EPA-600/2-76-16b
June 1976
Environmental Protection Technology Series
;
RESIDUUM AND RESIDUAL FUEL OIL SUPPLY AND
DEMAND IN THE UNITED STATES • 1973-1985
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangie Park, North Carolina 27711
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
E PA RE VIE W NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service. Springfield, Virginia 22161.
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EPA-600/2-76-166
June 1976
RESIDUUM AND RESIDUAL FUEL OIL
SUPPLY AND DEMAND IN THE
UNITED STATES--1973-1985
by
James A. Monk, Jr. , Mary M. Menino, Ellen S. Quackenbush,
Nigel Godley, Linsey R. Clark, Malcom E. Cloyd,
Indrakumar L. Jashnani, and Raymond P. Stickles
Arthur D. Little, Inc.
Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-1332, Task 19
Program Element No. EHB536
EPA Task Officer: Samuel L. Rakes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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TABLE OF CONTENTS
Page
C.I INTRODUCTION 1
C.2 DATA AVAILABILITY 3
C. 2.1 INTRODUCTION 3
C.2.2 DATA AVAILABILITY FOR RESIDUUM SUPPLY 3
C.2.3 DATA AVAILABILITY FOR RESIDUAL FUEL OIL DEMAND 5
C.3 RESIDUUM AND RESIDUAL FUEL OIL SUPPLY IN THE UNITED
STATES 9
C.3.1 INTRODUCTION 9
C.3.2 DISCUSSION OF THE HISTORIC DOMESTIC RESIDUAL FUEL
OIL MARKET 9
C.3.3 DIFFERENCE BETWEEN RESIDUUM AND RESIDUAL FUEL
OIL 11
C.3.4 CRUDE OIL SUPPLY FOR U.S. REFINERS 12
C.3.4.1 Volumetric Supplies 12
C.3.4.2 Crude Oil Quality Characteristics 12
C.3.5 U.S. REFINERY PRODUCTION AND USE OF RESIDUUM 20
C.3.6 1974 SUPPLY OF RESIDUAL FUEL OIL BY PAD DISTRICT.. 30
C.3.6.1 Overview at PAD Districts 40
C.3.6.2 PAD District I - The East Coast (Figure
C. 3-4) 41
C.3.6.3 PAD District II - The Midwest (Figure
C. 3-5) 43
C.3.6.4 PAD District III - The Gulf Coast (Figure
C .3-6) 43
C.3.6.5 PAD District IV - The Rocky Mountains
(Figure C.3-7) A3
ii-i
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C.3.6.6 PAD District V - The West Coast (Figure
C.3-8) 47
C. 4 DOMESTIC DEMAND FOR RESIDUUM PRODUCTS 49
C. 4.1 INTRODUCTION 49
C.4. 2 OVERVIEW ON MARKET DEMAND 49
C.4.3 RECENT HISTORY OF NON-ENERGY DEMAND FOR RESIDUUM-
BASED PRODUCTS 52
C.4.4 DOMESTIC DEMAND FOR RESIDUAL FUEL OIL 54
C.4.4.1 On The National Level 54
C.4.4.2 Regional Demand for Residual Fuel Oil 60
C.4.4.3 State Detail on Demand for Residual Fuel
Oil by End-Use Category 66
C. 5 GOVERNMENT FACTORS 85
C.5.1 INTRODUCTION TO DISCUSSION OF FACTORS AND TRENDS 85
C.5.2 OVERVIEW ON GOVERNMENT FACTORS 85
C. 5.3 DOMESTIC REFINING 87
C.5.3.1 Introduction 87
C.5.3.2 Current and Projected Domestic Refining
Capacity 88
C.5.3.3 Caribbean Refining Capacity 91
C.5.3.4 Present Government Policies and Programs
Influencing Growth In Refining Capacity.... 93
C.5.3.5 Domestic Refining Trends 97
C.5.4 EPA AIR QUALITY REGULATIONS 98
C.5.4.1 Introduction 98
C.5.4.2 Development of Current Air Quality
Regulations 98
iv
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Page
C.5.4.3 State Regulations 100
C.5.4.4 Current Issues Surrounding Air
Pollution Control 101
C.5.4.5 Air Quality Control Trends 110
C.5.5 MANDATORY FUEL CONVERSION PROGRAM ."Ill
C.5.6 PROMOTION OF FUEL USE RESEARCH 113
C.6 FOREIGN FACTORS AFFECTING RESIDUAL FUEL SUPPLIES IN
THE U.S 117
C.6.1 INTRODUCTION 117
C.6.2 CURRENT SOURCES OF U.S. CRUDE AND FUEL OIL IMPORTS.. 119;
C.6.2.1 Crude Oil 119
C.6.2.2 Residual Fuel Oil 119
C.6.2.3 Summary of Discussion 123
C.6.3 FOREIGN CRUDE OIL AVAILABILITY 123
C.6.3.1 Recent Import Forecasts 123
C.6.3.2 World Oil Production Potential 127
C.6.3.3 Summary 133
C.6.4 FOREIGN REFINING CAPACITY 133
C.6.5 CRUDE PRICE CONSIDERATIONS 137
C.6.5.1 The Effect of Current U.S. Crude Oil
Price Legislation 137
C.6.5.2 Historic Crude Oil Prices ; .140
C.6.5.3 Possible Future Crude Oil Price Trends 144
C.7 ENERGY PRODUCTION TRENDS 147
C.7.1 INTRODUCTION 147
C.7.2 DOMESTIC CRUDE OIL PRODUCTION 147
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C.7.2.1 Recent Statistics on U.S. Oil
Production 147
C.7.2.2 Projections of Future U.S. Crude
Oil Production 150
C.7.3 FOREIGN CRUDE OIL PRODUCTION 157
C.7.3.1 Exxon Forecast (December, 1975) 157
C.7.3.2 Library of Congress Forecast
(November, 1975) 161
C.7.3.3 Dependence on Arabian Peninsula
Countries 161
C.7.4 NATURAL GAS 164.
