of product price  increases,  effects upon employment and the  continued
viability of affected plants,  effects upon  foreign  trade  and other competitive
effects.

The study has been prepared with  the  supervision and  review of  the  Office  of
Water Regulations and Standards of  EPA.  This report  was submitted in fulfillment
of Contract No.  68-01-6341 by Sobotka  &  Company,  Inc.  The work on this analysis
was completed August  1982.

-------
                               TABLE OF CONTENTS
Chapter I
Chapter II
Chapter III
Chapter IV
Chapter V
Chapter VI
Chapter VII
EXECUTIVE  SUMMARY

A.   Introduction
B.   Structure  of the  Industry
C.   Methodology
D.   Costs  of Conforming  to Revised  Guidelines
     and New Source  Standards
E.   Impact Analysis
F.   Limitations of  the Analysis

STRUCTURE  OF THE PETROLEUM REFINING INDUSTRY

A.   Principal  Statistics of the Industry
B.   Coverage of the Analysis
C.   Economic and Financial Structure of the Industry

METHODOLOGY

A.   Price  Analysis
B.   Quantity Analysis

COSTS OF CONFORMING PETROLEUM REFINERIES TO
REVISED BATEA  GUIDELINES, NEW SOURCE PERFORMANCE
STANDARDS,  PRETREATMENT  GUIDELINES, AND PRETREATMENT
STANDARDS  FOR  NEW SOURCES

A.   Existing Sources
B.   New Sources

ECONOMIC IMPACT ANALYSIS WITH HIGH  LEVEL OF
PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS

A.   Price  Effects of Revised Guidelines
B.   Financial  Effects
C.   Production Effects
D.   Employment  Effects
E.   Community  and Balance of Trade  Effects

ECONOMIC IMPACT ANALYSIS WITH LOW LEVEL OF
PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS

A.   Price  Effects
B.   Financial  Effects
C.   Production Effects
D.   Summary of Economic  Impacts of Revised
      Guidelines on Existing Plants
E.   Impacts on New Plants

LIMITATIONS OF THE ANALYSIS
                                                                             1-1
                                                                             1-1
                                                                             1-3

                                                                             1-3
                                                                             1-6
                                                                             1-8
                                                                            II-1
                                                                            II-3
                                                                            II-3
                                                                           III-l
                                                                           III-2
                                                                           IV-1
                                                                           IV-4
                                                                            V-l
                                                                            V-2
                                                                            V-3
                                                                            V-4
                                                                            V-4
                                                                           VI-1
                                                                           VI-1
                                                                           VI-2

                                                                           VI-18
                                                                           VI-19
                                      -i-

-------
                         TABLE OF CONTENTS (continued)
Appendix A      PETROLEUM REFINING PROCESSES AND THE REFINING INDUSTRY

                A.  Types of Refineries                                     A-l
                B.  Location of Refineries                                  A-8
                C.  Financial Structure of the Industry                     A-10
                D.  Refining Industry Growth                                A-ll
                E.  Types of Refining Processes                             A-13
                                      -ii-

-------
                                LIST OF EXHIBITS
                                                                           Page
Exhibit I.I   SUMMARY OF COSTS TO PETROLEUM REFINERIES
              OF CONFORMING TO REVISED EFFLUENT DISCHARGE STANDARDS        1-4

Exhibit 1.2   COSTS TO A NEW PETROLEUM REFINERY OF CONFORMING TO
              REVISED EFFLUENT DISCHARGE STANDARDS                         1-5

Exhibit II.1  SUMMARY OF RESPONSES TO 1976 PETROLEUM REFINING
              INDUSTRY SECTION 308 QUESTIONNAIRE                          II-4

Exhibit II.2  THE EFFECT OF PRODUCT IMPORT TARIFFS ON CONSUMPTION,
              DOMESTIC MANUFACTURE AND IMPORTS OF PETROLEUM PRODUCTS      11-13

Exhibit IV.1  COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
              OF CONFORMING TO REVISED BATEA GUIDELINES                   IV-6

Exhibit IV.2  COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
              OF CONFORMING TO REVISED BATEA GUIDELINES                   IV-16

Exhibit IV.3  SUMMARY OF COSTS TO PETROLEUM REFINERIES OF
              CONFORMING TO REVISED EFFLUENT DISCHARGE GUIDELINES         IV-19

Exhibit IV.4  COSTS TO A NEW PETROLEUM REFINERY OF CONFORMING TO
              REVISED EFFLUENT DISCHARGE GUIDELINES                       IV-20

Exhibit VI.1  EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
              TO REVISED GUIDELINES OF MORE THAN 4.1
              CENTS PER BARREL OF CRUDE OIL PROCESSED                     VI-4

Exhibit VI.2  COMPARISON OF PROCESS UNIT VALUES
              VERSUS COST TO CONFORM TO REVISED GUIDELINES                VI-11

Exhibit A.I   FLOW DIAGRAM FOR TOPPING REFINERY PROCESSING
              LOW SULFUR CRUDE OIL                                          A-2

Exhibit A.2   FLOW DIAGRAM FOR HYDROSKIMMING REFINERY
              PROCESSING LOW SULFUR CRUDE OIL                               A-3

Exhibit A.3   FLOW DIAGRAM FOR FUELS REFINERY PROCESSING
              LOW SULFUR CRUDE OIL                                          A-4

Exhibit A.4   FLOW DIAGRAM FOR HIGH CONVERSION REFINERY PROCESSING
              LOW SULFUR CRUDE OIL                                          A-5

Exhibit A.5   U.S.  REFINERY CRUDE DISTILLATION CAPACITY
              AND OPERATIONAL ABILITY MATRIX                                A-7

Exhibit A.6   GEOGRAPHIC DISTRIBUTION OF REFINERIES
              AND REFINERY CAPACITY                                         A-9

Exhibit A.7   FUNCTIONAL CHARACTERIZATION OF PETROLEUM
              REFINERY PROCESSES                                            A-14


                                     -iii-

-------
                                   Chapter I
                               EXECUTIVE SUMMARY

A.   Introduction

     The Environmental Protection Agency  (EPA)  is in the process of developing
and issuing revised "best available technology economically achievable" (BATEA)
limitations and  "pretreatment"  standards  for  aqueous effluents  discharged  by
existing petroleum refineries.  It is also issuing revised new source standards
for future refineries. The  standards and limitations will be  issued  in accor-
dance with Sections 301,  304,  306 and 307 of the Clean Water Act.  The purpose
of this study  was to analyze the  economic impacts that  could  result  from the
implementation of revised limitations and standards.

     This study was restricted to 212 U.S. refineries that operated in 1976 and
were expected to  discharge  aqueous  effluents in  1984 into receiving  bodies  or
publicly/jointly owned treatment plants.   (Fifty  refineries will  discharge  no
effluents; twenty-one, including  eight known  dischargers,  did  not  respond  to
EPA's Section 308  Survey  Questionnaire and were not included in the analysis.)

     Most of the data underlying the  analyses  in  this report  were taken from a
development document  and  a  cost  manual prepared  by EPA.  These publications
include information on the  size and process unit  configuration of each  dis-
charging refinery and on the estimated  capital  and  operating  costs that may  be
required to  bring each  refinery  into conformance with  revised  guidelines.
B.   Structure of the Industry

     The petroleum refining industry had been  subject  to  a  set  of raw material
and refined product price  controls  that severely  distorted  competition.   This
study assumed that these  controls  would have  lapsed  by 1984 when  the revised

-------
                                      1-2
guidelines will become effective.  In  fact,  these controls were  terminated  by
presidential decree on January 28, 1981.

     In the absence  of price controls, the  market  for refined petroleum pro-
ducts is competitive between  domestic  and foreign plants.  Product  prices are
determined by the  marginal  costs of  the highest cost  supply needed to  clear
the market.  For  several reasons,  e.g.,  preferentially-priced  raw  materials
and/or fuel, advantageous tax treatment,  less  severe  environmental  controls,
less severe occupational  safety  and  health  requirements,  etc.,  many  foreign
refineries face lower  costs  than do  U.S. plants.    So the  maintenance  of  a
domestic refinery   industry  of  roughly  the  same size  that   existed  in  1978
would have  required  that  some  protection  be  afforded  against   unrestricted
competition from imported products.

     For the purpose of  economic analysis,  it  is useful  to  segregate  the in-
dustry on the basis of four  characteristics:

     B.I  Disposition of Aqueous Effluent. Refineries discharge either  direct-
ly or indirectly to publicly or jointly owned treatment plants, or not  at all.

     B.2  New or Existing Source of Effluent.

     B.3  Refinery Configuration.  Configuration is a good proxy for value added
by refineries.   The more  highly configured a refinery is, the greater  will  be
the value added per unit of  crude oil processed.

     B.A  Geographical Location.  Because transportation is an important compo-
nent of delivered  product cost,  the location  of  a  refinery relative to its crude
oil supply and  its product  markets,  and to  its competition,  has  a significant
impact on its value.

-------
                                      1-3
C.   Methodology

     The price analysis, described  below,  was simple.  For the quantity analy-
sis, the cost  estimates were restated  as  annualized costs per unit  volume of
crude oil processed.  Twenty-seven  refineries  were found to be facing costs to
conform to revised  guidelines  which exceeded 4.1  cents  per (42  gallon) barrel
of crude oil processed.  For each of  these the cost to  conform was compared to
the value of  the refinery.   Value  was  defined from an  investors'  viewpoint:
the present value of  future cash flows.  Value estimates were derived for each
of two premised  future  levels  of federal  protection against  petroleum product
imports:  a level high  enough to encourage  construction  of  new capacity, and a
lower level adequate  to preserve the industry at about its  current  capacity.
For each level  of  protection,  value  estimates   were  developed  from  factual
information about refinery  process  unit costs, historic product  manufacturing
margins, and  transportation costs  for  raw  materials   and  refined  products.
D.   Costs of Conforming to Revised Guidelines and New Source Standards

     Costs of  conforming existing  refineries to  revised  guidelines  (BAT  and
PSES) will apparently  range  from zero to  42 cents  per barrel  of crude  oil
processed, i.e., from  zero to  about  1.1 cents  per gallon of  refined product
manufactured.  Costs of  conforming  new source refinery capacity to revised new
source standards (NSPS and  PSNS)  will apparently range  from  zero  to  6.2 cents
per barrel crude oil processed,  i.e., from zero to about  0.2 cents per gallon
of refined product manufactured.

     The cost data are summarized in Exhibits I.I and  1.2.

-------
                                            1-4
                                        Exhibit I.I

                          SUMMARY OF COSTS TO PETROLEUM REFINERIES
                   OF CONFORMING TO REVISED EFFLUENT DISCHARGE  STANDARDS
DIRECT DISCHARGERS

  BAT-

    Level 1

    Level 2
                      Crude Oil
                     Distillation
                       Capacity

                      (1000 bpd)
14,142

14,142
             Capital    Operating             Annualized
              Costs       Costs     	Costs	
                                        Total             Unit
            (1000 $)  (1000 $/year)   (1000 $/year)   (cents/barrel)
 19,281

112,956
 3,678

24,985
 7,730

48,703
0.2

1.0
INDIRECT DISCHARGERS

  PSES-

    Option 1             2,402         9,591

    Option 2             2,402        84,807

  According to the Development Document:
                          3,163

                         14,432
                            5,175

                           35,267
                                0.7

                                4.1
    BAT-Level 1 is current BPT quality plus reduction in effluent  flow to  73% of
                "model" flow,

    BAT-Level 2 is the same flow reduction plus addition of  powdered  activated
                carbon to the  biological treater,

  PSES-Option 1 is current PSES quality plus removal of chromium from cooling
                tower blowdown, and
  PSES-Option 2 is flow reduction, equalization, biological  treatment, and
                filtration of  total effluent.

-------
                                              1-5
                                          Exhibit 1.2

                               COSTS TO A NEW PETROLEUM REFINERY*
                     OF CONFORMING TO REVISED EFFLUENT DISCHARGE STANDARDS
DIRECT DISCHARGER (NSPS)S

  Level 1

  Level 2
NO AQUEOUS DISCHARGE5
                               Capital
                                Costs

                              (1000 $)
    0

   75
INDIRECT DISCHARGER (PSNS)t

  Option 1                      260

  Option 2                    5,800
                 Operating
                   Costs

               (1000 $/year)
    0

  218
9,500
  140

2,230


1,880
                          Annual!zed
                             Costs
                     Total           Unit
                 (1000 $/year)  (cents/barrel)
    0

  234
  195

3,450


3,875
0

0.4
0.3

5.5


6.2
  200,000 barrels per stream day capacity, equipped for high conversion.

5 Costs are additional above current NSPS (BADT).

t Costs are additional above current pretreatment standards for existing  refineries.



According to the Development Document:

  NSPS-Level 1 corresponds to current NSPS (BADT) regulations,

  NSPS-Level 2 adds powdered activated  carbon to the Level 1 biological treater,

  PSNS-Option 1 is current PSES quality plus removal of chromium from cooling tower
                blowdown, and
  PSNS-Option 2 is flow reduction,  equalization,  biological treatment and  filtration
                of total effluent.

-------
                                      1-6
E.   Impact Analysis

     E.I  Price Impacts.   It was  discussed  above that  market-clearing prices
of petroleum products are  determined  by either the long-run  costs  of products
manufactured domestically  or  the  short-run  cost  of  imports  plus  tariff.
Under a  high level  of  federal  protection  against  imports,  the revised  new
source standards would increase  product prices by zero  to  0.15 cents per gal-
lon.  Under a low  level  of protection, prices will be determined by the costs
of imports  (including tariff  costs).   So  revised  guidelines  would  have  no
price impact.

     E.2  Financial Impacts.  With a  high  level  of federal  protection, the fi-
nancial effect  for existing refineries of  revised  new source  standards  and
revised guidelines vrould range from  a net cost of 81  million dollars per year
to a net  benefit  of  327  million dollars  per  year.   The range  exists because
there are five  possible  new source standards  that might be price-determining,
and four combinations  of revised direct/indirect guidelines that may be imposed.
Under a  low level  of federal  protection, and depending on  which  combination
of revised direct/indirect guidelines  was  imposed, the costs  to be  absorbed  by
existing refineries would range from 13 million to 81  million dollars per year.
The larger  number  represents  an  average  cost  increase for  the industry  of
about 0.1 percent, or roughly one percent of value added by refining.

     At the  time   of  this  study,  petroleum refineries  faced major  business
uncertainties.  The size of  the  "small refiner bias" in  the crude oil entitle-
ments program  was  under  review;  price  controls  on  most   products had  been
allowed to lapse, and further decontrol was  under  study;  crude oil  prices were
being increased to  world levels by  price decontrol;  the long range  level  of
protection against imports  to  be  afforded  U.S.  refineries was  unknown, etc.
Compared to  the financial implications  of these  uncertainties,  the estimates
of the costs of conforming to revised guidelines were inconsequential.

     E.3  Production  Impacts.  Twenty-seven  existing refineries were estimated
to face conformance costs exceeding 0.1 cents per  gallon of product manufactured.

-------
                                      1-7
Under a  high level  of  federal  protection  all  of these  were expected  to  be
willing  to  undertake effluent  treating  revisions  and  to  continue  operating.
Under a  low level  of federal  protection,  three refineries  were  identified as
apparently not  worth the cost  of  conforming to revised  Option 2 pretreatment
standards for existing  sources (PSES) guidelines.  These  refineries accounted
for only 0.1 percent of  industry capacity,  so the  loss  would have no effect on
overall  industry outturn.

     E.4 Employment Impacts.   Under a  high  level of  federal protection,  re-
vised standards and guidelines  would  lead to the following increases in industry
employment:

                                                         New Jobs
            Existing Direct Dischargers
                    Level 1                                  40
                    Level 2                                 600
            Existing Indirect Dischargers
                    Option 1                                 10
                    Option 2                                250

New employment  could range  from 50  to  750 jobs, depending  on the combination
of Level/Option chosen for implementation.

     Under a low level of protection, total industry  employment would increase
by about 50 people if Level  1 and  Option  1  are implemented.  If Level  2  and
Option 2 are implemented  instead,  employment  in  surviving  refineries  would
increase by  about  850  jobs; but 100 to 150 jobs  would  be lost  at the three
refineries which shut down.

     E.5  Community Effects.   The  three  refineries that may shut  down  are  all
small employers  located  in  or  near  metropolitan  areas.   Hence,  no  com-
munity impacts are expected if the plants shut down.

     E.6  Balance  of Trade  Effects.  There  apparently  will  be no  balance  of
trade effects of revised guidelines.

-------
                                      1-8
F.   Limitations of the Analysis

     The analysis is based  entirely  on costs developed by  the Effluent Guide-
lines Division of EPA.  The costs  are based on a  statistical  analysis of 1976
effluent flow data.   Also,  land costs  were assumed to  be negligible  for  all
refineries.

     Existing federal policy currently  does not substantially protect domestic
refineries against low priced  imports  of petroleum products.  The lowest level
of protection assumed  in  this  study  was a level that  would maintain domestic
refining industry throughput at roughly  its  1978 level.   But in  1978,  there
was no clear indication of what the refinery protection policy would eventually
be, if any, or when it might become effective.

     At the time this study was made,  it was not possible to foresee the dramatic
changes that eventually took place in the  world and the  U.S.  petroleum market
places.  Large price increases  significantly reduced  consumption.   In January
1981, all U.S. petroleum  price  controls were removed,  small refiner subsidies
were rescinded and the U.S.  industry  was given essentially no tariff protection.
U.S refining utilization  decreased from  89.4 percent  of  capacity in  1977  to
below 70 percent  in 1981.  More than fifty U.S.  refineries have discontinued
operations since decontrol.

     If the economic impact  analysis  were  redone in the context  of the current
economic environment,  some  changes  would  be  noted.   But  the impacts  on  the
existing industry (BAT and  PSES)  would be  small since compliance costs repre-
sent such a small fraction  of  value  added.  There  would be essentially no con-
struction of new  refining sources.   Market prices  for  petroleum products would
be determined by the  costs  of imports,   so  there  would  be no  price effects
of revised guidelines  applicable to  U.S.  plants.   Therefore, BAT and PSES com-
pliance costs would have to  be  absorbed by existing refineries.

-------
                                      1-9
     Even though  current  forecasts  indicate  that little  construction of  new
refining sources  will  take  place, it  can be  concluded  that  the NSPS  or  PSNS
standards considered in this  analysis  would  have  negligible  impact  on  the
economic viability of new plants.  A new refinery of the type noted in Exhibit
1.2 would have to generate a net cash flow before taxes (product revenues minus
the sum of  raw material costs  plus  cash  operating  expenses) of roughly  $150
million dollars per  year to  be commercially  feasible.   In this context,  the
annual costs  of  even  the  more  severe  treatment  options  considered  for  new
sources - PSNS  Option  2 or zero  discharge -  represent roughly two  percent  of
the cash  flow.   Relative costs of  this magnitude are too small to  influence
overall project economics.

-------
                                   Chapter II
                  STRUCTURE OF THE PETROLEUM REFINING INDUSTRY

 (NOTE:  The  material contained  in  this chapter  is updated  in Appendix  A.)
 A.   Principal Statistics of the Industry

     As of January 1, 1978,  the petroleum refining  industry in the United States
 and its possessions  consisted  of about  280 plants, owned by  about  150 firms,
 and located in 41 of the 50 states, Guam, Puerto Rico, and the Virgin Islands.1
 Industry capacity  for  processing crude  oil  was about 17 million  barrels (715
 million gallons)  per calendar day.^  The refineries  had a  replacement  value
 in excess of  40  billion dollars.  The industry  employed  about  160,000 persons
 in 1977.3

     The bulk of  refining  is  done by firms  which  also  market refined products
 or produce crude  oil, or do both.   In  most firms  the refining  portion of  the
 business is not  the  major  activity.   Refinery investment is  less  than 15 per-
 cent of total investment in the domestic oil industry.4

     U.S. refineries vary in capacity by over  three orders  of magnitude - from
 500 to 730,000 barrels  crude  oil per day.5  The degree of  refinery  complexity
 (measured by total refinery replacement value per barrel of crude oil distilla-
 tion capacity) varies between refineries  by a factor of fifteen.6  Consequently,
     1 U.S.  Department  of Energy,  Petroleum Refineries  in the United  States
and Puerto Rico, January ±, 1978, July 1978.
     2 Ibid.
     3 American  Petroleum Institute,   Basic Petroleum  Data  Book,  Petroleum
Industry Statistics, October 1975 and later years.
     4 Ibid.
     5 U.S. Department of Energy, op. cit.
     6 Sobotka & Co., Inc., Capital and Operating Costs for Grass Roots Petroleum
Refineries with  Several  Different Process  Unit Configurations, Department  of
Energy Contract EJ-78-C-01-2834,  April 12, 1979.

-------
                                      II-2
the replacement value of  refineries  ranges from roughly one million dollars to
perhaps two billion dollars.

     The delivered  price  of  crude oil  to U.S.  refineries  in December  1978
varied from about  six  dollars per barrel  for  domestic  "lower tier"  crude  oil
to about sixteen  dollars  per barrel  for  imported low-sulfur crude  oil.*   The
weighted average  composite  price was  thirteen dollars  per  barrel  (thirty-one
cents per gallon).   It  was  anticipated  that   imports would  account  for  about
forty-three percent of  crude oil intake  by U.S. refineries in  1979  and  about
ten percent of product consumption.2

     Average wholesale prices  for refined petroleum fuel  products  in December
1978 were:3
               Motor gasoline               42      cents per gallon
               Kerosene                     39.5      	
               Distillate fuel oil          38        	
               Residual fuel oil            25        	

     Average product yields from U.S. refineries during  1977 were:^
                                      Percent  of Crude
                                       Oil Processed
               Gasoline                     43.4
               Jet fuel and kerosene         7.8
               Distillate fuel oil          22.4
               Residual fuel oil            12.0
               Petrochemical feedstocks      3.6
               Liquefied gases               2.4
               Asphalt                       3.0
               Lubricants                    1.2
               All other                     4.2
                                           100.0
     1 Chase Manhattan Bank, The Petroleum Situation - February 1979.
     2 Oil and Gas Journal, May 14, 1979, p. 86.
     3 Chase Manhattan Bank, op.
     * Department of  Energy,  Crude Petroleum, Petroleum Products ,  and  Natural
Gas Liquids;  1977, DOE/EIA - 0108/77, December 8, 1978.

-------
                                      II-3
Not all domestic gasoline was manufactured from crude oil.  Roughly ten percent
was supplied predominantly  by  natural gas liquids.*  Also, natural gas proces-
sing plants supplied much more liquefied gases than did refineries.
B.   Coverage of the Analysis

     The refineries  for which  revised  BAT guidelines  or  revised pretreatment
guidelines costs  were  derived are those  which  answered a  survey questionnaire
issued under  authority of  Section  308 of  Public  Law 92-217.  A total  of 299
questionnaires were issued; responses are summarized in Exhibit II.1.
C.   Economic and Financial Structure of the Industry

     Revised effluent  guidelines  require compliance  by July  1,  198A.   Conse-
quently, the economic  structure of the industry in 1978 or  1979  is  not neces-
sarily relevent to the impact  analysis.   Rather,  the structure  in  1984  as it
would be without  revised  guidelines is the appropriate base for analysis.  The
1984 structure was estimated  to be the result  of five years  of  endogenous and
exogenous influences on the 1978-79 structure of the industry.

     The financial status of  the industry in  1978 is  not a  good  base  from
which to forecast the  1984   status  because then-current  conditions will  not
exist in 1984.  At the time that  this  analysis  was performed, the industry was
subject to  price  controls  and allocation  rules  for  both  raw materials  and
refined products.   Product price  controls  had  been  in effect since 1971,  and
crude oil price  controls and allocations  rules  since 1973-74.   The  controls
worked in two directions.  On the  one hand, the  costs  of raw materials  to U.S.
refineries  were lower  than the costs faced by  essentially  all of the  rest  of
the free world non-OPEC  refiners.   On  the other  hand,  product prices in the
United States were controlled  at  levels lower  than in most of the rest of the
     1 Ibid.

-------
                                      II-4
                                  Exhibit II.1

                            SUMMARY OF RESPONSES TO
           1976 PETROLEUM REFINING INDUSTRY SECTION 308 QUESTIONNAIRE
Forecast 1984 Waste                Number of          Reported 1976 Crude Oil
Water Discharge Mode               Refineries           Processing Capacity
                                                            (1000 bpd)

No waste water discharge               50                       846.3

Direct discharge to
  receiving body                      165                    14,141.8

Indirect discharge to
  publicly or jointly
  owned treatment plants               47                     2,401.5

Facility not refinery                  12

Refinery did not operate
  in 1976                               4

No response                            21*                      219.0s

                                      299*                   17,389.6
* Includes nine with known discharge modes - 6 indirect, 1 direct, 1 both
  direct and indirect, 1 zero.

§ Estimated.

t Includes all refineries reported by the Bureau of Mines as existing in 1976.

-------
                                    II-5
world.  The  balance of  this  chapter  is  devoted to  developing  a  reasonable
estimate of the structure of the industry in 1984.

     C.I  Exogenous Economic Factors.  The legislation which established crude
oil and product price  controls and allocations  was scheduled  to  lapse before
1984.  Crude oil  price controls  were  lifted  in  1981.  The prices  of several
major product  classes, notably distillate  fuel  oil,  had already been decon-
trolled in  1979.  Motor  gasoline  was the  only significant  product  still con-
trolled in  1979.  Based  on the foregoing, it  was assumed that  the markets for
crude oil and  for refined  petroleum products  in  1984  will  not be  subject to
price controls.

     The quality of some  refined  products was forecast  to  change  between 1979
and 1984.  The predominant change was expected in gasoline.   By 1984, at least
three-fourths of motor gasoline will  not contain any lead anti-knock additive,
whereas in  1978, about one-third  of gasoline  was  unleaded.1  In addition, the
average sulfur content of  fuel oils was expected  to decrease steadily in res-
ponse to State Implementation  Plans for  sulfur dioxide emissions from existing
facilities and new  source performance  standards  for  new facilities.  At  the
same time, the average sulfur  content of crude oils available to U.S. refiner-
ies was expected  to increase.  Both  Alaskan  North  Slope and  Mexican Reforma
crude oils  are higher than average  in sulfur,  as are most Middle Eastern crude
oils.  The  effect of these quality  trends is  to  increase the cost of manufac-
turing refined petroleum products.

     The structure of  U.S. domestic demand  was  also  expected  to change from
1979 to 1984.2  it had been widely forecast that, because of federally mandated
efficiency rules,  domestic gasoline consumption  would  reach  a peak around 1980
and stay at  that  level for  four  to five years  before resuming growth.   Con-
versely, the consumption of distillate  fuel oil was forecast to  increase slowly
     1 Hydrocarbon Processing,  April 1979, p. 13.
     2 Projections £f Energy Supply and Demand and Their Impacts,  Annual Report
to Congress, 1977,  Volume  II,  Energy  Information Administration,  April 1978,
p. 115.

-------
                                      11-6
rather than to  follow the pattern of  gasoline.   It was  thought  that domestic
manufacture of residual fuel  oil  might grow even if consumption  were to stag-
nate, since a large fraction of supply was imported, and could therefore be cut
back in  favor  of domestic production.   In reality, the  large  petroleum price
increases which took  place in 1979/1980 caused consumption of  all  products to
fall much faster than was premised for this analysis.

     It was assumed that as current natural  gas  price  controls and allocations
lapsed, energy  consumed  by   refineries  (except purchased  electricity)  would
come to cost about the  same per BTU,  regardless  of  its form.   This  was not yet
the case in 1979, because some refineries had a cost advantage by being able to
use as plant  fuel  natural gas  which  was  contracted  several years  earlier at
low prices, or was priced controlled.

     Outside the U.S., it was forecast that OPEC would continue as an effective
cartel, maintaining  crude  oil prices  at  the  1979  real  price  or  higher.
Additionally, because all  OECD countries were  reducing  the allowable  sulfur
content of fuel  oils,l  and low-sulfur  crude oil reserves  accounted  for  only
about one-fifth  of total  free world reserves,2  low-sulfur  crude  oils  were
commanding premiums more   than justified by  the  costs  of  desulfurization.
Consequently, substantial  construction  of fuel  oil desulfurization facilities
was expected.•*  It was  reasonable to  assume that the  price  difference between
high-sulfur and low-sulfur  crude   oils  would  eventually  reach an  equilibrium
which would  reflect the long run  full  cost of  desulfurization.  That is, the
difference between high-sulfur and low-sulfur crude oil  prices would  be  such
that a  refinery  owner  would  be  indifferent  between two options:   purchasing
high-priced low-sulfur  crude  oil, or  purchasing low-priced  high-sulfur crude
oil and installing desulfurization equipment.
     1 Oil and Gas Journal, November 28, 1977, page 56.
     2 International Petroleum Encyclopedia, 1975, page 296.
     3 In  the  years  between 1978  and 1982,  demand  for  low sulfur  residual
fuel oils  declined  substantially,  so  there  was  a  reduced need  to  construct
desulfurization facilities.   But  an  increasing  need  developed  to  install
conversion facilities to  convert both high  and  low sulfur  residual  materials
into lighter products.

-------
                                      II-7
     There existed  in  1978, and  still  exists today, a large  worldwide excess
of crude  oil distillation  capacity.1   This  surplus capacity  means that high-
sulfur fuel  oils  will  be available indefinitely on  the  world  market at prices
averaging less  than ten  percent  above the  acquisition  cost of  crude  oil.

     C.2  Price Determination.   The  petroleum refining industry  had  been sub-
ject to  product  price controls  between 1971 and  1981.   Before  that time the
domestic market  for wholesale  oil products  was competitive  in the economic
meaning of  the  term.2  That  is, the price  elasticity  of demand facing indi-
vidual firms was high.

     Despite a  strong  and  continuing industry  effort to  establish brand dif-
ferentiation for  retail   consumers,   the   wholesale  petroleum product  market
operates on  a commodity  basis.   Perhaps one-third of gasoline,-*  about  half of
intermediates and almost  all  of residuals  are sold  as commodities.  With such
large volumes sold  as  commodities by many refiners, an active brokerage busi-
ness exists.  Nonbrand marketers  maintain  aggressive purchasing staffs  and oil
companies compete  vigorously  in  the  various  governmental,  institutional  and
commercial "bid" markets.

     Before price  controls,  prices on  the various  wholesale markets typically
were close  to,  and  varied with,  short-run marginal  costs.^  This  indicated
that the  industry  was highly  competitive and  that  refinery  gate  (wholesale)
product prices  were  based on  short-run  marginal  costs.  Because  of  this,
     1 Oil and Gas Journal, June 12, 1978, page 40.
     2 Executive  Office  of  The  President,   Energy  Policy  and Planning,  The
National Energy Plan, April 2, 1977, p. 59; and Federal Trade Commission, Staff
Report on Effect  of  Federal  Price and Allocation Regulations  on  the Petroleum
Industry, December 1976, p. 1.
     3 So-called "unbranded"  sales at retail  by independent oil companies, com-
mercial sales directly  to users  and  sales  to government  combine  to  roughly
over 30 percent of total gasoline sales.
     * Stephen  Sobotka  &  Company,   The  Impact £f_  Costs  Associated With  New
Environmental Standards  upon  the  Petroleum  Refining  Industry,   Council  on
Environmental Quality unnumbered contract, November 23, 1971, p. 37.

-------
                                      II-8
wholesale product prices changed essentially instantly  when  short-run marginal
costs changed.  For example, crude oil price changes were immediately reflected
in product prices.1

     Short-run marginal costs,  of  course, vary with capacity  utilization.   As
the demand for  products increases, more  and more  of  total  industry  capacity
must be brought  into use  to  clear the market.   Naturally,  the highest  cost,
least efficient,  capacity  is  the last to  be brought into  operation.  So  in-
creased capacity  utilization also means higher marginal costs.  At  some  point
in the expansion  of  production,  short-run marginal  costs  become equal to  long-
run marginal costs.  Long-run marginal costs are the total costs of  financing,
building and  operating  new manufacturing capacity.  Long-run marginal  costs
include raw material  costs, cash operating  costs (labor, purchased  power  and
fuel, chemicals,  materials, etc.) and  the capital-related costs of  owning  the
new facilities (ad valorem  and  income  taxes, insurance, return of  capital,  and
return on capital).

     To restate,  in the absence of price controls, wholesale  product  prices  for
petroleum products have been priced close  to short-run marginal refining costs.
Consequently, product prices  increase as more and more  of  industry  capacity
is utilized to meet  product demand.   At some  point, product prices  are suffi-
ciently high that investment in  new refining  capacity becomes  attractive, that
is, a desirable rate-of-return can be foreseen from an investment in additional
refining capacity.

     It is at  this  stage  of  the  capacity growth  cycle that  increased  fixed
costs become a  permanent  part  of the  price  structure,  since  the  new capacity
necessarily incurs all  total-cost changes.   For  example,  increases in property
taxes have no  impact on short-run marginal  costs but  must be fully reflected
in product prices before new refinery capacity will become an attractive invest-
ment.
     1 Short-run marginal  costs  always include raw materials,  purchased power
and fuel, and chemicals.   In  some  cases,  labor and maintenance  costs will also
vary with output.

-------
                                      II-9
     The above reasoning applies to effluent  water  treating  costs faced by new
refinery capacity,  and also  to other  environmental expenditures.   The  costs
are essentially  fixed  once the  facilities are  in  place.   So the  costs  enter
long-run, but not short-run, marginal costs.

     U.S. petroleum  refineries  face competition  not only from  each  other but
also from  foreign refineries.   As  was  stated  above,  there was  substantial
unutilized crude  oil distillation  capacity  in  the  world  in 1978.*  Despite
this spare capacity, large new  refineries were under construction or planned
in several Middle East  petroleum exporting countries.^  From a  world point-of
-view these  refineries  were  economically  unjustified.   They apparently  were
being constructed for strategic  reasons^ and  to  provide  employment  for nation-
als.  Regardless of  cause, the  effect  of this  construction  has perpetuated a
low utilization  rate  for  world  refineries,  particularly   those  in  Europe.

     In 1978, it  was less  expensive to  manufacture  products  in U.S. refineries
than in most foreign  plants because  of  domestic  crude  oil price  controls.
However, this crude  oil price advantage  was  to be phased  out  and U.S.  crude
oil was to be priced at  world  prices.   Therefore,  by  1984  all  refineries  in
the world were considered to have approximately identical crude oil acquisition
costs.

     Note that refineries  controlled by  petroleum  exporting  countries do  not
necessarily face the same  crude oil acquisition  costs as   other  refineries.
For competitive,  political or  strategic  reasons,   an exporting  country  can
choose to offer crude oil to its own refineries at a lower  price  than to anyone
else.  Given  time and  a  lack of tariff  protection,  a substantial portion  of
world refining capacity  could  be  acquired by crude  oil  exporting  countries
through use of preferential crude oil pricing.
     1 Oil and Gas Journal, June 12, 1978, p. 40.
     2 Ibid.
     3 Crude  oil  exporting  countries  that  own refineries  have more  pricing
freedom than do countries  that  do  not, since  prices for crude oil sales  (but not
refined products)  are fixed by OPEC.

-------
                                     11-10
     The National Energy  Plan implied, but  did not  specifically state,  that
maintenance of a  viable U.S.  petroleum refining industry  was a  part of  the
plan.  For  example,  the  strategic  petroleum  reserve program  was planned  to
acquire only crude oil, and crude oil  is useless without  refineries.   Moreover,
the Deputy  Secretary  of the  Department  of Energy  told  a Senate  Subcommittee
that refining capacity  on the East Coast  "must be increased."*  These observa-
tions established that it was reasonable to assume that a viable refining indus-
try would be maintained in the United  States.

     In 1979, it  seemed  that the industry might have required  protection against
low-priced imports from oil  exporting companies in order  to  remain  viable.
Protection could  have  taken many forms:   domestic   crude  oil  price  controls,
quotas on imported  finished products,  and tariffs   on  imported finished  pro-
ducts.  Each of  these methods could have  been used to  achieve a desired  size
for the domestic industry.  However,  the balance of  this report was  written as
if tariffs would be the method utilized to protect  the domestic industry.   This
is because product tariffs are  the  most straightforward and  easiest  to under-
stand protection method.  However, other  alternatives are  available  and might,
in practice, be utilized.2

     Of the possible  levels of  tariff  that could be imposed, four are of par-
ticular interest:

          C.2.a  No tariff.   In this  case,  industry capacity  would  gradually
decline if OPEC nations  engage in competitive practices.   But  there is a minimum
level of capacity that would be maintained.  That level is the capacity required
to process crude  oil  produced  in the  U.S.3  If U.S. refining  capacity were to
fall below that level,  some domestic  crude  oil would have to  be  exported for
refining, which  would result  in  lower wellhead value.   Consequently, in the
     1 Oil Daily, June 22, 1978.
     2 In  practice,  an import  quota is likely to be most  effective in protec-
tion is  desired against  excessive product  imports  from petroleum  importing
countries.
     3 The most economic location for  refining Alaskan North Slope oil is Japan.
However, legislation requires this oil to be domestically refined.

-------
                                     11-11
absence of  tariff  protection, U.S.  crude  oil prices  would adjust  to  protect
enough domestic refining capacity to process all domestic production.

          C.2.b  A  tariff  designed to maintain  industry capacity  at  approxi-
mately the  current  level.   Such  a tariff would  lead  to  attrition of the least
efficient refineries that currently exist in the U.S., offset by "debottleneck-
ing" expansion  of   efficient,  existing  refineries.   The average differential
between product  prices  and  crude  oil  acquisition  costs  resulting from  the
tariff would probably be  greater than the average differential  experienced in
1978.  This  observation was  based on an  FTC analysis 1  which  concluded  that
most refinery  capacity  expansion begun  in the  U.S.  since  1975  was associated
with the  small refiner bias  in  the  crude oil  entitlement system.  In other
words, almost  no  expansion took  place in refineries  that  faced average  U.S.
price differentials.