C.7.4.1 Natural Gas Supply in the U.S 164.
C.7.4.2 Potential Demand for Natural Gas 166
C.7.4.3 Probable Demand for Natural Gas 166
C.7.4.4 Future Natural Gas Price 171
C.7.5 COAL
C.7.5.1 U.S. Historical Coal Production 172
C.7.5.2 Projected Demand for Coal 174
C.7.5.3 Projected Supply 176
C. 7.5.4 Supply/Demand Balance 180
C.8 DEMAND TRENDS FOR RESIDUAL FUEL PRODUCTS 183
C.8.1 OVERVIEW 183
C.8.2 TRENDS IN END-USE CONSUMPTION OF RESIDUAL FUEL
OIL 186
C.8.2.1 Utility Demand 187
C.8.2.2 Industrial Demand 188
C.8.3 DEMAND TRENDS FOR OTHER RESIDUUM PRODUCTS 188
vi
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Page
C.9 TECHNOLOGICAL TRENDS IN SULFUR REMOVAL PROCESSES 191
•
C.9.1 INTRODUCTION.... 191
C.9.2 POST-COMBUSTION SULFUR REMOVAL 192
C.9.2.1 Current Status of FGD Systems 192
C.9.2.2 Types of Flue Gas Desulfurization
Processes 193
C.9.2.3 Present Work in FGD Systems 197
C. 9.2.4 FGD Process Economics 197
C.9.2.5 Application of FGD Systems to Industrial
Boilers 201
C.9.3 PRE-COMBUSTION SULFUR REMOVAL 202
C.9.3.1 Catalytic Desulfurization of Residual
Fuel Oil 202
C.9.3.2 The CAFB Process 210
C.9.4 SELECTION OF THE DESULFURIZATION PROCESS 215
C.9.4.1 Selection Criteria 215
C.9.4.2 Comparison of Operating Costs of
Desulfurization Alternatives 218
C.10 RESIDUAL FUEL OIL HANDLING PROBLEMS 221
C.10.1 INTRODUCTION.< 221
C.10.2 PHYSICAL PROPERTIES 221
C.10.2.1 Viscosity 221
C.10.2.2 Pour Point 222
C.10.2.3 Specific Gravity 224
C.10.2.4 Sulfur Content 224
C. 10.2.5 Minimum Operating Temperature 224
C.10.3 TRANSPORTATION OF RESIDUAL FUEL OIL 225
vii
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C.10.3.1 Water-Borne Transport of Residual
Fuel Oil 225
C.10.3.2 Pipelines for Residual Fuel Oil 226
C.10.3.3 Other Transportation Modes 232
C.10.4 STORAGE OF RESIDUAL FUEL OIL 233
C. 11 FUTURE RESIDUAL FUEL OIL DEMAND 235
C. 11.1 INTRODUCTION 235
C.11.2 RECENT FORECASTS OF PRIMARY ENERGY BALANCES 236
C.11.3 IMPLICATIONS FOR RESIDUAL FUEL OIL DEMAND ... 238
C.12 FUTURE SUPPLY OF RESIDUUM 241
C. 12.1 INTRODUCTION 241
C. 12.2 POTENTIAL FUTURE RESIDUUM SUPPLY 241
C. 12. 3 SENSITIVITY OF RESULTS TO VARIOUS FACTORS 245
C.12.3.1 Government Product Import Controls.... 245
C.12.3.2 Crude Oil Prices. 246
C.12.3.3 Residuum Product Prices 246
C.12.3.4 Fuel Substitutability 247
C.12.3.5 Product Quality Variations 247
C.12.3.6 Technological Trends 249
C.12.4 CONCLUSIONS 251
viii
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LIST OF TABLES
Table C.3-1
Table C.3-2
Table C.3-3
Table C.3-4
Table C.3-5
Table C.3-6
Table C.3-7
Table C.3-8
Table C.3-9
Table C.3-10
Table C.3-11
Table C.3-12
Table C.3-13
Table C.3-14
Percent of U.S. Crude Oil Imports by Country
of Origin for 1973 13
Percent Domestic and Foreign Crude Run in U.S.