          C.2.c  A  tariff  designed  to  encourage  construction  of   enough  new
domestic refinery  capacity to  equal  the  future  growth in domestic  product
consumption.  This  tariff  would  have to  be  high enough that  the difference
between tariff-paid imported  product prices and (tariff-paid) imported  crude
oil prices  would be adequate  to justify  construction  of  new domestic capacity.

          C.2.d  A tariff designed to provide  for growth  and  also to phase  out
the currently substantial quantity of  residual  fuel  oil  imports.  To achieve a
more rapid  growth   of  output  of  residual  fuel  oil   than other  products,  the
tariff on residual  fuel  oil imports would  need to  be higher than in the preceding
case.

     Of the four tariff levels just discussed,  the second (hold constant capac-
ity) and the third  (encourage  refining capacity growth equal  to product consump-
tion growth) were  of  interest.   The no  tariff  case  seemed  to be inconsistent
with U.S.  policy, although it  was  the case actually  implemented.   The  highest
tariff case (phase  out  residual  imports)  would  lead to substantial  windfall
       Federal Trade Commission,  op.  cit.

-------
                                     11-12
profits for existing refineries and did not seem to be  necessary  for  strategic
reasons.*  Consequently, the economic  impact  analysis performed in this  study
included tariff  level  as  a parameter  to  be evaluated  at  two  levels.   The
effects of differing tariff levels are  depicted in  Exhibit II.2.

     C.3  Industry  Segmentation.   The  proper  basis upon  which to  segment  the
petroleum refining industry for an economic impact analysis of effluent  guide-
lines is the  individual  refinery, including  its  raw material acquisition  and
wholesale product  shipping  activities.   There  were   several  reasons  for this
conclusion:

          C.3.a  Revised  effluent guidelines  will   be  established  for each
individual refinery,, not  for  refining  companies,  or for  subdivisions of  re-
fineries.

          C.3.b  There is  an  active market  for all  domestic crude  oil  which
guarantees that  every barrel produced  will be purchased at the same  delivered
price that the purchaser pays  for other domestic crude oils of the same quality
at that location.  Consequently, a decision to close down a refinery will disad-
vantage the crude oil suppliers of that refinery only  by  the amount of  addition-
al transportation expense they may have to incur to  deliver  the  material to  a
different location.  Note that if the  location disadvantage  is severe,  it  may
be cheaper for crudes oil suppliers to reduce their  price to the existing nearby
refinery to enable it to keep going rather than to  absorb substantial  addition-
al transportation costs.

          C.3..C  Most refined  petroleum products are  fungible  and  widely avail-
able in  large quantities at  wholesale prices  that  are quoted daily in such
publications as  "Platts  Oilgram  Price  Service"  and "Oil Daily."  As  noted
earlier, over half  of  the  industry's  outturn is  sold  as  commodities  without
     1 Most  residual  fuel  oil imports  come  from  refineries  located  in  the
Caribbean.  These same refineries  would be available, in the event of an embargo,
to process crude oil stored under the strategic storage plan.

-------
                                                11-13
   CO
td
b.
b
U
       u
       3  0)
      TJ  O
       O •*
       U  U
      a. cu
                                                                                                  a
                                                                                                  H
                                                                                                        o o
                                                                                                        Q 83 Q
                                                                                                        O O 0
                                                                                                        U < td
                                                                                                        O O <
                                                                                                        C 4-1
                                                                                                        o u
                                                                                                        •H 10
                                                                                                        4-1 U-l
                                                                                                        a 3
                                                                                                        E C
                                                                                                           •H  a
                                                                                                           4J  4J
                                                                                                        •-I 03  U
                                                                                                        CO V  O
                                                                                                        u E  a

-------
                                     11-14
brand identification.   Moreover,  in  order  to  reduce  transportation  costs,
there is substantial trading between suppliers  of  products  that  are eventually
sold on the branded market.

     The decision to shut down  a  refinery, because of pollution  control  costs
or any other reason, is  based on  economic criteria.  The criteria  will  be the
same for an independent refinery as for one that is part of a company integrated
forward to the retail market and backwards to  crude  oil  production.  The deci-
sion to shut  down  would  be based  on an evaluation  of  the  cash  flow from the
refining/marketing system.   If  the present  value of  expected  future net  cash
flow generated by keeping the refinery  going is less than  the plant's  salvage
value, it would be  better to  scrap the  refinery than to keep it  in operation.
There are no  unusual  or hidden profits of  integration that need  to be  con-
sidered. 1

     The preceding  discussion shows  that the  individual refinery  rather  than
the company is the  proper level at  which to analyze the industry for refinery
closures.  More  important   than  intercompany   differences  are  the  different
types of refineries  that will  each  be  uniquely affected  by revised  effluent
treatment guidelines.

               C.S.c.i Discharge  mode.  There  are four modes  of  waste  water
discharge from refineries:   1) Many refineries  discharge no  effluent water.  In
some cases effluent water can all be disposed  by  such methods  as treatment and
reuse, underground  disposal  via  injection  wells,  percolation  into  sandy  or
gravelly soil, or  open  pit  evaporation.  Such  refineries  will  be unaffected
by effluent  guidelines.   2)  Several refineries  discharge  their  effluent  to
publicly-owned treatment  works  (POTWs)  for treatment.  Such arrangements  will
be regulated by revised  pretreatment guidelines.   3)  A few refineries,  notably
in the  San  Joaquin Valley  in  California and  along  the Houston  ship channel,
     * This has  not  always been  the case.   Before the  crude oil  production
depletion allowance was  repealed,  there probably were gains  from integration.
Also, transportation  facilities  probably  were  not  in  the  past,  and  it  is
alleged, may not presently be equally accessible to all refiners and marketers.

-------
                                     11-15
discharge effluent  to  jointly-owned  industrial  treatment  plants.   It  was
unclear whether such  refinery/treatment plant  combinations will be governed by
a combination  of  revised  pretreatment  guidelines  and  municipal  secondary
treatment regulations,  or by  revised  BATEA guidelines.   It was  assumed that
these refineries  are  not subject  to revised  BATEA guidelines.  4)  All  other
refineries discharge  directly into  receiving bodies.   These  plants  will  be
subject to revised  BAT guidelines.  A summary  of  refinery capacity  by  waste
water discharge mode was provided in Exhibit II.1.

               C.S.c.ii  New  or  existing  source.   New  refineries  will  be
subject to  new source  performance  standards  (NSPS or  PSNS).   Refineries  or
major expansions  of existing  refineries  for  which construction  starts  after
proposal of  these regulations will be  subject to these new  source standards.

               C.3.c.iii  Refinery process  unit  configuration.  Refinery con-
figuration is a  good  proxy for determining  the  value added  by refining.  The
more highly  configured  a refinery is  — that  is,  the more  complex it  is  —
the higher will be  the  average unit  value of  its products  and  hence its  value
added per unit of throughput.   It  is useful  to distinguish between five levels
of refinery  complexity.   1) The most  simple  plants  are those  that  have only
one significant processing  facility, a crude  oil distillation, or "topping",
unit.  Such  refineries  process crude  oil  into  residual  and  distillate fuel
or chemical  plants).   2)  Slightly more complex  refineries consist  of topping
capacity plus vacuum  distillation  of residual fuel oil.   Such  refineries pro-
cess high-sulfur  crude  oils into asphalt, high-sulfur distillate  and naphtha.
3) Refineries equipped with both topping and catalytic reforming facilities are
able to process crude oils into gasoline and fuel oils.  4) Refineries equipped
with topping and  catalytic reforming plus cracking (catalytic, hydro or thermal)
are able to  "convert" into  gasoline  some material that  would otherwise be fuel
oil.  Consequently, such  refineries  typically process crude  oils   into a high
fraction of gasoline,  plus kerosene jet fuel (for commercial aircraft) and low-
sulfur fuel  oils.   5) Refineries  equipped  for  the manufacture  of lubricating
oils are highly complex, requiring  large investment per unit volume of finished
lubricating oil.   Small lubricating oil refineries typically include only  cata-
lytic reforming in addition to topping  and lubricating oil  processes.

-------
                                     11-16
               C.3.c.lv  Geographic location.  Location is important  for judg-
ing a  refinery's  competitive  position.   The  least  advantageously  located
refinery would be  one sited in an  area, such as Houston, that has many other
refineries Which bring in  crude  oil and process it  into  products that  must  be
shipped to markets elsewhere  in  the United  States.  The most  advantageously
located refinery would be  adjacent  to  an oil producing field with most  of  its
sales within short truck delivery distance, and no other  refineries  or product
pipeline terminals in the area.

     Because so few refineries will be significantly affected by revised guide-
lines it was not necessary to develop a formal methodology  for  describing  the
competitive strength  or weakness  of geographic locations.  Rather,  this factor
was evaluated on an individual basis.

     C.4  Financial Status of Industry Segments.  As was discussed in the first
part of this section, the  financial status of  the petroleum refining industry
in 1978 was  not  considered relevant for judging the  impacts  of  1984  of revised
guidelines.  Instead, the  impact  assessment  was based on the financial status
that would be expected without price controls  but  with one or the other of  two
levels of government  protection of the industry.

          C.4.a  Low  protection.   A level  of  protection  was  assumed  that would
hold industry  capacity roughly  constant.   Some  capacity increase would  take
place in  refineries  that  are  competitively  well  situated and can be inexpen-
sively "debottlenecked," and  some abandonment of inefficient facilities would
take place.  With  this level  of  protection  the industry would be  financially
marginal.

          C.4.b  High protection.  A level of protection was assumed that would
cause the industry to grow at a rate equal  to  the growth in domestic consumption
of petroleum products.   With  this  level of  protection  the industry  would  be
financially strong.   The  difference in  price between  crude oil and finished
products would have to be  significantly greater than it was in 1978 to attract
new refining investments.   Then-existing refineries  therefore would  experience
greatly increased cash flows.

-------
                                  Chapter III
                                  METHODOLOGY

     This chapter  outlines  the methodology  used in  the  economic analysis  of
revised effluent guidelines for the petroleum  refining  industry.   The economic
impact analysis  included  two  keys steps:  determination  of the  price  effects
of the revised guidelines, and determination  of quantity and employment effects
associated with  price changes  and  with the shutdown  of plants  faced with high
costs to conform.

A.   Price Analysis

     The analysis  is  based  on two alternative levels of protective  tariff  on
imported petroleum products.   The  two levels  are explained and  justified  on
pages 11-10 and 11-11.

     The price in  a  competitive market for any manufactured product  is  deter-
mined by the cost  of the highest-cost  supplier whose  output clears the market.
In the  case of  petroleum  products in the U.S. market,  there  was  not  enough
existing domestic refinery capacity to clear the market for most  products.   So
the market clearing supply came from either imports or domestic  capacity expan-
sions.

     Foreign refineries had  substantial  idle  capacity  that could  have  been
operated at lower  costs  than can  many existing U.S.  refineries.  So,  in  the
absence of crude oil price controls the U.S.  market price  would, up to a point,
be determined by foreign refining costs plus U.S. import tariff costs.  However,
at some level of tariff,  the cost  of  imports  would have become greater than the
cost of products manufactured  in new U.S.  facilities.

     The price of  imports  was not affected at all  by revised  guidelines.   So
revised guidelines would  have had  no  impact   on  market  prices  of  petroleum
products at all tariff/quota levels below that  necessary to  encourage construc-
tion of new domestic capacity.

-------
                                     III-2
     At tariff  levels  sufficiently  high  to  encourage  new domestic  refinery
construction, revised guidelines for  new plants (NSPS or PSNS)  would  have had
a price effect.   U.S.  market prices  for petroleum products would have  had to
fully reflect the  full long-run  cost of  installing more  stringent  treatment
facilities, or the  new construction  would  not  have been  economically attrac-
tive and hence would not have taken place.
B.   Quantity Analysis

     At high tariff levels, revised NSPS and PSNS could have had a price effect
and an associated  quantity effect.  The  quantity  was determined  by  the price
elasticity of demand  for  petroleum products.   However, at that  overall market
price level, no  existing  refineries were forced to  shutdown  by the  costs  of
meeting the revised guidelines.

     At low levels of tariff, there would  be  no quantity effects due to price.
But there might have been shutdowns of  existing refineries  with high costs-to-
conform to  revised  guidelines.  The shutdown analysis entailed  comparing the
value of each existing discharging refinery with the  costs  of  conforming it to
revised guidelines.  The  value of the  existing refinery was  established  from
an investor's  point  of view:   that is,   as  a  source of  cash income.   From
that viewpoint, past capital investments  or the cost  to  reproduce the refinery
were irrelevant.  The only criteria that  established  value  were the amount and
timing of  future cash  to be  returned  to the  investor.   The  analysis,  then,
consisted of two steps:   estimation of  future  cash flows from the refineries,
and comparison of these cash flows  with the  costs  of conforming effluent qual-
ity from those refineries  to the requirements of revised guidelines.

     Since product prices  and consumption would not be affected by the costs of
conforming existing refineries to revised  guidelines, the shutdown analysis was
straightforward.  The cost  to  conform  each refinery  to  revised guidelines was
compared with the  value of each  refinery as  defined above.   Refineries  which
faced conforming costs  greater than their value would shut down.   All others

-------
                                     III-3
would continue  to  operate,  though their  value  would diminish  by  the  capi-
talized value of the costs to conform.

     It was  conceivable that  the salvage  value of  a plant  could  have  been
greater than its  value from  an investor's  viewpoint.  If  this  were  so,  the
plant would  be  scrapped even  though  it showed  a positive  present  value  cash
flow.  But this could not happen in practice, for the salvage value of refinery
equipment was predominantly based  on  its usefulness  to other refiners.  Prices
for salvaged refinery equipment  were  high  when it was  profitable to construct
and operate new refineries.  Conversely, when refinery operations were marginal,
salvage values were also low.

     The balance of trade  effects  of  revised guidelines would  reflect only the
necessity to replace volume from the very few refineries that would have chosen
to shut down rather than conform to the guidelines.  Employment effects  of  re-
vised guidelines would reflect the number  of new employees required to operate
and maintain the new effluent treating equipment offset  by the  number  of  em-
ployees losing work due to refinery shutdowns.

-------
                                   Chapter IV
                  COSTS OF CONFORMING PETROLEUM REFINERIES TO
          REVISED BATEA GUIDELINES, NEW SOURCE PERFORMANCE STANDARDS,
      PRETREATMENT GUIDELINES,  AND  PRETREATMENT  STANDARDS  FOR  NEW  SOURCES

     The cost data  used  in this study  consisted of two  sets  of capital costs
and operating  costs  for  most  refineries  that  discharged  during  1976  (see
"Coverage" in Section B  of Chapter II).  Five sets of costs were furnished for
a model new  refinery.  The data  were prepared by the Effluent Guidelines Divi-
sion, Office  of  Water and Hazardous Materials,  U.S.  Environmental Protection
Agency; and Burns and Roe  Industrial Services  Corp.*  All costs were stated in
dollars of  1977  purchasing power.   These  costs had been approved  for  use  in
this report  by EPA.  The  contractor  was instructed to  use the costs as revised
in the latest document.

A.   Existing Sources

     For indirectly discharging existing  refineries, costs  were developed for
two alternative treatment  methods.   Either method was  assumed to be applied to
effluent that has already  been  treated  to the quality  defined in Draft Supple-
ment for Pretreatment  to^  the Development  Document for the  Petroleum Refining
Industry Existing  Point   Source  Category,   EPA  440/1-76/083,   December  1976.
"Option 1"  is  to   treat   cooling • tower  blowdown  water   to  remove  chromium.
"Option 2" is a combination of  flow reduction, biological treatment, equaliza-
tion and filtration that  is  intended  to bring  pollutant mass  discharge  into
conformance with revised PSES.^
     1 The data  for direct dischargers  were  reported in March,  1979,  in Cost
Manual for the Direct  Discharge Segment of the Petroleum  Refining Industry as
revised on September 15, 1979.  The data for indirect dischargers were reported
in a letter from Burns and Roe to Sobotka & Co., Inc., dated May 18, 1979.  The
data for new source dischargers were reported in a letter from Burns and Roe to
Effluent Guidelines  Division,  U.S.  Environmental  Protection  Agency,  dated
April 11, 1979.
     2 The revised PSES definition used for Option 2 is not the same as the re-
vised BAT guideline  for  direct  dischargers.  The Option 2  definition  is asso-
ciated with a  version  of  the   Cost  Manual  that  was  issued  in April  1978.

-------
                                      IV-2
     For directly discharging  existing  refineries,  costs  were also  developed
for two alternative levels of treatment.  Either alternative  was  assumed  to  be
applied to effluent that has already  been treated  to best  practical technology
(BPT) quality.  For both levels the flow  was based  on 73 percent  of the "model
flow" computed  for  that refinery.   Details of  the model  flow equation  were
presented in the March 1979 "Cost Manual."

     Costs for  the  two levels  of treatment  were  derived  from the  following
treatment schemes:  Level 1 - flow reduction to 73  percent  of model flow, plus
installation of equalization and  filtration (if not already installed).  Level
2 -  all  Level 1  installations  plus  installation of  either  powdered  activated
carbon addition facilities  or rotating biological  contractors.

     The cost data are presented for direct  and indirect dischargers in Exhibits
IV.1 and  IV.2,  respectively.  Exhibit  IV.3 contains  a  summary  of  costs  for
these refineries.

     A term appears in Exhibits  IV.1, IV.2  and IV.3 that may require explana-
tion.  "Annualized  costs"  combine  capital  cost  and operating  cost  into  a
single value  that represents average total annual  disbursements  required  to
finance, operate, and  amortize  a facility.   The  "annualized costs"  presented
      i
in the exhibits are the sum of two components:

     A.I  The first component is  annual cash  operating costs for  labor,  mate-
rials, chemicals, energy,  insurance,  and ad valorem taxes.  These costs  were
those provided in the Cost Manual and the Burns and Roe  letters plus  the esti-
mated value  of  increased  and ad  valorem  taxes.   The  latter  costs  together
amount annually to about four percent  of original  capital investment.1
     1 Sobotka &  Company,  Inc.,  Economic  Impact £f_  EPA's  Regulations on  the
Petroleum Refining Industry, April  1976,  EPA 230/3-76-004, Part Two,  p.  II-2.
The data were supplied by Turner, Mason & Solomon from  a survey of Gulf refiners.

-------
                                      IV-3
     A.2  The  second component  is  capital  recovery and  return-on-investment
at the  rate of  12 percent  per  year, the  rate recommended  by EPA.*   It  was
assumed that the investments would have the following characteristics:  Twenty-
year physical  life,  sixteen-year  life  for  depreciation,  double  declining
balance depreciation  schedule, fifty  percent  income tax  rate,  no investment
tax credit,  no  working  capital,  no  salvage  value, and  construction  funds
spent over  a two-year  period:   thirty percent in the  first year  and seventy
percent in the second.

     These parameters led to  an  annual  before-tax   cash  flow requirement  of
twenty-one percent  of  capital  cost.  In  other words,  the  owners of  such  an
asset could,  on  average,  have  taken this  much  cash out  of  the  business
each year of its useful life.  Some of it,  of course,  must  have  been paid  as
income tax.