Refineries in 1973 ,
15
Percent Domestic Crude Oil Production by PAD
District and Key States in 1973 .... 15
Quality Characteristics and Residuum Fractions
(650° +F) of Typical Crude Oils 18
Characteristics of Crude Oil Residuums Related
to Ease of Catalytic Hydrodesulfurization......... 19
Estimated Domestic Refiners' Usage of Residuum
Hydrocarbons (650° +F) in 1973 25
Estimated Domestic Refiners' Percent Use of
Residuum Hydrocarbons (650° +F) in 1973 26
Fuels Consumed by Refineries by PAD District
1973
29
Source of Residual Fuel Oil Demand by PAD District
in 1974. 31
Distribution of Domestic Production of Residual
Fuel Oil by Sulfur Content - 1974 32
Imports of Residual Fuel Oil by Sulfur Level and
Exporting Country 1974 33
Interdistrict Movements of Residual Fuel Oil
Between PAD Districts in 1974 '34
Estimated Percent Availability of Residual Fuel
Oil by Sulfur Content 1974 35
Detailed Residual Fuel Oil Domestic Supply and
Consumption by PAD Districts - 1970-1974 *. 36.
Table C.4-1 The Importance of Residual Oil Products in Domestic
Consumption of Petroleum Products 1970-1974 50
ix
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Page
Table C.4-2 Domestic Demand for Residuum; by Product Type,
by PAD District ..... 53
Table C.4-3 Residual Fuel Oil Use In the United States:
1970-1974 56
Table C.4-4 Percentage Residual Fuel Oil Use In the United
States: 1970-1974 57
Table C.4-5 The United States Residual Fuel Oil Demand by
PAD District, 1970-1974 61
Table C.4-6 Profiles of Regional Residual Fuel Oil Demand,
by End-Use Category, 1970-1974 63
Table C.4-7 Residual Fuel Oil Demand by End-Use Category by
District, 1970 and 1974 64
Table C.4-8 Growth Profile of Regional Fuel Oil Demand by End-
Use Category, 1970-1974 65
Table C.4-9 Total Sales of Residual Type Fuel Oils in the
United States . 68
Table C.4-10 Use of Residual Type Fuel Oils in the United States
for Residential/Commercial Purposes for PAD
Districts I-V by State, 1970-1975 71-73
Table C.4-11 Use of Residual Type Fuel Oils in the United States
for Industrial Purposes, for PAD Districts I-V,
by State, 1970-1975 74-76
Table C.4-12 Sales of Residual Type Fuel Oils in the United
States for Electric Utility Company Use, in PAD
Districts I-V, by State, 1970-1975 77-78
Table C.4-13 Use of Residual Type Fuel Oils in the United States
for Transportation Purposes for PAD Districts I-V,
by State, 1970-1975 79-81
Table C.4-14 Sales of Residual Type Fuel Oils in the United
States for Unspecified Use, (including Military)
for PAD Districts I-V, by State, 1970-1975 82-84
x
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Page
Table C.5-1 Present Operable U.S. Refining Capacity By
PAD District 89
Table C.5-2 Forecast of U.S. Refining Capacity By PAD
District, 1975-1979.... 90
Table C.5-3 Caribbean Area Refinery Processing Capacities
As At 1/1/75 92
Table C.5-4 Detailed Federal, State and Local Sulfur
Regulations 102-108
Table C.6-1 Residual Fuel Oil Consumption and Imports iis
Table C.6-2 Sources of U.S. Crude Oil Imports 120
Table C.6-3 Sources of U.S. Residual Fuel Oil Imports For
Domestic Consumption 121
Table C.6-4 Exxon's Forecast of U.S. Energy Demand 124
Table C.6-5 PIRINC Forecast - Projected U.S. Oil and NGL
Supply - 1985 126
Table C.6-6 Forecast of U.S. Oil Imports By Region 128
Table C.6-7 Crude Oil Production for Major Petroleum
Exporting Countries - August 1975 129
Table C.6-8 U.S. Domestic, Canadian Maritimes and Caribbean
Exports Refining Capacity 134
Table C.6-9 Illustration of Delivered Cost of Residual Fuel
Oil (2.8% Sulfur) With and Without Entitlements
Based on Arabian Light Crude Oil Refined in the
Caribbean 139
Table C.7-1 Statistics on U.S. Domestic Crude Oil (Excluding
Prudhoe Bay in Alaska) 148
Table C.7-2 Petroleum Production From the Five Major U.S.
Producing Areas and Year of Peak Production 151
Table C.7-3 Comparison of U.S. And World Numbers of Producing
Oil Wells And Average Well Productivities 151
xi
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Page
Table C.7-4
Table C.7-5
Table C.7-6
Table C.7-7
Table C.7-8
Table C.7-9
Table C.7-10
Table C.7-11
Table C.7-12
Table C.7-13
Table C.7-14
Table C.7-15
Table C.7-16
Table C.7-17
Table C.7-18
Table C.7-19
Various Estimates of Undiscovered Re-
coverable Resources of Oil 154
Projections of U.S. Petroleum Liquids
Production 154
Non-Communist World Oil Production As
Projected by Exxon 159
Exxon's Assumed Growth Rates Non-Communist
World 159
Non-Communist World Oil Production As
Projected by Library of Congress 162
Reserves and Productive Capacities of the
Arabian Peninsula Countries 163
Future U.S. Natural Gas Year-End Proved
Reserves and Production Levels
167
Federal Power Commission Natural Gas
Curtailment Priorities 169
Prices Received by Producers for Natural
Gas Sales, 1966-1975 170
World Coal Statistics - 1973 173
1974 U.S. Demonstrated Coal Reserve Base By
Potential Mining Method 173
Projection of U.S. Bituminous Coal and Lignite
Demand 175
Actual and Projected U.S. Coal Production 177
Federal Ownership of Coal Lands and Rights... 173
U.S. Domestic Coal Mine Capacity 179
Projected Shortfalls of U.S. Coal Supply 181
Table C.9-1 U.S. Utility SO Control System Commitments.. 194
Table C.9-2
Table C. 9-3 Double Alkali FGD Systems 200
Utility SO- Control Process Economics 199
xii
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Table C.9-4
Table C.9-5
Table C.9-6
Table C.9-7
Table C.9-8
Table C.9-9
Properties of Atmospheric Residues From
Widely Available Crudes 204
Desulfurization Costs for Arabian Reduced
Crude Mixture (3.8%S) (Direct Desulfurization
to 0.3%S) :209
Desulfurization Costs for Iranian Heavy
Reduced Crude (2.5%S) (Direct Desulfuriza-
tion to 0.3%S) 211
Desulfurization Costs for Iranian Heavy
Reduced Crude (2.5%S) (Indirect Desulfuriza-
tion to 0.7%S) :212
Desulfurization Cost for CAFB (2.6%S Fuel).... :216
Comparative Desulfurization Costs 219
Table C.10-1 Capital and Operating Costs for a Hot Oil
Pipeline
230
Table C.ll-1 A Comparison of Recent Forecasts of Total U.S. .
1985 Energy Demand 237
Table C.ll-2 A Comparison of Growth Rates Assumed In Recent
Forecasts of U.S. Energy Demand 239
Table C.12-1 Future Supply and Use of Residuum in the United
States 242
xiii
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LIST OF FIGURES
Page
Figure C.3-1 Petroleum Administration For Defense
(PAD) Districts of the United States 14
Figure C.3-2 Conversion Refinery Flow Diagram -
Sweet or Sour Crude Intake 21
Figure C.3-3 Hydroskimming Refinery Flow Diagram -
Sweet Crude Intake 22
Figure C.3-4 PAD District I - 1974 Residual Fuel Oil
Product Position 42
Figure C.3-5 PAD District II - 1974 Residual Fuel Oil
Product Position 44
Figure C.3-6 PAD District III - 1974 Residual Fuel Oil
Product Position 45
Figure C.3-7 PAD District IV - 1974 Residual Fuel Oil
Product Position 46
Figure C.3-8 PAD District V - 1974 Residual Fuel Oil
Product Position 48
Figure C.6-1 World Oil Supply 132
Figure C.6-2 History of Crude Oil Prices 141
Figure C.7-1 U.S. Natural Gas Supplies, 1946-1974 165
Figure C.9-1 Simplified Illustration of Direct and Indirect
Desulfurization Units 206
xiv
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C.I INTRODUCTION
In response to Task Order Number 19 of the Environmental Protection
Agency (EPA) contract number 68-02-1332, Arthur D. Little, Inc. has
prepared this report on the Supply and Demand for Residuum in the
United States. The purpose of the report is to define the available
supply of residuum and residual fuel oil now and in 1985, to determine
the demand for residuum and residual fuel oil now and in 1985, and to
assess the factors which control and impact on the supply and demand.
Under terms of the Task Order, this report has been prepared using
literature from the public domain as the reference source. It was found
that available literature was inadequate for the level of detailed
analysis which had been originally anticipated. This problem is discussed
more fully in C.2.
The report has three main groups of chapters. Chapters C.3 and C.4 develop a
historical data base on the supply and demand for residuum and its
products. The emphasis in the report has been on residual fuel oil
rather than the other residuum products, but perspective on the total
amount of residuum has been maintained. Having developed a base of
information about the current supply and demand situation, Chapters C.5
to C.10 discuss the factors which impinge on the petroleum industry,
the world oil market, the use of residual fuel oil and its distribution
to users. Finally, C.ll and C.12 discuss the future demand for and supply
of residual fuel oil. C.12 further contains some summary conclusions
about the future supply/demand for residuum.
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C.2 DATA AVAILABILITY
C.2.1 INTRODUCTION
This report has been prepared using publicly available information.
On some specific topics no data was available and the report either
uses estimates or was reduced in scope on that particular topic. This
chapter describes the main data sources for the historical supply and
demand analyses. Other sources which were used infrequently or were
referenced only indirectly will be mentioned in the text where such
data was used.