     The derivation of annual capital charges could have included other factors.
On the one hand, inclusion  of  the  investment tax  credit and  of  rapid amortiza-
tion (allowed for pollution control  facilities) would have led  to lower annual
charges.  Alternatively,  inclusion of  land costs (assumed to be  zero)  and  of
"sustaining" investments^  would  have  led  to  higher charges.   The  excluded
factors roughly  offset  each other.  The  effect of  higher annual  charges  was
derived in Chapter VII.

     Costs were  converted to a per-barrel basis  on  the assumption that  crude
oil throughput would  average ninety  percent  of calendar day  capacity.   It  was
noted that  such  a  rate  of capacity  utilization might  not  be achievable  by
     * Gerald  A.  Pogue,  Estimation £f_ the  Cost  of  Capital  for Major  U.S.
Industries, November 1975, EPA 230/3-76-001.
     2 Replacement of  worn out equipment; installation of  facilities  required
to meet new  and/or  revised environmental,  safety and health  regulations;  re-
placement of" obsolescent equipment with new equipment that costs less to operate
and/or maintain, such  as  more efficient furnaces and motors;  and  installation
of new equipment to  take advantage of technological advances, e.g., new cracking
or reforming  catalysts,  process  control  computers, etc.   See David F.  Hart,
Harvard Business  Review,   Vol.  46,  No.  5  (September/October 1968),  p.  32.

-------
                                            IV-4
some asphalt refineries  with  highly seasonal demand.  Reported  annual  average
operating rates in  1976  for asphalt refineries  ranged from 17  percent  to 100
percent of capacity.  Had  several  years of data been  available,  it would have
been better to  use a historical  average  rate  for each  plant rather than  an
assumed rate, but such data were not available.
B.   New Sources

     The costs of  conforming  new source refineries to  revised  guidelines were
computed for a specific model refinery.  The model1 was sized for a capacity of
190,000 barrels per calendar day of  Arabian  Light  crude oil.  The model was con-
figured for a  high yield  of gasoline, commercial jet  fuel and  distillate fuel
oil to correspond  with  demand  growth forecasts published  by  the Department of
Energy.2

     Current NSPS  (BADT)  regulations for new,  directly-discharging  refineries
corresponded closely to revised  Level 1  NSPS guidelines,  so  there was  no cost
for conforming the  model  to this level.   Revised Level  2  NSPS  guideline costs
represented the addition of  a powdered activated carbon facility  to the (assumed)
existing activated sludge unit.

     Level 1 revised guideline PSNS costs were based on chromium removal from
cooling tower  blowdown.   Level 2 revised PSNS  costs  were based on  installing
BPT technology,  including  activated  sludge treatment,  filtration,  and appro-
priate inplant controls.
     1 Memorandum from  Sobotka  & Co., Inc., to Office of  Analysis  and Evalua-
tion, NSPS Refinery_ Cpjnfiguration, February 14, 1979.
     2 Energy  Information  Administration,  Annual   Report  _t£  Congress  1977,
Volume JL! - Projections of_ Energy Supply and Demand and Their Impacts, DOE/EIA -
0036/2, April 1978, Chapter 5.

-------
                                      IV-5
     Costs of  conforming  the model new  refinery to revised NSPS  and  PSNS are

presented in Exhibit IV.4.  Also shown are  costs for achieving no aqueous dis-

charge . *
     1 EPA Internal Memorandum  from Effluent Guidelines Division  to Office of
Analysis and  Evaluation,  Compliance  Cost  for  Achieving  N£  Discharge  -  New
petroleum Refineries, 5 June  1979.   These  1972 costs were inflated to 1977 using
cost indices published in the Oil and Gas Journal.

-------
                             IV-6
                         Exhibit IV.1

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

TOPPING
2
6
70
100
189
197
199
255
266
292
Subtotal
ASPHALT
3
9
19
52
53
54
72
Distillation
Capacity
(1000 bpd)
CONFIGURATION
20.0
22.0
13.0
11.0
5.0
4.4
9.7
29.5
5.9
1.0
121.5
CONFIGURATION
1.2
3.5
2.5
4.0
14.0
3.0
8.5
Capital
Costs
Lev 1 Lev 2
(1000

0
0
12
0
0
0
125
0
130
0
267

0
0
0
0
0
0
0
$)

50
85
160
35
53
50
197
115
190
0
935

35
52
0
240
35
35
35
Operating
Costs
Lev 1
(1000

0
0
9
0
0
0
13
0
13
0
35

0
0
0
0
0
0
0
Lev 2
$/year)

11
11
33
11
8
8
23
15
74
0
194

6
8
0
26
19
12
18
Annualized Costs
Total
Lev 1
(1000

0
0
12
0
0
0
39
0
40
0
91

0
0
0
0
0
0
0
Lev 2
$/year)

22
29
67
18
19
18
64
39
114
0
390

13
19
0
76
26
19
25
Unit
Lev 1
Lev 2
(cents/barrel)

0
0
0.3
0
0
0
1.2
0
2.1
0

0
0
0
0
0
0
0

0.3
0.4
1.6
0.5
1.2
1.3
2.0
0.4
5.9
0

3.4
1.6
0
5.8
0.6
2.0
0.9

-------
                             IV-7
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

Distillation
Capacity
(1000 bpd)
Capital
Costs
Lev 1
Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
(cents
Lev 2
i/barre
ASPHALT CONFIGURATION (CONTINUED)
108
118
119
120
236
237
260
Subtotal
TOPPING PLUS
109
13.9
6.0
11.0
4.2
4.5
5.0
3.0
84.2
CHEMICALS
23.5
0
0
0
0
0
0
0
0

0
35
55
115
100
35
35
58
865

40
0
0
0
0
0
0
0
0

0
9
9
15
13
14
7
9
165

27
0
0
0
0
0
0
0
0

0
16
21
39
34
21
14
21
344

35
0
0
0
0
0
0
0

0
0.4
1.0
1.1
2.5
1.4
0.9
2.2

0.5
REFORMING CONFIGURATION
1
7
24
30
87
88
91
30.0
38.0
53.3
22.8
5.2
45.0
3.9
0
0
0
180
125
0
0
50
70
240
230
220
175
35
0
0
0
18
13
0
0
23
10
26
44
26
20
5
0
0
0
56
39
0
0
34
25
76
92
72
57
12
0
0
0
0.7
2.3
0
0
0.3
0.2
0.4
1.2
4.2
0.4
1.0

-------
                             IV-8
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

REFORMING
93
103
112
190
210
213
239
259
265
Subtotal
CRACKING
11
20
32
37
40
41
43
46
Distillation Capital
Capacity Costs
(1000 bpd)
CONFIGURATION
6.5
36.0
12.5
9.0
18.1
21.6
22.7
655.0
200.0
1,179.6
CONFIGURATION
47.0
100.0
110.0
103.0
405.0
365.0
80.0
65.5
Lev 1 Lev 2
(1000
(CONTINUED)
0
0
160
0
0
0
0
0
0
465 1

0
0
0 4
0 1
435
0 6
0 2
0
$)

35
78
330
60
35
73
35
75
48
,789

60
75
,000
,600
555
,400
,100
60
Operating
Costs
Lev 1
(1000

0
0
16
0
0
0
0
0
0
47

0
0
0
0
35
0
0
0
Lev 2
$/year)

7
11
36
9
6
10
18
172
53
476

70
153
352
148
550
546
186
75
Annual i zed Costs
Total
Lev 1
(1000

0
0
50
0
0
0
0
0
0
145

0
0
0
0
126
0
0
0
Lev 2
$/year)

14
27
105
22
13
25
25
188
63
850

83
169
1,192
484
667
1,890
627
88
Unit
Lev 1
Lev 2
(cents/barrel)

0
0
1.2
0
0
0
0
0
0

0
0
0
0
0.1
0
0
0

0.7
0.2
2.6
0.7
0.2
0.4
0.3
0.1
0.1

0.5
0.5
3.3
1.4
0.5
1.6
2.4
0.4

-------
                             IV-9
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

Distillation Capital
Capacity Costs
(1000 bpd)
Lev 1 Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$7yeaf)
Unit
Lev 1 Lev 2
(cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
49
50
51
56
57
59
60
61
62
63
64
65
67
68
71
74
76
77
80
33.5
21.5
150.0
40.0
107.0
57.0
195.0
200.0
295.0
91.0
78.0
154.0
380.0
140.0
21.0
22.5
42.5
23.2
52.0
0
0
865
195
530
0
0
0
0
0
235
370
2,610
385
0
0
180
0
0
120
565
3,140
1,100
630
75
75
80
100
1,900
310
470
5,860
485
200
170
1,430
40
90
0
0
602
22
112
0
0
0
0
0
25
42
379
54
0
0
19
0
0
15
57
1,030
106
678
88
148
208
377
125
221
328
869
434
230
20
135
30
13
0
0
784
63
223
0
0
0
0
0
74
120
927
135
0
0
57
0
0
40
176
1,689
337
810
104
164
225
398
524
286
427
2,100
536
65
56
435
38
32
0
0
1.6
0.5
0.6
0
0
0
0
0
0.3
0.2
0.7
0.3
0
0
0.4
0
0
0.4
2.5
3.4
2.6
2.3
0.6
0.3
0.3
0.4
1.8
1.1
0.8
1.7
1.2
0.9
0.8
3.1
0.5
0.2

-------
                            IV-10
                   Exhibit IV.I (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

Distillation
Capacity
(1000 bpd)
Capital
Costs
Lev 1
Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
81
83
84
85
92
94
96
97
98
99
102
104
105
106
113
115
116
117
121
57.0
90.0
80.0
138.0
270.0
85.0
528.0
50.0
202.3
28.7
90.0
298.0
89.0
154.9
42.0
131.9
68.0
30.0
295.0
160
0
0
0
480
228
0
0
0
0
230
0
305
0
0
0
0
355
0
1,040
85
75
95
2,810
303
2,480
35
1,600
83
305
4,100
380
1,100
330
90
900
945
3,100
16
0
0
0
50
22
0
0
0
0
23
0
34
0
0
0
0
23
0
99
195
142
268
479
169
442
12
144
11
45
344
218
104
34
220
84
80
275
50
0
0
0
151
70
0
0
0
0
71
0
98
0
0
0
0
98
0
317
213
158
288
1,069
233
963
19
480
28
109
1,205
298
335
103
239
273
278
926
0.3
0
0
0
0.2
0.3
0
0
0
0
0.2
0
0.3
0
0
0
0
1.0
0
1.7
0.7
0.6
0.6
1.2
0.8
0.6
0.1
0.7
0.3
0.4
1.2
1.0
0.7
0.7
0.6
1.2
2.8
1.0

-------
                            IV-11
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

Distillation Capital
Capacity Costs
(1000 bpd)
Lev 1
Lev 2
(1000 $)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
122
124
125
126
127
129
131
132
133
134
144
146
147
149
150
151
152
153
155
107.0
42.0
56.0
46.0
6.5
5.0
168.0
300.0
100.0
103.0
49.9
4.9
65.0
44.0
51.0
177.0
120.0
125.0
14.5
520
0
0
260
0
120
0
740
660
350
0
125
0
170
0
330
630
0
0
4,920
365
340
4,660
150
220
90
3,070
785
450
113
220
40
970
52
3,030
745
100
95
104
0
0
36
0
13
0
138
161
48
0
13
0
18
0
32
143
0
0
485
38
35
422
18
26
240
577
767
366
14
26
53
92
83
272
760
304
13
213
0
0
91
0
38
0
293
300
122
0
39
0
54
0
101
275
0
0
1,518
115
106
1,400
50
72
259
1,222
932
460
38
72
61
296
94
908
916
325
33
0.6
0
0
0.6
0
2.3
0
0.3
0.9
0.4
0
2.4
0
0.4
0
0.2
0.7
0
0
4.3
0.8
0.6
9.3
2.3
4.4
0.5
1.2
2.8
1.4
0.2
4.5
0.3
2.0
0.6
1.6
2.3
0.8
0.7

-------
                            IV-12
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

CRACKING
156
157
158
159
160
161
162
163
165
167
168
169
176
179
180
181
183
184
186
Distillation
Capacity
(1000
bpd)
Capital
Costs
Lev 1 Lev 2
(1000
$)
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
CONFIGURATION (CONTINUED)
55.
130.
54.
19.
23.
51.
90.
52.
60.
195.
170.
188.
52.
26.
80.
363.
63.
67.
185.
0
3
6
0
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
575
0
720
0
0
315
980 3
0
0
0
475
75
40
225
35
275
75
700
234
675
80
845
285
225
390
,540
420
75
75
0
0
0
0
0
0
0
0
0
82
0
125
0
0
41
145
0
0
0
48
164
51
24
22
29
201
70
26
482
231
799
30
25
261
590
42
103
149
0
0
0
0
0
0
0
0
0
203
0
276
0
0
107
351
0
0
0
148
180
59
71
29
87
217
217
75
624
248
976
90
72
343
1,333
130
119
165
0
0
0
0
0
0
0
0
0
0.3
0
0.4
0
0
0.4
0.3
0
0
0
0.8
0.4
0.3
1.1
0.4
0.5
0.7
1.3
0.4
1.0
0.4
1.6
0.5
0.8
1.3
1.1
0.6
0.5
0.3

-------
                            IV-13
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

Distillation Capital
Capacity Costs
(1000 bpd)
Lev 1
Lev 2
(1000 $)
Operating
Costs
Annualized Costs
Total
Lev 1 Lev 2
(1000 $/
year)
Unit
Lev 1 Lev 2 Lev 1 Lev 2
(1000 $
/year) (cents/barrel)
CRACKING CONFIGURATION (CONTINUED)
194
196
201
204
205
208
211
212
216
219
221
222
226
227
230
232
233
234
235
405.0
319.0
66.0
103.0
103.4
310.0
125.0
60.0
476.0
80.7
129.5
13.5
7.5
45.0
25.0
55.0
100.0
75.0
94.0
750
1,280
0
268
270
0
0
0
0
0
300
155
0
0
0
0
0
0
0
10,100
4,380
60
358
1,970
100
60
50
3,250
850
390
430
65
60
520
60
60
60
75
74
244
0
29
27
0
0
0
0
0
34
16
0
0
0
0
0
0
0
945
724
82
297
180
394
71
63
488
82
297
45
10
98
52
92
87
87
123
232
513
0
85
84
0
0
0
0
0
97
49
0
0
0
0
0
0
0
3,066
1,644
95
372
594
415
84
74
1,170
260
379
135
24
111
161
105
100
100
139
0.2
0.5
0
0.3
0.2
0
0
0
0
0
0.2
1.1
0
0
0
0
0
0
0
2.3
1.6
0.4
1.1
1.8
0.4
0.2
0.4
0.7
1.0
0.9
3.1
1.0
0.8
2.0
0.6
0.3
0.4
0.4

-------
                            IV-14
                   Exhibit IV.1 (continued)

      COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
          OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code
Distillation Capital
Capacity Costs
(1000 bpd) Lev 1
Lev 2
(1000 $)
CRACKING CONFIGURATION
238
243
252
256
257
261
Subtotal
LUBRICATING
10
12
89
90
154
172
173
174
177
240
241
78.0
42.0
10.6
40.0
150.0
40.0
12,568.9
Operating
Costs
Lev 1
(1000
Lev 2
$/year)
Annualized Costs
Total
Lev 1
(1000 :
Lev 2
$/year)
Unit
Lev 1
Lev 2
(cents/barrel)
(CONTINUED)
243
0
0
0
0
180
17,504
318
145
115
285
1,400
228
106,094
27
0
0
0
0
18
3,026
181
17
15
30
128
59
22,935
78
0
0
0
0
56
6,704
248
47
39
90
422
107
45,217
0.3
0
0
0
0
0.4
1.0
0.3
1.1
0.7
0.9
0.8
OIL CONFIGURATION
6.0
4.5
4.0
2.2
5.5
12.0
3.5
7.1
7.6
5.5
12.0
0
0
0
0
0
185
160
135
175
0
0
70
441
77
60
700
235
200
565
225
40
45
0
0
0
0
0
22
16
13
19
0
0
10
45
12
9
68
88
61
57
86
26
42
0
0
0
0
0
61
50
41
56
0
0
25
138
28
22
215
137
103
176
133
34
51
0
0
0
0
0
1.5
4.3
1.8
2.2
0
0
1.3
9.3
2.1
3.0
11.9
3.5
9.0
7.5
5.3
1.9
1.3

-------
                                           IV-15
                                  Exhibit IV.1 (continued)

                     COSTS TO DIRECTLY DISCHARGING PETROLEUM REFINERIES
                         OF CONFORMING TO REVISED BATEA GUIDELINES
               Crude Oil
Refinery
Code

LUBRICATING
242
258
Subtotal
Distillation
Capacity
(1000 bpd)
Capital
Costs
Lev 1 Lev 2
(1000 $)
Operating
Costs
Lev 1 Lev 2
(1000 $/year)
Annualized Costs
Total

Lev 1 Lev 2
(1000 $/year)
Unit
Lev 1 Lev 2
(cents/barrel)
OIL CONFIGURATION (CONTINUED)
5.2
85.5
160.0
0 40
0 60
655 2,758
0 30
0 86
70 620
0
0
208
38
99
1,199
0 2.3
0 0.4
PLANT DOES NOT PROCESS CRUDE OIL1
295
309
Subtotal
0.0
0.0
0.0
170 210
220 265
390 475
18 44
482 524
500 568
54
528
582
88
580
668


Grand Total
  Direct    14,141.8
19,281  112,956   3,678  24,985   7,730  48,703
  No entry for Item II.A in reply to Section 308 Questionnaire.

-------
                              IV-16
                           Exhibit IV.2

       COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
            OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

TOPPING
23
110
128
145
193
195
206
231
264
305
Subtotal
ASPHALT
8
18
31
79
107
148
166
Subtotal
Distillation
Capacity
(1000 bpd)
CONFIGURATION
16.0
6.0
3.8
5.2
3.2
1.0
36.5
10.0
23.0
13.0
116.9
CONFIGURATION
5.0
19.5
12.0
3.0
17.0
20.0
14.0
90.5
Capital
Costs
Opt 1
(1000

0
0
0
59
59
0
70
0
0
103
291

63
145
100
0
100
0
118
526
OPJL-2 .
$)

315
250
277
247
247
247
437
1,110
250
277
3,657

0
495
247
0
255
493
273
1,763
Operating
Costs
Opt 1 Opt 2
(1000 $/year)

0
0
0
9
9
0
11
0
0
15
44

10
19
14
0
14
0
17
74

73
67
41
65
65
65
113
422
66
41
1,018

0
78
65
0
68
131
108
450
Annualized Costs
Total
Opt 1
(1000 $

0
0
0
21
21
0
26
0
0
37
105

23
49
35
0
35
0
42
184
Opt 2
i/year)

139
120
99
117
117
117
205
655
119
99
1,787

0
182
117
0
122
235
165
821
Unit
Opt 1 Opt 2
(cents/barrel)

0
0
0
1.3
2.0
0
0.2
0
0
0.9

1.4
0.8
0.9
0
0.6
0
0.9

2.7
6.1
10.0
6.9
11.1
35.7
1.7
20.0
1.6
2.3

0
2.8
3.0
0
2.2
3.6
3.6

-------
                              IV-17
                     Exhibit IV.2 (continued)

       COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
            OF CONFORMING TO REVISED BATEA GUIDELINES
Crude Oil
Refinery
Code

Distillation
Capacity
(1000 bpd)
Capital
Costs
Opt 1
(1000
Opt 2
$)
Operating
Costs
Opt 1
(1000
Opt 2
$/year)
Annualized Costs
Total
Opt 1
(1000
Opt 2
$/year)
Unit
Opt 1
Opt 2
(cents/barrel)
TOPPING PLUS CHEMICALS
207
REFORMING
16
21
291
Subtotal
CRACKING
13
14
25
29
33
38
45
58
73
78
86
46.0
CONFIGURATION
48.0
20.0
15.2
83.2
CONFIGURATION
193.0
12.4
53.8
131.1
44.0
93.0
111.0
70.0
44.5
30.0
25.0
166

188
102
202
492

620
114
232
357
206
425
480
284
225
143
211
375

826
373
250
1,449

5,800
315
375
4,650
1,090
4,350
3,900
1,900
915
1,390
800
23

28
14
39
81

211
12
51
88
37
152
176
74
45
17
44
108

169
78
61
308

858
64
70
707
196
629
575
235
121
175
136
58

67
35
81
183

341
36
100
163
80
241
277
134
92
47
88
187

342
156
114
612

2,076
130
149
1,684
425
1,542
1,394
634
313
467
304
0.4

0.4
0.5
1.6

0.5
0.9
0.6
0.4
0.6
0.8
0.8
0.6
0.6
0.5
1.1
1.2

2.2
2.4
2.3

3.3
3.2
0.8
3.9
2.9
5.1
3.8
2.8
2.1
4.7
3.7

-------
                                           IV-18
                                  Exhibit IV.2 (continued)

                    COSTS TO INDIRECTLY DISCHARGING PETROLEUM REFINERIES
                         OF CONFORMING TO REVISED BATEA GUIDELINES
             Crude Oil
Refinery
Code

Distillation Capital
Capacity
(1000 bpd)
CRACKING CONFIGURATION
111
114
130
142
143
175
182
188
200
203
224
225
228
229
66.0
24.0
5.4
63.0
44.0
165.0
324.5
100.0
29.3
335.0
20.0
40.4
25.0
5.6
Costs
Opt 1
Opt 2
(1000 $)
Operating
Costs
Opt 1
(1000 $'
Annual! zed Costs
Total
Opt 2 Opt 1
/year)
Opt 2
(1000 $/year)
Unit
Opt 1
Opt 2
(cents/barrel)
(CONTINUED)
470
0
0
216
0
972
1,000
500
285
1,062
0
0
216
98
2,450
683
1,310
2,450
2,190
13,300
7,000
3,660
1,150
13,800
655
2,220
710
242
213
0
0
38
0
701
354
202
91
382
0
0
40
13
309
130
473
309
262
2,892
1,061
486
152
2,062
138
266
140
35
312
0
0
83
0
905
564
307
151
605
0
0
85
34
824
273
748
824
744
5,685
2,531
1,255
394
4,960
276
732
289
86
1.4
0
0
0.4
0
1.7
0.5
0.9
1.6
0.6
0
0
1.0
1.8
3.8
3.5
42.2
4.0
5.2
10.5
2.4
3.8
4.1
4.5
4.2
5.5
3.5
4.7
Subtotal    2,055.0
8,,H6   77,305   2,941   12,481  4,645  28,739
LUBRICATING OIL CONFIGURATION

  220          10.0           0
           258
0
67
0     121    0
3.7
Grand Total 2,401.6
  Indirect
9,591   84,807   3,163   14,432  5,175  32,267

-------
                                           IV-19
                                        Exhibit IV.3

                          SUMMARY OF COSTS TO PETROLEUM REFINERIES
                   OF CONFORMING TO REVISED EFFLUENT DISCHARGE GUIDELINES
                      Crude Oil
.lation Capital
icity Costs
Operating
Costs
Annual! zed
Costs
Total Unit
                      (1000 bpd)    (1000 $)  (1000 $/year)  (1000 $/year)  (cents/barrel)
DIRECT DISCHARGERS

  Level 1

  Level 2


INDIRECT DISCHARGERS

  Option 1             2,402

  Option 2             2,402
14,142
14,142
19,281
112,956
3,678
24,985
7,730
48,703
0.2
1.0
9,591
84,807
3,163
14,432
5,175
35,267
0.7
4.1

-------
                                             IV-20
                                          Exhibit IV.4

                               COSTS TO A NEW PETROLEUM REFINERY*
                     OF CONFORMING TO REVISED EFFLUENT DISCHARGE GUIDELINES
DIRECT DISCHARGE (NSPS)5

  Level 1

  Level 2


INDIRECT DISCHARGE (PSNS)t

  Option 1

  Option 2


NO AQUEOUS DISCHARGE8
                               Capital
                                Costs

                              (1000 $)
  Operating
    Costs

(1000 $/year)
         Annualized
            Costs
    Total           Unit
(1000 $/year)  (cents/barrel)
0
75
260
5,800
0
218
140
2,230
0
234
195
3,450
0
0.4
0.3
5.5
                              9,500
  1,880
  3,875
6.2
  Based on 171,000 barrels per day annual average throughput.

  Costs are additional above current NSPS (BADT).

  Costs are additional above current pretreatment guidelines for existing refineries.

-------
                                   Chapter V
                  ECONOMIC IMPACT ANALYSIS WITH HIGH LEVEL OF
                  PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS

     It was established  in  Chapter  III  that  either  of two levels  of protection
against refined  petroleum  product   imports  might  have  been  reasonably  ex-
pected to  be  in place in  1984.  In this  chapter,  a high level  of protection
was assumed.   Specifically,  the level  was  high  enough to  support growth  of
U.S. domestic refinery capacity at  about the  same  rate as the rate  of  growth
of consumption  of  petroleum  products.   In  this  situation,  the  market  would
have cleared at prices determined by the full  cost  of products manufactured in
new facilities.

A.   Price Effects of Revised Guidelines

     If new refinery  capacity  is to  be built, the  entire plant  must earn an
adequate rate  of  return.   This includes   the  effluent-treating  facilities.
Consequently, prices  with  revised  new  source  guidelines will be higher  by an
amount equal to the  full annualized cost  of the  facilities  needed to achieve
them.  The costs are.

Direct dischargers (NSPS)
     Level 1           no cost
     Level 2           0.009 cents per gallon refined product

Indirect dischargers (PSNS)
     Option 1          0.007 cents per gallon refined products
     Option 2          0.13    	

No aqueous discharge   0.15 cents per gallon refined product
     * Costs are  from  Chapter IV, Exhibit  6  divided by 0.94,  the  approximate
fractional yield of products from crude oil in new refineries.

-------
                                      V-2
     There was  no  way to  estimate  which of  the  above  four options, in  fact,
would have  turned  out  to  be associated  with  the price-determining  (market
clearing) refinery at any  specific time.  All that  could  be concluded  was that
the price effect of  revised new source guidelines  would  have  ranged from zero
to 0.15  cents  per gallon  of product manufactured  (stated in  1977  purchasing
power).
B.   Financial Effects

     This chapter assumed  that  new refineries  would  be fully  compensated for
all costs by tariff  protection.   Consequently, revised new  source guidelines,
by premise, had no financial effect on new refinery capacity.

     For existing refineries, the  financial impact  of  revised  guidelines  would
have been  the  difference between  the  benefits associated with higher product
prices caused by revised  new source guidelines, and the costs  associated with
meeting revised  guidelines  for  existing  sources.   As developed above,  the
benefits might have been as low as  zero or as high  as  0.15 cents  per  gallon of
refined product.   Existing  refineries  would  process roughly  5,435  million
barrels per year of  crude oil.*   So the annual benefit to existing refineries
from revised new source guidelines might have  been as low as  zero or as high
as 340 million dollars per year.^

     The total annualized cost to existing refineries  of revised guidelines for
existing sources would range from 13 million dollars per year  (BATEA Level  1 and
PSES Option 1)  to  81  million dollars  per year  (BATEA  Level  2  and  PTES Option
2).^  So the net financial  effect  on  existing refineries of  revised guidelines
might have been as adverse as a cost  of  (zero minus   81 =)  81  million dollars
     1 Chapter  IV,  Exhibit IV.3:  (14.142 +  2.402) million barrels  per  day x
0.9 operating ratio x 365 days per year.
     2 5,435 million  barrels  per  year x  0.062 dollars per  barrel  crude  oil
processed = 340 million dollars per year.
     3 Chapter IV, Exhibit IV.3.

-------
                                      V-3
per year or as beneficial as a revenue increase of (340 minus 13 =) 327 million
dollars per year.
C.   Production Effects

     This chapter was  based  on a premise of protection  against  imports suffi-
ciently high to support  growth of U.S. domestic refinery  capacity.   Hence "by
definition" there could  be  no production impacts of revised  new source guide-
lines on  new  refineries.  Whether  or not  revised  existing  source  guidelines
had an impact  depended  on how much the condition of the industry would change
from its  current  status if  a high protection  policy  were to be implemented.

     New refinery capacity^ required a difference between product sales revenue
and raw material  acquisition cost of  about  three dollars  per barrel  of  crude
oil processed^ to justify its construction.   During  1978 the difference between
revenue and raw material was approximately  2.3 dollars per barrel.3  Thus, the
gap between 1978  conditions  and  a  high  protection  policy   was 0.7  dollars per
barrel crude oil processed.  This improvement in condition  was greater than the
highest cost estimated  for conforming an existing  refinery to  revised guide-
lines:  0.42 dollars per barrel.^  So the  combination of high  protection and
revised guidelines would have left the highest  cost-to-conform refinery better
off than  in  1978 by roughly 0.28 dollars per  barrel  of crude  oil  processed.
Clearly, there would be  no  production effects  of revised  guidelines  if a high
protection policy was implemented.
     1 Size and configuration as outlined in Chapter IV, Section B.
     2 Sobotka &  Co. ,  Inc. , Capital  and Operating Costs  for  Grass Roots  Re-
fineries with  Several  Different  Process  Unit  Configurations,  Department  ojf
Energy Contract No. EJ-78-C-01-2834, Task No. 10,  April 12, 1979.
     3 Chase Manhattan Bank, The Petroleum Situation,  March 1979.
     4 Chapter IV, Exhibit 4, Refinery 130.

-------
                                      V-4
D.   Employment Effects

     Given high protection, no jobs  would  be lost in the U.S.  petroleum refin-
ing industry because of revised  effluent  guidelines.   New jobs would have been
created by  revised  guidelines.   New effluent-treating  facilities  would  have
needed to be operated, maintained, and  supervised.   It was possible to develop
rough estimates of  employment from  the data  prepared by Effluent  Guidelines
Division.  The estimates  were:
                                                     New Jobs
Existing Direct Dischargers
     Level 1                                             40
     Level 2                                            600

Existing Indirect  Dischargers
     Option 1                                            10
     Option 2                                           250

Hence, new  employment  could  have ranged  from  50  to 850 jobs, depending  on
which combination  of Level/Option was chosen for implementation.
E.   Community and Balance of Trade Effects

     Given high protection, revised  effluent  guidelines were  expected  to have
no community or balance-of-trade effects.

-------
                                   Chapter VI
                   ECONOMIC IMPACT ANALYSIS WITH LOW LEVEL OF
                  PROTECTION AGAINST PETROLEUM PRODUCT IMPORTS

     It was  noted  in  Chapter  II  that  either  of  two  levels  of  protection
against refined  product  imports might  have been expected to  be in  place in
1984.  In this chapter,  a low level of  protection was assumed.  Specifically,
the level was  such  that  the  capacity of the industry would remain roughly con-
stant during the period 1979-1990.  Of  course,  there  would be some shifting of
capacity as  inefficient  and/or  poorly located  plants   were  abandoned  while
efficient and/or  well-located  plants  expand  modestly  by  "debottlenecking"
existing facilities.   In this  situation,  the market  would  clear at  prices
determined by  the  costs of  imports  (including the  cost  of  tariffs,  if  any).

A.   Price Effects

     Market prices  for  petroleum  products will  be determined by the  costs  of
imports.  Import  costs  would be  unaffected by  U.S.  effluent  guidelines.   So
there would be no price effects of revised guidelines.
B.   Financial Effects

     Because petroleum product  prices  would  be unaffected  by revised  guide-
lines , the costs of revised  guidelines would have been  absorbed  by the petro-
leum refining industry.  The total  costs  of  revised  guidelines to the existing
industry were shown in Exhibit  IV.3  and are repeated  here.   The costs  for a
"model" new source were shown in Exhibit IV.4.

-------
                                      VI-2
Direct Dischargers
     Level 1
     Level 2
                       Capital
                        Costs
                      (1000 $)
 19,281
112,956
                                   Annualized Costs
  Operating
    Cost	
(1000 $/year)   (1000 $/year)  (cents/barrel)
                                Total
                Unit
     3,678
    24,985
 7,730
48,703
0.2
1.0
Indirect Dischargers
     Option 1            9,591
     Option 2           84,807
                 3,163
                14,432
                     5,175
                    32,267
                 0.7
                 4.1
These were small costs compared to  other  cost elements incurred by refineries,
e.g., raw material cost was about  14 dollars per barrel, cash  operating  costs
ranged from 0.50 to 2 dollars per barrel, and  capital  charges  ranged from 0.50
to 3 dollars per barrel.   It  was  concluded that revised  guidelines would have
a negligible  impact  on  the  financial status  of  the  industry  as  a  whole.
C.   Production Effects

     Although the average cost of revised guidelines would be small, there were
some refineries that  would have  faced  significant  cost  increases.   If  such
costs were  sufficiently  high, refiners  would have  been  better off  shutting
down than incurring the costs.   It was the purpose  of  this section to identify
high-cost refineries and  to  judge  whether  or not  they  were  likely to  shut
down.
     A reasonable minimum  value for  judging the  significance of  conformance
cost was one-tenth cent per  gallon,  or 4.2 cents per barrel.   One-fourth cent
per gallon is the usual increment by which price quotes for almost all products
are changed.  Also, it was essentially impossible to measure unit manufacturing
costs within one-tenth cent per  gallon,  because product  volume measurement was
not sufficiently accurate.

-------
                                      VI-3
     The 27 refineries  with  revised-guideline  costs  greater than 4.1 cents per
barrel of crude oil processed were listed in Exhibit VI.1.

     C-l  Values  of  Existing Refineries.   As  was stated  in Chapter  III,  the
value of an asset  to  an investor is the  present  value of  its  expected future
cash flow.   Of course,  no one  can compute the  present  value  with certainty
because all the facts  required  for the computation  lie in the  unknown future.
But it is possible to infer present values from actions that informed investors
are taking.   For  example,  if several informed  investors  decided independently
to invest in  new  catalytic cracking capacity, it  was  reasonable and useful to
assume that they expected the present value of  future  cash flow from new cata-
lytic cracking units to  equal (or exceed) the  cost  of  such units.  Conversely,
if existing crude oil distillation capacity in the world was more than adequate
to meet forecast 1990 needs, it was reasonable and useful  to assume that compe-
tition would have restricted cash flow from less efficient crude units to zero;
and no unit  would  have  come  anywhere near generating  a cash flow commensurate
with its replacement costs.

     In the  following  paragraphs,  estimates  of the values of  new processing
units were developed.   Except  where otherwise indicated,   evidence  of  new con-
struction was based on listings in Hydrocarbon  Processing, February 1979, and/or
Oil and Gas Journal, May 7,  1979.   Construction costs  of  new processing units
(stated in dollars  of  1977 purchasing power),  were  from  Sobotka &  Co., Inc.,
op. cit., April 12, 1979.  Adjustments for unit capacity and age were developed
after unit values are derived.

          C.I.a  Conversion processes and catalytic reforming.   In 1979, many
units of each of  these  processes   were  under  construction.  This  established
that many different  investors had  concluded  that acceptable  rates of return
could be expected  from investments  in  such units.  For  consistency  with  the
annualized costs computed  for revised guidelines  (Exhibit IV.1) it  was assumed
that a  discounted  cash  flow rate-of-return  of twelve  peripMit  per year  was
"acceptable."  The expected annual  before-tax  cash  flow  from  such  new units,
then, was 21  percent of  capital  cost.   Expected before-tax cash flows from new
large conversion and reforming units are

-------
                                      VT-4
                                  Exhibit VI.1

              EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
                     TO REVISED GUIDELINES OF MORE THAN 4.1
                    CENTS PER BARREL OF CRUDE OIL PROCESSED
             Crude Oil
Refinery
Code

130
195
231
154
193
175
128
12
126
173
174
145
110
266
52
225
177
143
38
78
Distillation
Capacity
(1000 bpd)
5.4
1.0
10.0
5.5
3.2
165.0
3.0
4.5
46.0
3.5
7.1
5.2
6.0
5.9
4.0
40.4
7.6
44.0
93.0
30.0
Configuration*
Discharge
Mode5
Compliance Costs
Lev /Opt Lev /Opt 2
(cents/barrel)
C
T
T
L
T
C
T
L
C
L
L
T
T
T
A
C
L
C
C
C
I
I
I
D
I
I
I
D
D
D
D
I
I
D
D
I
D
I
I
I




2.0
1.7


0.6
4.3
1.8
1.3

2.1


2.2

0.8
0.5
42.2
35.7
20.0
11.9
11.1
10.5
10.0
9.3
9.3
9.0
7.5
6.9
6.1
5.9
5.8
5.5
5.3
5.2
5.1
4.7
  As defined in Chapter III:   T = topping, A = asphalt,
  R = reforming, C = cracking, and L = lube.
§ Direct or Indirect

-------
                                    VI-5
                          Exhibit VI.1 (continued)

            EXISTING REFINERIES WITH ANNUALIZED COST TO CONFORM
                   TO REVISED GUIDELINES OF MORE THAN 4.1
                  CENTS PER BARREL OF CRUDE OIL PROCESSED
           Crude Oil
Refinery
Code

229
146
203
129
122
87
224
Distillation
Capacity
(1000 bpd)
5.6
4.9
335.0
5.0
107.0
5.2
20.0
Configuration*
Discharge
Mode8
Compliance Costs
Lev/ Opt Lev/ Opt 2
(cents/barrel)
C
C
C
C
C
R
C
I
D
I
D
D
D
I
1.8
2.4
0.6
2.3
0.6
2.3

4.7
4.5
4.5
4.4
4.3
4.2
4.2
As defined in Chapter III:   T = topping, A = asphalt,
R = reforming, C = cracking, and L = lube.