C.2.2 DATA AVAILABILITY FOR RESIDUUM SUPPLY
The primary source of all information on the supply of residual fuel
oil in the U.S. is the Department of the Interior, Bureau of Mines (BOM)
Division and, in particular, two publications in the Mineral Industry
Surveys series:
- Crude Petroleum, Petroleum Products and Natural Gas Liquids,
released in monthly and annual summary forms and referred to
as the "Petroleum Statement."
- Availability of Heavy Fuel Oils by Sulfur Levels, released in a
monthly form which contains annual summaries in the December
issue and is referred to as the "Availability of Fuel Oils by
Sulfur Content."
While some information is available on PAD district sub-divisions (pro-
duction and stocks of fuel oil) and other on the state level (imports
and selected interdistrict product movements) complete information on
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the regional supply of residual fuel oil is available only on the PAD
district level. Also, complete information on some subjects (refinery
internal energy needs) is only included in the annual summary editions
of BOM publications. Because the 1974 annual Petroleum Statement was
not available at the time of writing this report, the year 1973 was
chosen for the discussion of the U.S. refining industry. For other
supply analyses complete information was available for 1974, and this
latter year was selected for non-refining discussions.
Sulfur content data is limited to information available at the Office of
Oil and Gas or from statistics collected by a BOM survey of individual
oil companies and shippers. The former excludes military and bonded
imports (7% of 1974 imports) and crude oil burned as fuel and exports
(both less than 1% of domestic fuel oil supply). The BOM survey covers
transfers from PAD District III only, thus omitting 5% of the 1974
interdistrict trade in residual fuel oil. The volume of fuel oil trans-
fers from PAD Districts II, IV and V is gathered by the Department of
Commerce, Corps of Engineers Division and published in the annual
Petroleum Statement, but sulfur content of these shipments is not
monitored.
Imports of residual fuel oil are reported by country of last origin
which may not be indicative of either the refinery location or the
actual crude oil source. Although almost 75% of 1974 Latin American
crude production was of Venezuelan origin, and Venezuela does have a large
residual fuel oil production capacity, not all Venezuelan crude is refined
in Venezuela, nor do all Venezuelan refineries charge solely Venezuelan
crude. Venezuelan crude, which varies in quality by field location,
is shipped throughout the Caribbean for refining, and once it enters
a foreign country it loses its Venezuelan identity. This identification
problem is compounded by Caribbean islands such as the Netherlands Antilles
which import all their crude needs, and whose product exports cannot be
associated with any specific crude without extensive analysis. Further-
more, some inter-country product shipments may take place after a product
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leaves its country of refining and before it enters the U.S.
C.2.3 DATA AVAILABILITY FOR RESIDUAL FUEL OIL DEMAND
Publicly available analyses of residual fuel oil demand usually deal
with actual sales; that is, there is no continuing effort conducted to
determine that portion of demand that is not met by marketed supplies.
Certain trade journals periodically provide some analytical information
concerning the residual fuel oil market, but the majority of information
used in this study of residual fuel oil demand was prepared and published
by the Bureau of Mines Division of the U.S. Department of the Interior.
The information is collected by the BOM by a direct mail survey technique,
covering refineries and other distributors who have annual sales of at
least 10,000 barrels of fuel oil and/or kerosene, and therefore provides
the most comprehensive demand statistics prepared on the subject. In
addition, use of the BOM demand data Insures consistency with the supply
data. The most detailed information; i.e., breakdown of U.S. residual
fuel oil sales by end-use, PAD District and States, is published for
calendar years only.
Annual detailed demand information published by the Bureau of Mines
appears in the following two publications:
• Sales of Fuel Oil and Kerosene (annual), which is part of BOM's
Mineral Industry Surveys effort. This document, also referred
to as Fuel Oil Sales (annual), is prepared by the Division of
Fuels Data and is released in September or October with data
covering the preceding calendar year; i.e., data for 1975
will not be released until Fall, 1976. Fuel Oil Sales (annual)
presents the statistical breakdown of total U.S. demand for
residual fuel oil by major end-use category (heating, electric
utilities, etc.), by PAD District and by State. In addition,
U.S. demand for each end-use category is also broken down
by PAD District and by State. There is no monthly detail.
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The only caution that must be exercised when using this
data concerns the end-use categories for heating and
industrial purposes (for both oil companies and other
industries). While industrial sales are requested
to be stated excluding residual fuel oil used for
heating, this has typically not been the case. Con-
sequently, the industrial sales category is commonly
considered to include industrial fuel oil sales for
heating. Likewise, the category presented as fuel
oil sales for heating use is perceived as being more
closely representative of fuel oil sales to the
Residential/Commercial sector only.
• Crude Petroleum, Petroleum Products, and Natural Gas
Liquids (annual), is published at least a full year after
the end of the calendar year in question: it is also called
the Petroleum Statement. It includes a table called "Supply
and Demand of All Oils in the U.S.," which presents the
monthly as well as the annual demand levels for residual
fuel oil.