Direct or Indirect

-------
                                      VI-6
Process

Catalytic
  cracking
Alkylation
Hydrocracking
Thermal cracking t
Delayed
  coking
Catalytic reforming
  (including naphtha
   desulfurization)
                                  Expected Annual Cash Flow
  Capacity,
  Thousand         Total Cost *      Total         Unit §
(barrels/day)   (million 1978 $)  (million $) ($/barrel/day cap.)
127
61
126
27
26.7
12.8
26.5
5.7
485
640
590
285
     55
     20 §
     45
     20

     20                 40            8.4
     35                 83           17.4
* Including offsite and associated costs.
§ Thousand barrels per day of product.
t Estimated.
420
500
          C.l.b  Lubricating  oil  manufacture.  The  operation of  this  complex
combination of processes  created  substantial cash flow.  Since  World  War II, 1
lubricating oil manufacture had generated a before-tax cash flow ranging between
two and  four  dollars  per barrel  manufactured.^  Also, the demand  facing U.S.
and free world lubricating oil manufacturers was growing at least as rapidly as
is manufacturing  capacity.3  Consequently,  a  continuation of before-tax cash
flows at historical levels  seemed assured for  many  years.   On  the  same basis
as tabulated above, the expected annual cash flow from lubricating oil manufac-
ture was about 1,200 dollars per barrel of calendar day capacity.^
     1 With the exception of the Arab oil boycott of 1973 and 1974.
     2 R.F. Sommerville, Hydrocarbon Processing , August 1977, p. 127
     3 Ibid.
       ($3.00  per  barrel  x  365 days  per  year)/0.9  capacity  utilization.

-------
                                      VI-7
          C.l.c  Crude oil distillation.  There existed  in 1978 a large world-
wide surplus of crude oil distillation capacity.1  Consequently, in the absence
of tariff or quota protection, the only cash flow that would have been expected
from a large  new  crude  unit  would  have been a  reduction in  company income
taxes due to tax depreciation of the new unit.  This amounted to 3.5 percent of
capital cost, which  was  about fifteen dollars per  year  per barrel  of calendar
day capacity (for a 150,000 barrel per day unit).2

     Small crude  oil distillation  units owned  by  small  refiners  were in  a
different situation in 1978.  Such units received  an  outright  subsidy from the
federal government via the  "entitlements"  system.  The  amounts  of  the subsidy
were:3

         Company Refining Capacity                      Subsidy
         (thousand barrels per day)               (cents per barrel)
                 below  10                                 96
                 10  -  30                                 53
                 30  -  50                                 28
                 50  - 100                                  9

     This study assumed that the subsidy would be negligible by 1984.

          C.l.d  Adjustments for size and age of process units.   All else equal,
a small process unit  would  cost more to build, per barrel  of  capacity, than  a
large unit.  It  follows  that,  if  they  were to be economical  to build,  small
units must also have generated more cash flow per  barrel than  large ones.   But
this logic was overlooked here.  Rather, all  units  of a  given  process, regard-
less of size, were assumed to generate  the  same annual cash flow per barrel of
capacity.   This assumption may have understated the value  of small  units.   But
     1 Oil and Gas Journal, June 12,  1978,  p.  40.
     2 Capital cost about sixty million dollars.
     3 Oil and Gas Journal, May 9,  1979, p.  48.

-------
                                      VI-8
it seemed  better  to  risk overstating  the impact  of revised  guidelines  (by
understating the  value  of  affected   refineries)  than  to  risk  understating
them.

     All else equal, an  old  process unit  was  less  valuable than a new one  of
the same size and capability, both  because a new unit  was  expected to  generate
cash for more years than an old one, and because a new unit  should have costed
less to maintain.

     It was  difficult  to  judge the  remaining life  of  a  process unit.    For
example, there were more than a dozen catalytic cracking units that were  first
built in  1944 and  1945 that had  been  so thoroughly rebuilt  and modernized
that they  were  almost as  efficient as brand  new units,  despite  33  years  of
operation.  Nevertheless, it  was appropriate to recognize  old units are not as
valuable as  new ones.   A  useful  way to account  for  this  lower value was  to
utilize lower values for  the  annual  cash  flow estimates  that were  tabulated in
Sections C.I.a and  b.  above.   A reasonable  factor  is one-half.   That is,  the
average annual cash flow expected from an "old" unit over the next, say, thirty
years was one-half that expected from a new unit.^

     From the above and,  for  convenience,  averaging the costs of  processes  of
nearly equal  value, the  following  estimates  were  used for  computing the  value
of an existing refinery:
     1 This  is  equivalent to  estimating  that  the old unit  will last for  six
years and  the new unit for thirty:  The present value of  an  annuity of  $1  per
year for  6 years  at  12 percent  per  year is  $4.3.   The  present  value  of  an
annuity of $1 per year for 30 years at 12 percent per year is $8.5.

-------
                                      VI-9
             Process                         Expected Annual Cash Flow,
                                              ($/barrel/day capacity)
             Lubricating oil                            600
             Alkylation                                 300
             Hydrocracking                              300
             Catalytic reforming
               (including naphtha
                desulfurizatlon)                        250
             Catalytic cracking                         250
             Delayed coking                             200
             Thermal cracking                           150
             Crude oil distillation                      10

          C.l.e  Asphalt  manufacture.   This process  was  not  Included  in the
above table,  because  in  contrast to  other refinery  processes,  the value  of
most asphalt manufacturing facilities was determined predominantly by the level
and relative location  of  roadbuilding activity.  If roadbuilding  activity was
strong.(so  that  the  asphalt  plant  is  operating near  capacity)  and  located
nearby (so  that  the plant has  a shipping cost  advantage  over  its  competitors)
the plant generated a  high cash flow.  On  the  other hand,  sporadic  roadbuild-
ing activity located well  away from  the plant  might have led to essentially no
cash flow.

     For these reasons, the  asphalt  refinery listed in Exhibit  VI. 1  was evalu-
ated on  the basis of  implied  roadbuilding  activities  rather  than  on  process
unit value.

     C.2  Guidelines Cost  Versus  Refinery Value.  In Exhibit VI.2,  the values
and revised  guidelines compliance  costs   for  the   26  non-asphalt  refineries
listed in Exhibit 7 were  compared.   Costs  and  values  were  stated  on an annual
basis.  Compliance costs are from Exhibit IV.1;  values  were computed by multi-
plying process unit capacities  reported by  the refineries  in their  replies  to
the "Section  308 Questionnaire"  times  the estimated  annual  per-barrel  cash
flows tabulated in Section C.l.d.  above.

-------
                                     VI-10
     Exhibit VI.2 has shown that nineteen refineries had expected cash flows from
their process units that were substantially greater than the cash flows required
to meet revised  guidelines.   These plants clearly  would have been  willing to
conform to revised guidelines in order to preserve their cash flow.  The remain-
ing seven  (non-asphalt)  refineries had Level  2 or  Option 2  compliance  costs
greater than their process unit values.  All of these  refineries  were of "top-
ping" configuration.

     C.3  Evaluation  of  High  Cost Refineries.  The seven topping  refineries
are discussed individually in order of refinery  code number.   Then the asphalt
refinery is discussed.

          C.3.a  Refinery 110  was located in  Michigan about  125 miles  north-
west of Detroit.   This  plant faced revised  guideline costs  (indirect,  Option
2) of six  cents  per barrel  crude oil processed, compared  to  an estimated pro-
cess unit value of six cents  per barrel.

     Refinery 110  began  operating before 1970.*  The  plant  sold one-tenth of
its 1976  output  as  gasoline,  and one-quarter  as  military   jet  fuel.2   The
principal competition for gasoline and fuel  oil  sales  comes from a forty thou-
sand barrel-per-day cracking  refinery located about fifteen miles away.

     It appeared  that  the future  of  Refinery 110  was independent  of revised
guideline costs.  If a small  refiner subsidy had been maintained, even at a low
level, this plant most probably would have been willing to incur revised guide-
line costs and keep  operating.   But,  without such a benefit,  the refinery had
little or  no  value and  might  have chosen  to shut  down.   (However,  the plant
operated in the early 1970s   without subsidy.)  Revised guideline costs did not
appear to  be  large enough to  significantly  influence  the decision  of whether
or not to shut down.
     1 U.S.  Bureau  of  Mines,  Petroleum  Refineries jLn  the United  States  and
Puerto Rico, published annually.
     2 Reply to Section 308 questionnaire.

-------
VI-11



































CM
«
M
>
4J
1-1
JO
•H
J=
X
u





























































CO
M
.J
CO U
gs
J *^1




































*
fa

J5
a

1-1
i
B
•<«
•a
01
4-1
a
•H
4J
CO
























ts
4J
•H
U
CO
O.
a
u

4-1
•H
B
9

CO
CD
Ol
U
O
t-t
OH















1
0)
4J ^3
•H 00 t-l 4J
C 3 3 eo
0 BO 0
» 2: 73
CO CU CD
CU 0) CO CU
CJ 3 •* B
O •-! > -H
t. CO CU iH
0- > Od
CU CD
3 3 *J
rH B B)
«B -H O
> X 0

•C 1
01 01 CO
CC *t3 OJ 4J
O -rJ -H C OS
H > 3 'H O
0) O •-! CJ
Pi

co
CD CO
E Ot 4J CU
O O «H 3
t-i O B iH
B^. tj ^^ rt
£ >
bo
r-( B
§2
b U
cu cd
P CJ


bO
B
•H

O
CJ

C
•H hO
^j C
>t -H
fH ^
id u
4J <0
a u
CJ CJ
u bo
•H B

>> H
t-i C
eo o
^J ^J
« a


ho
1 B
O -H

73 CJ
^s cd
£ S
u


1
*4 B
>•. O
Jd -H
iH 4J
< «
01
^ ^H
.3 S
0)
Eg
CJ
0) CU
B 73
•H 0
0)
/•>
rH
0)
b
^
« ^ ^
-^aoo-*^ mvo-*oo

B
CU
u
m^mm comchcM
cowincy>in<^coin
v_/ • •
5 "^

«/>
ooor>»u^»nt^iney>oo
O^^4U^'*4 ^^OOCT^CO
CO ^^ ^* MD CM ^H vO ^*
«— i •
x-» m


coooo«»ooo
00 CM CO '**' *G CO ^O C7^
oo CM r» "i CM
« «l
5 -


















— o
• •
CM m
r^


^
^^
td
73 O O
t-i -3 in
01 -*
a

CO
^H
0)

^4
03
,fl

O
0
O

x_^
o
•
CM

O O O
-4 r»> CM
•^
-^oomojooin
in«-4omcomcoooc»j
ro CT^ f^ *^ ^^ ^" ^^ ^^
^H M-4 ^| ^H ^^ ^H ^^





^
m CM m -H o o




m r«. 1-1 co o sr
OO 00 ON *^ ^^
CO CM O\ ^x
• » «
Z3 *"* *"*


O CO \O Is* O •*
o o r>» -^ CM i-<

*"*


m o r*. -* o oo
00 O> \O O CM -H
^. CO f— t «-^ ^^ ^^
*> « «
CM -H CM
•—4









CM
•
in






CM
•
ON
•™"*





in CM — t
•* -< CM
^H





\O
•
*^






^tf
•
CO

r*. in
-- CM

o m -H CM o ON
\o co r»> in vo m


vo co ^ m o vo



-------
VI-12
































.^N,
•c
V
3
C
•H
4J
C
o
u
V— '

CM
M
^

4J
•H
.0
•H
X
w























































en
M
J
en u
gs
3g
>
a
H W
M cn
Z i-i
s >
u
en oJ
en
Cd O
CJ H
o
2 £
Pu S
o
M^ &4
O Z
o
S5 CJ
O
en o
Wt^
P^
2t! H
a. en
S o
O CJ
cn
i
u

































o
iH
h
,£.
CO
CO
CJ

iH
Annua
•a
CJ
4J
«
B
•H
^J
.3























>>
4J
•H
U
a
d
4-1
*rt

CO
CO
CU
u
O

P*













1
01
4J TJ
•H 0) f4 U
C 3 3 m
» p cs o
co 32 -a
03 0) 00
cu a* eg cu
O 3 -H C
0 r-t > .H
kl (0 CU i-l
a. > pd
ttJ 0)
3 3 w
•H C »
CO «H O
> X CJ



•0 1
CU CU CO
W T3  3 TH O
0) 0 rH CJ

CO
co ca

O O il 3
(4 O C iH
b fc" S CO
CM >
bO
•H C

h U
CU A
•C k^
H CJ


be
e
•H

cS

u
1-1 bo
•u C
X-H

CO U
4J CO
CO h
CJ CJ

U eo
•H C
U -rj
.H 1
(0 O
JJ M-(
CJ Qj

i c1
0 -H

•O 0
X «
X t-i
u


rH C
>» 0
£t 1-1
«^
IS
•SrH
2S
0
CU 0)
B -0
•H O
1-4 O
01

x-s
I-l
0)
S \
^o co sr sr sr ON
•>^ sr co m oo m
CO
jj
e
5
NO ON -^ 00 NO
PH m NO sr co
r». oo rx in oo
m r*" m in
CM


x-s
 «»
NO oo r*. NO
CM









0 0

r^. "^
CO



o o o m

00 ON CD ^**
-H -H sr ^^



^•^
>,
cd
•o moo
(4 -4 — m
CU -^ CM
a
ca
^H
CU
14
cd
pO

o
o
o

00 NO NO
• • •
CO OO CM
^
—
sr NO o o o
o r-. sr co o
sr sr OA co


m r«» co oo oo
cs r^ sr co r^
CM -H —






sr co r^ co •-^ r^
\o sr r^ CM m >-*




NO «^ O CO CS CS
r» o> cs oo cs eo
-H NO CS (O ON CS
-* m r».
00 "H




NO CM O CS 00 CM
co r* NO r» — 4 ?v
o\ in



CM co o m o sr
NO NO oo m sr in
cs r^ -H sr sr co
« •> »
•— 4 O ON


i *i
•H CS





0 0

t^v ^^
es —4



NO O O
• • •
sr o —
sr sr






o o — o o
CM es O sr •-«
O -H


o
•
Q\
CM




o m
* *
CM sr
"«^
00
00
NO ON O O O CM
m sr m m r- m
CO O
CO -*

ON vO CO ON CM r^
cs sr o cs cs oo
es -< CM -H -<






m





o
<™^
<^v
^





NO
CM



m
r»«
cs
*
—
















m
v
CO

























o
0
CM


sr
cs
CM


-------
                                     VI-13
          C.3.b  Refinery  128  was  located  in Northeastern Montana.  This plant
faced revised  guideline costs  (indirect,  Option  2)  of  ten cents  per barrel
crude oil processed,  compared  to an estimated process unit  value  of six cents
per barrel.

     Refinery 128 began operation before 1970.  It changed  ownership in 1977*
and the  new owners  Increased  capacity  from  3,000 to  4,500 barrels  per  day
during 1978.2  During 1976, forty percent of  the  refinery's outturn was military
jet fuel.  No  gasoline  was manufactured.3   Principal competition  for residual
fuel oil sales came  from another small refinery located  about  100 miles east;
jet fuel, diesel  fuel,  and distillate fuel oil  competition  also arises from a
pipeline terminal located about 100 miles south.

     This plant was located in a crude oil producing area.  The local crude oil
gave high yields of jet and diesel fuels.  Operations  associated with
crude oil production and transportation consumed diesel  fuel.

     It was concluded that  this refinery was viable without  subsidy.   And  its
strong location,  adjacent  to  both  its  crude oil  supply and markets,  made it
probable that the owners  would have been willing  to absorb  guideline conform-
ance costs and  to continue operations.  It  was  also possible  that  they might
have persuaded their crude oil suppliers to share some of the costs.

          C.3.c  Refiner 145  was located in Southwest North  Dakota.   It faced
revised guideline costs (indirect, Option 2)  of seven  cents per barrel of crude
oil processed, compared to an  estimated process unit value of six  cents  per
barrel.

     Refinery 145 began operations in  1974, after the  small  refiner  subsidy
program went into effect.   The plant  processed crude oil produced  nearby.   It
     1 Bureau of  Mines/Department of  Energy, Petroleum  Refineries,  op.  cit.
     2 Oil and Gas Journal, March 26, 1979, p. 129.
     3 Reply to Section 308 Questionnaire.

-------
                                     VI-14
manufactured no  gasoline  or  jet  fuel In  1976.   Principal  competition  came
from a fifty thousand barrel-per-day  refinery  located  about eighty miles east,
and from a  products pipeline terminal located about  ninety miles  northwest.

     Because of  its  location,  Refinery 145 appeared to  be viable  as  a diesel
fuel and fuel  oil manufacturer  without  federal subsidy  or tariff protection.
It would probably not have been economic to build  without  subsidy.   But,  once
built, its  transportation  cost  advantage  relative to  its  competition  should
have enabled it  to  continue in business.  Revised  guideline  costs  did not ap-
pear to be high enough to jeopardize its viability.

          C.3.d  Refinery  193  was located in  the  Houston,  Texas,  metropolitan
area.  It faced  revised  guideline costs (indirect,  Option  2) of  eleven cents
per barrel  crude  oil processed,  compared to an estimated  process unit  value of
six cents per barrel.

     This refinery began operations before 1970.   It  expanded by  about fifty
percent after the  small  refiner  subsidy program went  into  effect.   The plant
reported an  outturn  of  fifty percent  gasoline in 1976.  Since it  had neither
cracking nor reforming  facilities, it  was assumed that  much of the  gasoline,
perhaps as much  as  two-thirds,  was high-octane blending  stocks purchased  from
nearby refineries.   Competition  arose from these same  refineries;   over  one
million barrels per day of refining capacity was located within thirty miles of
Refinery 193.

     The estimated  conformance  costs  for this plant included no  provision for
land.  It  was  understood informally that the  plant  had  such severe  space re-
strictions  that  the  installation of  a water  treatment facility that  required
any significant land area  could  be accomplished  only by removing  some existing
tankage or by purchasing expensive adjacent land.  If this information was cor-
rect, Refinery 193  was  facing higher  conformance  costs than eleven  cents per
barrel.

-------
                                     VI-15
     It was  not  possible to  estimate the actual  cost for  this  plant without
engineering and  real estate  data.   However,  it  appeared  that  this  refinery
might have  chosen to  shut  down  rather  than incur  revised  guideline  costs.

          C.S.e  Refinery 195 was located near  San Antonio,  Texas.   It  faced
revised guideline  costs  (indirect, Option 2)  of 36 cents  per barrel  of crude
oil processed, compared  to  an  estimated process unit  value of  six  cents per
barrel.

     Refinery 195  began operations  before  1970.   The  plant  manufactured  no
gasoline or  jet   fuel  in  1976.   Principal  competition  came  from two  small
nearby refineries,  and  from  five nearby pipeline terminals  that distributed
products refined along the Texas Gulf Coast.

     Refinery 195  and its neighbors  appeared to have a significant transporta-
tion advantage compared to their  competitors.  Texas  crude oil flowed  past San
Antonio on its way east to Gulf Coast refineries and products flowed back west
to San Antonio.   However, it  seemed  doubtful that  the  advantage  was enough to
compensate for the high revised-guideline costs.

     It was  concluded that  Refinery  195  would have incurred revised-guideline
costs only  if  federal  subsidies  to  small  refiners  continued at  fairly high
levels.  Without subsidy, revised  guidelines  costs apparently would have caused
it to choose to shut down.

          C.3.f  Refinery 231 was  located near Salt Lake City, Utah.  It faced
revised guideline  costs (indirect, Option 2) of twenty cents  per barrel  crude
oil processed, compared  to  an  estimated process unit  value of  six  cents per
barrel.

     This plant began operations  in  1973,  and  expanded  from  one  thousand  to
ten thousand barrels per day  capacity in 1974, after the  small refiner subsidy
program went into effect.   Forty percent of outturn in 1976 was motor gasoline.
As was the case for Refinery 193,  it  could be assumed that much of this product

-------
                                     VI-16
was high octane  blending components procured  from  one or more  of six  nearby
refineries.  These plants were  equipped  with catalytic cracking  and  catalytic
reforming.   Competition for  Refinery 231  arose from  these  same plants.

     It appeared that  Refinery  231 was  an "entitlements  refinery,"  i.e.,  its
existence was dependent on  federal  subsidy.1   It was likely  that  this  plant's
outturn could have been  more  economically supplied  by  minor expansion of  one
or more of  the nearby refineries.   If this analysis  was  correct,  the refinery's
future was  determined  by  federal  subsidy  policies  rather than revised  guide-
lines.

     However, even if  the  refinery was  competively viable without  subsidy,
revised guideline costs probably  would have caused  it  to shut down.   Revised
guideline costs faced  by  every  neighboring refinery were  less than  four  cents
per barrel.^ The revised  guideline  cost  disadvantage of  over one-half  million
dollars per year,3 and the capital requirement of 1.1 million dollars4 appeared
to be too large to face.

          C.3.g  Refinery 266  was  located in  Southwestern  Michigan,  roughly
equidistant from  Chicago, Detroit,  and  Toledo,  where  the  nearest  refineries
were located.  This  plant faced revised  guideline  costs  (direct, Level  2)  of
six cents per barrel  crude oil processed, compared to an estimated process unit
value of six  cents per barrel.   In 1976  the plant processed mostly Canadian
crude oil  (transported in the nearby lakehead pipeline)  and some local  crude
oil.5
     1 However, it  must be  noted  that  Refinery  193  in Houston has  even less
reason to exist, but has been in business for over a decade.
     2 Exhibits IV.1:  Refinery 288.
     3 (0.2 - 0.035 cents/barrel) x (10,000 barrels/day capacity) x (0.9 utili-
zation factor) x (365 days/year) « $0.54 million/year.
     4 Exhibit VI.1.
     5 Reply to Section 308 questionnaire.

-------
                                     VI-17
     Refinery 266 began operation before  1970.   It  expanded  to  its  1978 capac-
ity, 5,600  barrels  per day, during  1974.   Refinery 266 manufactured  military
jet fuel, fuel oils, and a small quantity of leaded  motor gasoline.1  Principal
competition was  from two pipeline  terminals,  each located  about  fifty  miles
away.

     The area around Refinery 266  was  well populated and industrialized.   It
appeared that all of the plant's output was delivered  within  a radius of twenty
or thirty miles.   The refinery  appeared  to have a significant transportation
cost advantage over  other refineries,  perhaps  twenty  cents per barrel  of pro-
duct.  This would have been true regardless of  the  level of  federal protection
against imports.  So the  revised guideline  cost  was  not enough  to cause this
refinery to cease operation.

          C.3.h  In  summary,  the impact of  revised guidelines  on  topping  re-
fineries would have depended strongly on the future level of  federal subsidies
for small refiners.   The  subsidy level  in  1978 for firms processing less than
ten thousand barrels per day was about 95 cents  per  barrel crude oil processed.
If the  subsidy  had   continued  at even a  fraction (one-third?) of  this level,
revised guideline costs probably would  not have caused any refineries  to shut
down.

     If, however, the small refiner  subsidy was eliminated,  it  was  anticipated
that the following  topping  refineries might  choose to  shut  down  rather than
incur revised Option 2 PSES  costs.  (They would  not  have   been  affected  by
Level 1, Level 2, or Option 1  revised guideline  costs.)

             Refinery
               Code               	Capacity	     Located Near
                                 (thousand barrels per day)
               193                           3.2                Houston
               195                           1.                  San  Antonio
               231                          10.2                Salt Lake  City
                          Total             14.2
     1  Ibid.

-------
                                     VI-18
          C.3.1  The asphalt  refiner,  Code  52, was located at the east  end of
the panhandle of Florida.   It faced revised guideline costs  (direct,  Level 2)
of six cents per barrel crude oil processed.

     Refinery 52 began  operation before  1970  and increased its capacity  from
3,000 barrels per day  in 1970 to  5,000 barrels  per day  by  1974 and  to 9,000
barrels per day  by  1979.   Almost  half  of  1976  product  outturn was  asphalt.
Some military  jet   fuel was  also  manufactured,  but  no  gasoline.   Imported
Venezuelan crude oil accounted for all raw material requirements.

     Because Refiner 52  was located on  the  Gulf of Mexico,  it  faced  competi-
tion from all other Gulf Coast asphalt manufacturers.  And  when  U.S.  refiners'
crude oil acquisition  costs  were allowed  to  equalize  with offshore  refiners'
costs, this plant would  again face  competition from Caribbean refiners, as it
did before the OPEC price increase  of  late  1973.  However,  it was  important to
point out that finished  asphalt  was much more  expensive  to ship and  to  store
than asphaltic crude  oil.   So relatively short distances  created  significant
transportation/storage cost advantage  in the  asphalt manufacturing  industry.

     It seemed highly  unlikely that Refiner  52  would have been unwilling to
incur revised guideline costs.  The  costs  were moderate,  the  refinery appeared
to be well located,  and it  had sufficient confidence to triple its capacity over
the last eight years.
D.   Summary of Economic Impacts of Revised Guidelines on Existing Plants

     D.I  The analysis indicated that no petroleum refineries were likely to be
shut down  under the Level  I/Option  1  guidelines.   It also  identified  three
small petroleum  refiners  that,  in  the  absence  of  a  small  refiner  subsidy,
might have  elected  to  shut  down rather  than to  incur  revised Option  2  PSES
costs.  However,  if  a  small refiner  subsidy  was continued  they would  have
probably incurred the costs and continued operations.

-------
                                     VI-19
     These refineries accounted for one-thousandth, i.e., 0.1 percent, of total
industry capacity.  Industry output  would not have been affected  if  they shut
down.

     D.2  Employment  Effects.  Under  Level  I/Option  1  there  would  have  been
no employment  effects because  no  petroleum refineries  were likely to  shut
down.  It  was estimated that  100 to  150 persons were  employed in  the  three
small refineries  that may  have  shut  down  under the  Option  2  guidelines.

     New jobs  would  be created by  revised  guidelines in  existing refineries.
The new effluent  treatment  facilities  would  need to  be  operated, maintained,
and supervised.  It appeared that  about 50 to 850 jobs would have been created.1
A net increase of  50  (Level I/Option 1) to  725 (Level  2/Option  2,  net of three
shut down refineries) was expected.

     D.3  Community  Effects.   The  three  refineries  that may  have  shut  down
were all  small employers located  in  or  near metropolitan  areas.   Hence,  no
community impacts were expected if the plants did shut down.

     D.4  Balance  of  Trade  Effects.   No  balance of  trade effects of  revised
guidelines were expected.
E.   Impacts on New Plants

     With no tariff protection compliance costs for new sources (NSPS and PSNS)
would have to be absorbed by new sources.  However, the magnitude of compliance
costs would have  negligible impact on  the economic viability of  new  plants.
     1  Chapter  V,  Section D.

-------
                                  Chapter VII
                          LIMITATIONS OF THE ANALYSIS

     There are  two principal  limitations to  the  analysis presented  in this
report, the  cost  data, and  the necessity of  assuming future  federal govern-
ment policy for protecting domestic refineries.

     The estimated  costs  of conforming  refineries  to revised  guidelines were
based on a  survey that was  conducted  in 1976.  Twenty-one  refineries did not
respond to the  survey,  and  several refineries might  have  altered their actual
or planned effluent treatment  and flow since  then,  as well as  their  size and
configuration.

     Estimated costs for  conforming  directly-discharging  refineries to revised
BAT guidelines, and indirectly-discharging refineries to  Option 2 pretreatment
guidelines, were based  on a  flow model.   The flow model  was derived by statis-
tical analysis of a nonhomogeneous universe:   two different types of refineries
were subjected  to  a single  analysis:   those  that  complied with  existing BPT
regulations and those  that  did  not.   Moreover,  the resulting model  stated
that the following  important refining processes  discharge  no effluent  water at
all:  catalytic reforming, alkylation,  delayed coking, fluid coking, and hydro-
desulfurization.  Finally,  it   was  assumed  by  Effluent  Guidelines  Division
that land costs were negligible for  all refineries.   This  probably is not the
case.

     If costs to  conform  were  increased  by  twenty  percent, the number  of re-
fineries with compliance  costs  greater than  4.1  cents per barrel crude oil
processed (Exhibit VI.1) would  have increased from 22 to 40.  And the number of
(non-asphalt) refineries with compliance costs greater than process unit values
(Exhibit VI.2) would have increased from five to  eight.  Two of the added three
refineries  had already  been  analyzed in  detail  because  compliance costs and
process unit  values  were equal.   The  third -  Refiner  130 -  was quite  well
located and appeared to enjoy  a significant  transportation  advantage  relative
to its competition.

-------
                                     VI1-2
     At the time this study was made, it  was not possible to foresee the dramatic
changes that eventually took  place  in the world and the  U.S.  petroleum market
places.  Large price increases  significantly  reduced consumption.   In January
1981, all U.S.  petroleum  price controls were removed, small refiner subsidies
were rescinded and the  U.S. industry was given essentially no tariff protection.
U.S refining utilization  decreased  from  89.4  percent  of  capacity in  1977  to
below 70 percent in 1981.  Currently  (July 1982), the utilization rates is about
71 percent.  More than fifty U.S. refineries have discontinued  operations since
decontrol.  Except for modifications in refineries to change output  states and
to enhance their capabilities to process low valued crude oils, little new pro-
cess capability is under construction.

     If the economic impact analysis were redone in the context  of the current
economic environment,  some  changes  would be  noted.   But  the  impacts  on the
existing industry  would  be small.  Except  as  noted above, there  currently is
essentially no construction of  new  refining facilities.   Consequently, BAT and
PSES compliance  costs  would  have   to  be  absorbed  by  existing  refineries.

     These costs  were  generally small  compared  to the  capital  values  of most
existing plants.  (The methodology and results  of the capital values for exist-
ing refineries that were computed in this  study are still valid.  At that time,
crude distillation capacity was assigned little capital  value.   But most refin-
ing downstream processing capability was quite valuable.)  This  study determined
that only  three  U.S.  plants  might  experience  compliance costs  that  exceeded
residual capital  values  and  thus might discontinue  operations.  All  of these
were simple refineries not equipped with much downstream processing capability.
Of the fifty or  so U.S.  plants that have shutdown  since  decontrol,  by far the
largest number  are plants of  this  type.   It  is quite  likely that  the three
plants identified  as  candidates for  closure as a  result of PSES  rules, have
already discontinued operations for economic reasons other than PSES compliance
costs.

-------
                                   Appendix A
             PETROLEUM REFINING PROCESSES AND THE REFINING INDUSTRY

A.   Types of Refineries

     Crude oils, the primary raw material used in refining, are liquid mixtures
of many hydrocarbon-containing chemical  compounds.   Crude oils differ from one
another in the  relative  concentrations  of the various compounds.  The physical
characteristics of a given  crude  oil can range from an almost colorless liquid
similar to  gasoline to  a dark  viscous material  Which must  be heated to  be
pumped.  Crude  oils also  contain varying  concentrations of  nonhydrocarbons,
including compounds  of  sulfur,  nitrogen, oxygen and  heavy metals.   These com-
pounds create problems in the refining  process  and with product contamination.
Sulfur is of principal concern because sulfur compounds can cause severe corro-
sion to  refinery  equipment and   can be  a  major  source  of  air  pollution.

     The purpose of an oil refinery is to process crude oil into various refined
fractions and blend  those  components into the desired  finished products.   Al-
though a typical oil refinery is technically complex, the manufacturing process
is conceptually  simple.   A refinery   consists  of  a number of  modules or units
integrated into a processing sequence.  Each unit contains equipment to perform
a refining or  petrochemical operation on  crude oil, or  on a  fraction  of the
crude, or on a similar  substance derived from natural gas.   These  operations
include:  separation by fractionation; conversion by chemical reaction, often in
the presence of a catalyst, to  higher  valued products;  product  treating;  and
auxiliary support facilities for such purposes as utility generation, pollution
control, and storage.   The actual processing configuration will  depend  on the
characteristics of the  crude oil  processed  and on  the desired  final  product
mix.  Exhibits A.I through A.4 show  flow charts and product  yields  of increas-
ingly complex refinery  configurations processing  a  typical  light,  low  sulfur
crude.

     The configurations are chosen to show that gasoline yield can be increased
from zero  to  at  least   seventy   percent  of  crude  oil  processed.   Process

-------
              tii  in
              ISs

                             A-2
                                                                CM
                                      CM
                          S

                          2*3
                          «»t
      UJ O
      D. ^
      Q. U.
J3
•i-l
.C
      51
r-i 1 1
1
CD.IUIZO— zo o_>uizo— zo
tu
z
4
>-
U
O
o
Ul
Z
c!
10
o
» '




t



^
« ^
Z 13
15
z o

Z _)
k



6
in
<
U
>•

i
0 _|
OC O
'u
_)
in
o
t




Ul
1 i
i/t
i^f
K

                                                                         (0
                                                                         O
                                                                         00
                                                                         3

                                                                        •o
                                                                         u
                                                                        T3
                                                                         U
                                                                         C

-------
5o2
rf»- fe
O 2 UJ
                  A-3
ON  CM
trv

CM
o
oo


5 -if- o
» 3~ J










^_
o:
UJ
£6
V








8
o
t

B_JuiZO — Z O
i
UJ
Z
g
I
U
z
D
ffi

k




i
^* c/i W'
§§J2
j UJ g
1
4
LU
a: uj
o
^? — »
^ la
< ^2
^^^ 1
iJ s -^
•H QtO
• H X ^
a oS
S 2
< CO
O (jj
5 o
cc
$ a
o
— ' tn
ll «₯
"• 5










I








UJ


2
a
h-
o
o
UI

i
4_^
j
S
O







k 4

1

u
O
z
o
z
UJ
GASOLIK
^
V)
5
i



z
UJ
o
g
c
z







g|I = jW gj = — UJ
x ^> 5 2 5 cu.wp —


t

ffl_IUJZO-ZO
k 1

1

/)
•*
1 **
u
;i
< 0
4f ^J
U tt


tr
ONUV3M
[N39OUOA
I *"
















_tt_°
<








Z
0.
<
z





VJ
t-
§
_!
> ^

















j
5
0
>
UJ
Z
k






















*
§o
V)

^< K
k















1— 1
*~
«H^
lk^
00
CO
*
^J
.^
3
•o
ni
QJ
•a
^
u
c
»— 1

*
^^ f™
5

-------
                                    A-4
oo2
              t-i
                          CM
       CO
                                                   m
                                                   CM
                                                                           01
                                                                                              O)
                                                                                              co
                                                                                              (0
                                                                                              00
                                                                                             TJ
                                                                                              0)
                                                                                             •O
                                                                                              3
                                                                                             •—I
                                                                                              U
                                                                                              C

-------
 §fc =
                              A-5
                00
      o  o
                           «M
                           r*»
                                                              •Jc
                                                              •ft
                                                                          en
                           I/)
     i
      era:
    a:
    UJ
    LUO


    7 UJ
    cn 5-
    or o
    UJ
    > a
>r4
J=
 X
    o

    21
w  cc £
    o o

    o
§




1
J*
Tl
t-i
i<
o:
j^








in
D
D
3 «/)
= S
ft
a
_i
4
j:
D
a
Z

ffl-IUI
OLINE .
IH OCTANE)
55
1
5
c
a
j .
CMUS
PROCESSING
•\




uJ
z
u
o
GASOLINE (LOW





|
V
1
Z
k






«/•
C











I
f
o-
(



1
o
I
Ul
z
li
o
10
o
1 1




z
Ul
HYOROC






Z
1 1








.
N-
i
4
h-
5

i
I
y






0
t 1








•>

t
o
J.
*l
X
< ,
!!
I







t






V)
c



t
1 —
1
i
j
:
t_
•^^•^H
UHdVN
Ul
O
o
uJ
C
a










"




6
in
 OU
ffl-JUlZO-







4
\s





0
in
<
Ul
Z Ul
3 j in
5 U
-I »
u


Ul
in
Ul
5
•Zl





UM OCTANE
0
Ul
2
Z
d
Js
4

t.
f
<
H
«
(.

I
1.
>
2
c



>
i




_J
O
in
O
Z
O



: z
•'§
K
4 i
O
t/1
4
O
Z
0
,5
nusia
t



k





o
o
5











5l§5
ft «J »
1





Ul
I
u
o
I
_j
Ul
Z
in in
O 15



i
<
4

1 §5
Sft
>a
!
1
I
J










X
< 6
""1 <
1 ^
1 |
i
E

i





                                                                          ff

                                                                          u
                                                                          IS
                                                                          -I U
                                                                                   QJ
                                                                                   W
                                                                                 W)
                                                                                 c-u
                                                                                 01 3
                                                                                 Ur-l
                                                                                  -X

-------
                                      A-6
units are successively added  to  the simplest  possible  "topping"  configuration
(Exhibit A.I) as follows:

     o  Exhibit  A. 2  (hydroskimming  configuration):   Catalytic  reforming  is
        added to upgrade  naphtha from military  jet fuel  and/or  petrochemical
        feedstock to gasoline.
     o  Exhibit  A.3 (fuels  configuration):    Catalytic  cracking  is  added  to
        convert about one-half  of the  Exhibit A.2  residual  fuel oil  outturn
        to gasoline.  A further  fraction  of  residual fuel oil is  converted  in
        catalytic cracking to  olefins  (propylene and  butylenes).  These  com-
        pounds are  reacted (alkylated)  with  isobutane  (partly  derived  from
        refinery processing and  partly purchased from the  natural  gas process-
        ing industry) to make additional gasoline.
     o  Exhibit A.4  (high  conversion  configuration):  More catalytic cracking
        and alkylation are added.  This  increment  converts about  half  of  dis-
        tillate fuel oil to gasoline.   Also,  coking  is  added to convert remain-
        ing residual fuel  oil  to  coke and (mostly) catalytic cracking  feedstock.
        And catalytic, reforming is expanded to accommodate naphtha from coking.
        This configuration represents  a  practical  maximum of gasoline  manu-
        facture.  Additional  increments are  feasible,  but uneconomic except  in
        unusual cases.

     In addition to  configuration,  oil  refineries  can be  categorized  by size,
product mix and type of feedstock which can  be processed  (high or  low sulfur).
Exhibit A.5 shows the distribution of  U.S. refineries by size  and configuration
as of January  1,  1982.   Refineries  with capacity over  120,000 barrels per day
account for nearly  60 percent  of total U.S.   refinery  capacity.   However,  only
44 plants (16  percent)  of the total 273  plants  are in this   size group.   The
large number of  small refineries is  comprised of  two  groups:  those located
near isolated  producing  areas  or  small  markets  far  from alternate  product
sources; and those  which  have been built  in  recent years in response to the
government's small  refinery  subsidy programs  and  still  continue to  operate.
During 1981  roughly 50  refineries,  mainly  small  inefficient plants,  discon-
tinued operations.