Another table, entitled, "Fuels Consumed for All Purposes
at Refineries in the U.S., by States", presents annual
residual fuel oil consumption in refineries. This table
gives an indication of the portion of residual fuel oil
sales to oil companies used by refineries. There is a
companion table which details the consumption information
by refining district rather than state. These refinery
fuel consumption tables are first published in the Monthly
Petroleum Statement issued for the month of April following
the calendar year in question.
Monthly residual fuel oil data published by the Bureau of Mines appears
in the Crude Petroleum, Petroleum Products, and Natural Gas Liquids (i.e.,
the Petroleum Statement), issued for each month. There is a three or
four month time lag in its publication. That is, information covering
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December, 1975 should be put by the end of April. This document gives
total U.S. demand and supply levels for residual fuel oil.
Other sources for residual fuel oil demand data include the Federal Energy
Administration and the Oil and Gas Journal. The FEA in its Federal Energy
News issues a weekly FEA Demand Watch, which gives U.S. demand levels for
four week periods for major petroleum products, including residual fuel
oil. This information is based on weekly data from the American Petroleum
Institute. The Oil and Gas Journal usually publishes at least one article
during the last quarter of the calendar year which discusses anticipated
residual fuel oil demand for the upcoming heating season. In addition,
the magazine publishes other articles on available forecasts of petroleum
products, which often include details for residual fuel oil.
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C.3 RESIDUUM AND RESIDUAL FUEL OIL SUPPLY IN THE UNITED STATES
C.3.1 INTRODUCTION
This chapter is divided into four parts. The first presents an over-
view of domestic residual fuel oil supply, including historic factors
that led to a U.S. dependence on Caribbean fuel oil imports as well
as current legislation that encourages domestic production. The impact
of sulfur restrictions on this market is also discussed. The second
section outlines the problems faced by domestic refiners as the source
and quality of their crude oil changes. Amenability of several impor-
tant crude oils to desulfurization is discussed. The third section
discusses 1973 operations of U.S. refineries, focusing on the regional
supply of residuum. Uses for residuum that compete with residual fuel
oil production are highlighted. Finally, in the fourth section actual
1974 supply of residual fuel oil by region is outlined in detail.
Regional self-sufficiencies in supply versus reliance on imported fuel
oil are discussed. For reasons of data availability we have used 1973
for the discussion of refining but have been able to use 1974 data for
the detailed analysis of supply and demand and have used 1975 data
where available for an up-to-date assessment of the residual oil market.
C.3.2 DISCUSSION OF THE HISTORIC DOMESTIC RESIDUAL FUEL OIL MARKET
The U.S., with the exception of the East Coast, has historically relied
on low-cost domestic supplies of natural gas and coal to meet its need
for industrial and public utility energy sources. The East Coast,
being physically separated from western reserves of coal and southern
reserves of natural gas, developed a dependence on Caribbean-refined
residual fuel oil for use in public utility and industrial boilers.
-------
In the sixties and early seventies, shortages of natural gas shifted
domestic energy demand toward residual fuel oil and coal, causing more
areas in the U.S. to join the East Coast's dependence on fuel oil imports.
Over the period 1969-1972 annual domestic demand for fuel oil increased
203 MMBBLS from the 1969 demand of 722 MMBBLS to 925 MMBBLS in 1972. In
response, fuel oil imports jumped 176 MMBBLS (38%) to 637 MMBBLS, while
domestic production of fuel oil rose only 28 MMBBLS (10%) to 293 MMBBLS
per year. As a result of the U.S. government's initiation of the Old
Oil Entitlements and Oil Import Fee Program, the relative growth rates of
fuel oil imports and domestic production were reversed in 1974. Under these
programs domestic crude prices were pegged at a level well below the
world crude market price, and a fee was levied on all crude oil and
product imports. Caribbean refiners faced world prices for crude and
potentially lower U.S. market prices for residual fuel oil. Due to the
availability of low-cost domestic crude, U.S. refiners had the advantage
of a composite crude oil cost that fell below world levels and a residual
fuel oil product price that was set by relatively high-priced Caribbean
substitutes. Thus, there was an obvious economic incentive for domestic
refiners to increase their fuel oil yield. From 1972 to 1974 U.S. demand
for residual fuel oil rose 32 MMBBLS (3%) to 958 MMBBLS. In turn, domes-
tic output of fuel oil jumped 98 MMBBLS (48%) to 390 MMBBLS, while imports
actually dropped 64 MMBBLS (10%) to 574 MMBBLS per year.