-------
                                       A-7

                                   Exhibit A.5

     U.S. REFINERY CRUDE DISTILLATION CAPACITY AND OPERATIONAL ABILITY MATRIX
                       (number of plants  in each category and
                     their combined crude distillation capacity)
CRUDE DISTILLATION
CAPACITY
(barrels per
stream day)
SIZE 1
(0 - 20,000)
SIZE 2
(20,0001 -
50,000)
SIZE 3
(50,001 -
120,000)
SIZE 4
(120,001 -
250,000)
SIZE 5
(250,001+)
TOTALS
OPERATIONAL ABILITY*
A
Topping
I/
63 plants
(599,830)
V - 44%
H - 59%
T - 3%
23 plants
(692,485)
V - 50%
H - 271
T - 4%
1 plant
(80,000)
V - 67.
H - 2*
T - 0.41


85 PLANTS
(1,372,315)
V - 100Z
H - 7%
T - 7%
B
Hydro-
Skimming
21
26 plants
(255,051)
V - 32%
H - 25%
T - 1Z
11 plants
(369,205)
V - 46*
H - 14Z
T - 2%
3 plants
(183,526)
V - 232
H - 4%
T - 1Z


40 PLANTS
(807,782)
V - 100%
H - 4Z
T - 4Z
C
Medium
Conversion
3/
11 plants
(124,760)
V - 1%
H - 12Z
T - 0.7Z
32 plants
(1,177,342)
V - 13Z
H - 46Z
T - 6%
32 plants
(2,419,693)
V - 27Z
H - 57%
T - 13Z
12 plants
(1,971,142)
V - 22%
H - 44%
T - 11%
9 plants
(3,219,948)
V - 36%
H - 51%
T - 17%
96 PLANTS
(8,912,885)
V - 100%
H - 48%
T - 48%
D
High
Conversion
4/
2 plants
(37,814)
V - 1Z
H - 4%
T - 0.2%
9 plants
(317,447)
V - 4%
H - 12Z
T - 2Z
18 plants
(1,572,323)
V - 21%
H - 37%
T - 8%
15 plants
(2,510,537)
V - 33%
H - 56%
T - 13%
8 plants
(3,074.684)
V - 41%
H - 49%
T - 17%
52 PLANTS
(7,512,805)
V - 100%
H - 40%
T - 40%
TOTALS
102 PLANTS
(1,017,455)
V - 5%
H - 100%
T - 5%
73 PLANTS
(2,556,479)
V - 14Z
H - 100%
T - 14%
54 PLANTS
(4,255,542)
V » 23%
H - 100%
T - 23%
27 PLANTS
(4,481,679)
V - 24%
H - 100%
T - 24%
17 PLANTS
(6,294.632)
V - 34%
H - 100%
T - 34%
273 PLANTS
(18.605,787)
V - 100%
H - 100%
T - 100%
II  Topping (no further processing)
21  Hydroskimming (Category 1 plus reforming but no conversion)
2/  Medium conversion (Category 2 plus cracking or coking)
kj  High conversion (Category 2 plus cracking and coking)

Within each category, three capacity percentages are given:
V  »  capacity as percent of total vertical column (operation category)
H  «  capacity as percent of total horizontal column (size category)
T  »  capacity as percent of total U.S. refinery crude distillation capacity

SOURCE:  Oil and Gas Journal,  March 22, 1982

-------
                                      A-8
     The total sulfur  content  and  hydrogen sulfide contained in the  crude  oil
are important determinants  of  the  configuration of  a refinery, the  equipment
metallurgy and the size of the pollution control units needed to control sulfur
emissions.  In comparing high and low sulfur refineries, the major difference is
that the distillate fractions of the  high sulfur refineries must be  desulfurized
prior to blending or  further processing.   For plants  of  equal  total  crude pro-
cessing capacity, high sulfur refineries  will require  more capacity  in such
units as hydrotreating, sour water strippers, acid gas treating plants, sulfur
recovery plants and tail gas treating units.

     The categorization of  U.S.  plants in Exhibit A.5  does not reflect  dif-
ferences in sulfur content of crude oils processed.  Within most of  the size and
operational-ability categories  distinguished in the exhibit, there are  refine-
ries that  process  exclusively low-sulfur  crudes  and  refineries that  process
essentially all high-sulfur  crudes.    But  most  U.S.   refineries process  a  mix
of both low-sulfur and high-sulfur crude  oils,  so it  is  difficult to quantify
feedstock differences as a useful  parameter for  categorization.
B.   Location of Refineries

     As of  January 1,  1982,  there were  273  refineries in  the United  States
located in 41 states.  A large number, however,  are concentrated in a few major
refining centers located along  the California Coast, the Gulf  Coast,  the East
Coast, the Washington Coast and the Chicago area.

     Exhibit A.6 provides a summary of  the geographic distribution of domestic
refineries.  Approximately  37  percent  of  all  refineries  are  located in  six
major refining  centers.   Refineries in these areas  tend  to be large complex
facilities with a  full  complement of downstream processing  facilities.   These
six refining areas provide approximately 64 percent of total crude distillation
capacity and 67 percent of cracking capacity.

-------
Location
Chicago Area




Washingto




All Other






TOTAL
A-9
Exhibit A. 6
GEOGRAPHIC DISTRIBUTION OF REFINERIES AND
as of January 1, 1982
Number of
Refineries

Coast 34
lulf Coast 21
Coast 27
, Philadelphia, Delaware 8
ea 5
Coast 7
171


REFINING CAPACITY

Distillation
Capacity
(thousand barrels
4,457
2,679
2,327
1,194
842
412
6,690




Cracking
Capacity*
per day)
1,501
968
877
465
348
141
2,122
273
1J8,601
6,422
* Includes catalytic cracking, hydroeraeking and coking.
SOURCE:  Oil and Gas Journal,  March 22, 1982.

-------
                                      A-10
     For the most part, the major refinery centers are located in highly indus-
trialized areas with numerous air emission sources.  Many of  the large  refine-
ries, particularly those along the Gulf Coast, are integrated  with  or adjacent
to petrochemical and chemical  plants  which rely on the refineries  for feedstock.
Some major utilities are located near  refineries;  fuel and utilities  are  ex-
changed between nearby  plants.
C.   Financial Structure of the Industry

     It is difficult to  analyze the financial  structure  of the petroleum  re-
fining industry using  published  data.   Most major  refining  firms  are part  of
larger enterprises  which  are not  exclusively,  or  even primarily,  in the  re-
fining business.  Many of  the  smaller  firms  are  privately  held.   Those  for
which published refining  profitability  data are  available  are not typical  of
the industry.

     While profitability  of  the business as a  whole  has  been subject to  some
variability, industry earnings have been adequate to attract  capital  to finance
growth and replacement.   In  recent years about 80  percent of  capital  require-
ments of the  industries  have been met  from internal sources.  Record profits
resulting from  rising  oil  and  gas prices  have  greatly increased  resources
available to  the  industry.   But  U.S.  refineries  were  operating  at  about  65
percent of  capacity in  early  1982,  a  lower  capacity  utilization level  than
ever before.   At  these  operating  levels,  refineries  by themselves  are  not
profitable.  Several large  and  small plants have  closed  recently or  have  an-
nounced plans to do so.

     Uncertainties about  future  product  demand make  it impractical  to provide
a detailed estimate of the refining industry's  capital  requirements  for expan-
sion and  modernization for  the years  to  come.   A  review  of spending  plans
for 1982 however, provides  some insight into  the industry's  capital  require-
ments.  In 1982 the U.S.  petroleum industry  plans  to spend a record 95.3 billion
dollars in domestic activities,  and 32 of these  U.S. firms  plan to spend another

-------
                                      A-ll

16 billion dollars outside the  U.S.*   About  10 percent  of the domestic capital
expenditures, roughly 9 to 10 billion dollars, represent planned investments in
refineries and chemical  plants.   A large portion of these  expenditures  are to
maintain the productive  capacity of  existing  plants as they age, and much of
the rest  will  be used  to change the mix of  products made  or to adjust  the
industry's capacity to  produce  a mix of feedstocks that  is  gradually becoming
more difficult to process.   Essentially no capital is  being  spent  to increase
the industry's total  capacity to  process  raw materials.   By far the  largest
portion of  the industry's total capital  expenditures,  about  70 percent,  is
budgeted for exploration and production.

     Refinery employment as a whole has been fairly stable.   In 1980 there were
approximately 154,000 employees;  in  1975,  about 153,000;  and in 1970, 154,000.
About one-third of  the people  in the industry are  skilled workers  whose  job
opportunities at a  comparable skill  level are dependent  on  employment  in  the
"process" industries.  The other  two-thirds are employable  in other industries
at their present skill levels if job opportunities exist for them.
D.   Refining Industry Growth

     There are a number  of  factors which will have  significant  impacts  on the
future of the domestic refining industry.  The dramatic rise in crude oil  prices
following the political disruptions in  Iran  has  reduced  the level  of petroleum
demand worldwide from 1977  to 1982.   Decontrol  of U.S.  crude and  petroleum
products in  early  1981 has  increased  the prices of oil products  in the  U.S.
and opened the domestic market to competition from foreign refineries.  Finally,
the average  world supply of  crude oil  will  become  heavier and higher in  sulfur
content.
     1 Oil and Gas Journal, Feb. 15, 1982, p.  59.

-------
                                      A-12
     These changes  will  tend  to   reshape  the  refining  industry.   Refinery
crude oil  runs  will be  lower than previously  projected because of  declining
demand.  At the  same time, downstream  processing will  increase  to keep  pace
with changing demand patterns:   total  gasoline demand will decline but  demand
for unleaded  gasoline   will  increase;  high quality  middle  distillate  demand
(jet and diesel fuel) and certain petrochemical demands will  increase;  residual
fuel demand will decline  at  a greater rate than other  products.  While trying
to adapt  to these  changes,  refiners  will  be  faced  with heavier  and  higher
sulfur crudes.

     As a  result  of these changes  refiners  will be forced to shut down crude
distillation facilities.  The refining industry  will  not require  the  construc-
tion of additional  new  grassroots  plants over  the  next  decade but  will  still
require downstream  process expansion.   U.S. refinery  crude  oil  runs  are  pro-
jected to  increase from  current depressed  levels  (less  than twelve  million
barrels per day) to the intake  levels which prevailed  in the  late 1970s (about
fourteen million  barrels  per day)  over the  next  decade.  At  the  same  time,
downstream processing will increase to keep pace  with changing demand patterns
which result  in  the output of  larger  percentage yields of light products and
the need to process higher sulfur crudes.  As a result, refiners will  invest in
additional facilities  for heavy  oil  conversion,  desulfurization  and  sulfur
recovery.

     Future processing requirements  will be satisfied through modification of
existing plants.   No  new refineries are now being  built in the  U.S.,  nor are
any likely to be built over the next decade.  Very few new refineries  have been
built in  the  last  decade  (except  for  "entitlement" refineries).  This  trend
should continue due to  industry economic considerations and  general  community
resistance toward new refining centers.

     Refinery expansions  will involve revamping existing equipment,  replacing
old units  with larger more  efficient ones, and adding new facilities  into the
existing flow  scheme.   Expansions   will  tend  to be  concentrated  in the larger
more efficient  refineries,  particularly  those  in  major   refining   centers.

-------
                                      A-13
E.   Types of Refining Processes

     In refining, crude oil is first separated  by  molecular size into fractions,
each of which can be blended directly into  final petroleum products or processed
further.  In the  downstream processing operations, the molecular size and struc-
ture of petroleum fractions  are altered to  conform to desired characteristics
of refined  products.   Exhibit  A.7  classifies  the various  refinery  processes
according to  their  principal  functions.   These  major processing  steps  are
described briefly below.

     Fluid catalytic cracking uses  high  temperature  in the  presence of  a cata-
lyst to convert  or "crack" heavier  fractions  into lighter  products,  primarily
gasoline and distillates.  Feed is  brought to  process  conditions (1000°F and 20
pounds per square  inch  pressure)  and then mixed  with  a powdered  catalyst  in a
reaction vessel.   In  the  reactor,  the  cracking  process is completed  and  the
hydrocarbon products pass  to  a fractionating  section  for separation.   Coke is
formed on the catalyst as a by-product of the cracking  reaction.  Coked catalyst
is transferred from the  reactor to a regenerator  vessel where air is  injected
to burn the coke  to CO and CC^.  The regenerator  flue  gases are passed through
cyclones and,  sometimes,  electrostatic precipitators,  to  remove  entrained
catalyst.   They are then vented to  the atmosphere  or  sent to a CO boiler where
carbon monoxide is  burned  to  C02-   The regenerated catalyst is returned to the
reactor.

     Hydrotreating  (also known  as  hydrodesulfurization) is  a catalytic process
designed to remove  sulfur,  nitrogen and  heavy metals  from petroleum fractions.
Feed is heated to process  temperature (650° to  750°F), mixed with hydrogen and
fed to a  reactor containing  a fixed  bed  of  catalyst.  The primary  reactions
convert sulfur compounds in the feed  to  hydrogen sulfide (I^S) and the nitrogen
compounds  to ammonia.  The I^S  and  ammonia are separated from the desulfurized
product;  the H2S is sent to sulfur recovery facilities.

     Catalytic reforming is  used  to  upgrade  low-octane  naphtha  to  produce
high-octane gasoline blending  stocks.  The flow pattern is  similar to  that of

-------
                                         A-14

                                    Exhibit A.7

             FUNCTIONAL CHARACTERIZATION OF PETROLEUM REFINERY PROCESSES
              SEPARATION
A. Separation on the Basis of Molecular
     Weight

   Distillation (atmospheric and
     vacuum fractlonatlon of crude
     oil, naphtha splitting,
     depropanizing,  stabilization)

   Absorption (recovery of olefins
     from catalytic  cracked gas,
     recovery of propane from natural
     gas or hydrocracked gas)

   Extraction (deasphalting of feed-
     stock for lubricating oil manu-
     facture or for  catalytic
     cracking)

B. Separation on Basis of Molecular
     Structure

   Extraction (recovery of benzene,
     toluene and xylenes from catalytic
     refornate, removal of aromatics
     from lubricating oil feedstock)

   Crystallization (dewaxing of lubri-
     cating oils, recovery of para-
     xylene from mixed xylenes)
          ALTERATION (CONVERSION)
A.  Conversion on the basis of Molecular
       Weight

    Thermal cracking
      (visbreaklng, coking)

    Catalytic cracking

    Hydrocracking

    Alkylation

    Polymerization
B.  Conversion on Basis of Molecular
      Structure

    Catalytic reforming (benzene, tol-
      uene, and xylene manufacture;  and
      octane improvement)
    Isomerization (normal butane to iso
      for alkylation, normal pentane
      and hexane to iso for octane
      improvement)
                            TREATMENT TO REMOVE IMPURITIES

                         Hydrogen treatment (hydrotreating)

                         Caustic treatment (Herox, Bender)

                         Clay treatment (of lubricating oils)

                         Acid treatment

-------
                                      A-15
hydrotreating except  that  several  reactor  vessels  are  used.  The  required
temperature is  about  1000°F and  pressure about 200 psi.   Reforming catalysts
are readily  poisoned  by  sulfur,  nitrogen  or heavy  metals and  therefore the
feed is  normally  hydrotreated  before  being  charged  to  the  reforming  unit.

     In hydrocracking  the  cracking  reaction  takes  place  in the  presence  of
hydrogen.  The  process  produces  high  quality desulfurized  gasolines  and dis-
tillates from a  wide  variety of  feedstocks.   The process employs  one  or more
fixed bed  reactors  and  is similar in flow  to the hydrotreating process.  Pro-
cess conditions  are 800°F  and  2000 psi.   Like  hydrotreating,  hydrocracking
produces by-product l^S which is diverted to sulfur recovery.
     Coking is  another  type of  cracking  which does  not  employ a  catalyst or
hydrogen.  The  process  is  utilized  to convert heavy  fuel  oils into light pro-
ducts and a solid residue (coke).  Feed is brought to process conditions (900°F
and 50 psi)  and fed to  the coking  vessel.   Cracked  products are  routed  to a
fractionation section.   Coke accumulates  in  the vessel  and  is  drilled  out
about once every day.   In  one version  of  the coking process,  fluid  coking, a
portion of the  coke is  used for process  fuel and the  balance is removed as
small particles.

     Acid gas treating and  sulfur recovery units  are used  to  recover hydro-
gen sulfide (H2&) from refinery gas  streams and convert it to elemental sulfur.
Sour gas containing H2S is produced  in a number of refinery units,  particularly
cracking and hydrotreating.   In the  acid  gas treating  units, H2S is  removed
from the fuel gas  by absorbing  it in an alkaline solution.   This  solution, in
turn, is heated and  steam-stripped  to remove the I^S  which  is  sent  to  the
sulfur recovery unit.   In  the process,  a portion of  the H2S  is  burned  to  form
S02»  This reacts  with  the  remaining I^S  to  form sulfur and  water.   Sulfur
recovery is high but never  100  percent.   The remaining sulfur  is  incinerated
and discharged  to  the  atmosphere  or removed by a  tail  gas treating  unit.

     The purpose of the  tail gas treating unit   is  to  convert  any  remaining
sulfur compounds from the sulfur recovery  unit to elemental  sulfur.  There are

-------
                                      A-16
several processes available, the most  common of which are the Beavon  and  SCOT
processes.  In both  processes, sulfur  compounds  in the  sulfur  unit  tail  gas
are converted to  H2S.  The  Beavon process  converts  l^S to  sulfur through  a
series of absorption  and oxidation steps.   The SCOT process  concentrates  the
H2S and  returns  it  to  the  sulfur recovery facilities.   In both  processes,
the treated tail  gas  is virtually  free of  sulfur  compounds when  released to
the atmosphere.

-------
                                 Appendix B

                    Cost  per pound of pollutant removed

     The exhibit below presents a summary of the cost per  pound of pollutant
removed for each of the  options considered.  Note that the incremental
costs and loadings  for existing dischargers are based on  industry-wide
data, while the new source  data is reported on a per plant basis.   The
values are in dollars per pound of pollutant removed.
                           Cost  per pound of pollutant

                                PETROLEUM REFINING
Control
Option
Proposed BAT1
Proposed BAT2
Revised BAT1 (BATS)
Revised BAT2 (BAT7)
PSES1A
PSES1B
PSNS
NSPS1
NSPS2
NSPS3
NSPS4
Annual
Cost
(000)
$ 7,730
48,703
25,000
37,000
5,180
32,300
195
284
284
3,875
3,875
Pounds
Removed
(per year)
73,000
114,000
75,000
112,000
90,000
333,000
90,000
807.5
807.5
1,552.9
1,146.5
($/pound removed)
$ 105.10
427.22
333.33
330.35
57.55
97.00
2.16
351.70
351.70
2,495.33
3,379.26
                                               ftU.S. GOVERNMENT PRINTING OFFICE: 1982 381-082/331  1-3

-------
U.r-        '• '  ••' " :;  ,-,""."  •..:' '  •" "'ncy
F:;,,     -   :'
230  .  ,j:J, Dv .;;,,,;;  Cti;:,.t
Chicago, Illinois  60604

-------