Recent federal and state air quality regulations have focused attention
on the sulfur content of domestic energy sources. Standards for the
burning of residual fuel oil are most strict for new or large facilities,
for urban areas and for the East and West Coasts. Residual fuel oil
provides only a small portion of total energy needs on the Gulf Coast
and in the Midwest, and, therefore, high sulfur* residual can be burned
*Unless noted otherwise, sulfur contents in residual fuel oil will be
defined as follows:
Very Low - less than 0.5% sulfur by weight
Low - Less than 1.0% sulfur by weight
High - greater than 1.0% sulfur by weight
Very High - greater than 2.0% sulfur by weight
10
-------
in these areas without greatly altering ambient air quality. However,
on the East and West Coasts where residual fuel oil is a major energy
source a large percentage of the fuel oil burned must be low sulfur to
maintain ambient air quality. To meet this demand profile which is
heavily skewed toward low sulfur fuel oil, U.S. refineries selectively
charge low sulfur domestic, African and Indonesian crudes which
produce a naturally low sulfur product. In contrast, Caribbean refiners
rely both on selective charging of low sulfur African crudes and
on extensive residual hydrodesulfurization of the heavy, high sulfur
Venezuelan and Saudi Arabian crudes that make up the bulk of the world
crude supply. In recent years, as U.S. domestic crude production
declined, U.S. refiners have attempted to maximize imports of low sulfur
foreign crudes to avoid installing the desulfurization capacity that
would be required to handle high sulfur foreign crudes. In 1974 a
nominal 10.5 MBCD of residual fuel oil hydrodesulfurization capacity
was maintained at U.S. refineries. Importation of high sulfur Saudi
and Venezuelan crudes will undoubtedly increase in the future and
desulfurization of domestically produced residual fuel oil, either in
the refinery or at the end-user's site, will be required before the
fuel may be burned.
C.3.3 DIFFERENCE BETWEEN RESIDUUM AND RESIDUAL FUEL OIL
The term residual fuel oil has a loose application in the U.S. oil
industry, referring both to the heavy hydrocarbons that comprise a
large portion of the natural crude oil barrel and to numbers 5, 6 and
bunker "C" residual fuel oil products. When discussing refining, this
report will focus on "residuum," defined as that portion of the crude
oil barrel left unvaporized at 650°F (343°C) and normal atmospheric
pressures, and which can be used as a feedstock to further processing or
be blended, with little alteration, into any one or all of the following
end products: asphalt, road oil, lubricating oil, waxes and residual
fuel oil. When discussing the supply and demand of residual fuel oil
this report will concentrate on residual fuel oil products as a class.
The terms residual fuel oil, fuel oil, residual and resid will be used
synonymously to refer to the latter class of petroleum products.
11
-------
C.3.4 CRUDE OIL SUPPLY FOR U.S. REFINERS
C.3.4.1 Volumetric Supplies
In 1973, 26% of the crude oil refined in the U.S. was imported, 31% of
this foreign oil originating in Canada, 23% in the Middle East, 22% in
Africa and 11% in Venezuela (see Table C.3-1). (By 1975 this dependence
on foreign crude oil has grown to 32%.) The most common crudes imported
into the East Coast in 1973 were Nigerian and Venezuelan, into the Gulf
Coast, Nigerian and Saudi Arabian, into the middle U.S., Canadian and
into the West Coast, Canadian, Indonesian and Saudi Arabian. Dependence
on crude imports varied by Petroleum Administration for Defense (PAD)
districts (see Figure C.3-1 for a definition of these regions) as shown
in Table C.3-2. The East Coast (PAD District I) imported 84% of its
1973 needs, the Gulf Coast (PAD District III) imported only 8% and other
districts imported intervening percentages as shown on Table C.3-2.
As Table C.3-3 shows, most of the domestic crude refined in the U.S. is
produced in Louisiana and Texas. This production has made District III
more than self-sufficient in crude supplies, such that in 1973 Dis-
trict III had crude production equal to 125% of crude runs in the
district's refineries. PAD District IV likewise produces more than it
needs, while the other districts have less oil production than runs to
refineries. It should be noted that District III actually imported 8%
of its total crude runs so it is not possible to say that crude produced
in a given district will necessarily be refined in that district.
C.3.4.2 Crude Oil Quality Characteristics
Crude oils are physical mixtures of hydrocarbons ranging from light,
short chain hydrocarbons such as liquefied petroleum gas (bottle gas)
to moderate weight hydrocarbons such as gas oils (distillates), to
heavy, long chain hydrocarbons such as residual fuel oil and waxes.
The proportionate yield of each of these hydrocarbons as well as overall
qualities such as sulfur and metals content vary widely among crudes.
These qualities and yields determine how a crude responds to different
processing. For example, vanadium and other metals de-activate the
12
-------
Table C.3-1
Percent of U.S. Crude Oil Imports by Country of Origin for 1973
Country of Origin
Algeria
Canada
Indonesia
Iran
Libya
Nigeria
Saudi Arabia
United Arab Emirates
Venezuela
Other
Total
Total
U.S.A.
3.7
30.9
6.2
6.7
4.1
13.8
14.2
2.2
10.6
7.3
100.0
I
8
9
1
10
6
26
8
3
21
7
100
II III
6 3
83
1
3 8
2 12
27
20
—
13
6 16
100 100
IV V
—
100 30
23
5
—
—
29
4
3
7
100 100
Total
Imports (MBBLS) 1,183,966 466,074 260,368 145,654 16,132 295,768
Percent Total Imports 100.0 39.3 22.0 12.3 1.4 25.0
Source: Department of The Interior, Bureau of Mines,
1973 Annual Petroleum Statement.
13
-------
Figure C.3-1
Petroleum Administration For Defense (PAD)
Districts of the United States
fine/. Alaska
and Hawaii)
14
-------
Table C.3-2
Percent Domestic and Foreign Crude Run in U.S. Refineries in 1973
Crude Source
Domestic
Foreign
Total
PAD
I
15.8
84.2
100.0
Total Crude Run
(MBBLS) 548,027
Source: Department
Petroleum,
PAD
II
79.6
20.4
100.0
1,271,998
of the Interior, Bureau
Petroleum Products, and
PAD
III
92.1
7.9
100.0
1,844,698
PAD
IV
89.4
10.6
100.0
PAD
V
59.1
40.9
100.0
151,521 721,010
of Mines, Mineral Industry
Natural Gas Liquids, 1973;
Surveys
Annual
Total
U.S.A.
74.1
25.9
100.0
4,537,254
, Crude
Petroleum
Statement.
-------
Table C.3-3
Percent Domestic Crude Oil Production by PAD District and Key
PAD/State
PAD I
Florida
Other
Total PAD I
PAD II
Oklahoma
Kansas
Illinois
Other
Total PAD II
PAD III
Louisiana
Texas
New Mexico
Other
Total PAD III
PAD IV
Wyoming
Other
Total PAD IV
PAD V
Alaska
California
Total PAD V
Total U.S.A.
Total U.S.A. (MBBLS)
Source: Department of
States in 1973
Crude Oil
As a Percent of Total
U.S. Crude Production
1.0
0.2
1.2
5.7
2.0
1.0
1.8
10.5
24.7
38.5
3.0
2.6
68.8
4.2
3.1
7.3
2.2
10.0
12.2
100. 0
3,360,903
Production
As a Percent of
District Refinery Runs
6.1
1.3
7.4
15.1
5.2
2.6
4.8
27.7
45.0
70.1
5.5
4.7
125.3
93.2
68.7
161.9
10.3
46.6
56.9
74.1
3,360,903
the Interior, Bureau of Mines, 1973 Annual
Petroleum Statement.
16
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catalysts used in current residuum hydrodesulfurization processes.
Likewise, asphaltenes, which are highly complex hydrocarbon ring
structures, "lock" sulfur into the hydrocarbon molecule and make
desulfurization difficult.
Qualities of several domestic and foreign crudes are given in
Table C.3-4. In general, domestic crudes are light (high °API gravity),
yield relatively low percentages of residuum and have low sulfur con-
tents. Californian and Alaskan crudes are exceptions in that they have
a relatively high residuum yield and sulfur contents, but these are not
major U.S. crude sources at the present time. Major foreign crudes from
the Persian Gulf area are fairly heavy (low °API gravity), have a high
residuum yield and are often high in sulfur. African, Canadian and
Indonesian crudes are generally sweeter (lower in sulfur) and lighter
but only African crudes are currently an important source of U.S. crude
supply. The average sulfur content of the crude refined in the U.S.
will tend to increase as U.S. crude imports increase and sulfur removal
for sulfur-sensitive products will become more important. Reclassifica-
tion of foreign crudes by ease of residual hydrodesulfurization, a
function of nickel, vanadium and asphaltene contents, yields the
ranking given in Table C.3-5. As will be discussed in more detail in
Chapter C.9, Type I crudes can be desulfurized "directly," i.e., as
the residuum comes straight from the atmospheric distillation tower.
Type IV crudes are not suitable for direct desulfurization but must be pre-
processed to allow the desulfurization operation to be less affected
by the metals content. Indirect desulfurization cannot remove as much
sulfur from residuum as can direct desulfurization.
In conclusion, if low sulfur fuel oil must be burned domestically and
crudes of Type I are not available to domestic and Caribbean refiners,
then an alternative to direct hydrodesulfurization, such as the CAFB,
may be attractive to fuel oil consumers.
17
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Table C.3-4
Quality Characteristics and
Texas S
West Texas
Louisiana
Oklahoma
Arabian Light
Arabian Heavy
Kuwait
Nigeria
Algeria
Iranian Light
Iranian Heavy
Lybian Amna
Lybian Brega
Residuum Fractions (650° +F)
ide Oils
t Mix
; Sour
irth Slope
. Ventura
i Wilmington
e Oils
.ght
:avy
'orcados
[as si Messaoud
.ght
tavy
ia
iga
i Minas
L Bachaquero
i Tia Juana
[ixed
Crude Oil
Specific
Gravity "API
35.4
33.4
36.2
40.2
27.5
29.7
19.6
34.5
28.2
31.5
29.4
44.7
33.9
31.0
35.9
40.4
35.3
17.0
26.3
39.0
of Typical Crude
Residuum Yield
(650° +F), %
Liquid Volume
20.0
31.9
38.1
38.3
53.0
47.6
64.5
43.2
63.0
58.9
38.9
27.7
41.0
50.0
48.0
32.0
59.0
58.8
57.8
36.2
Oils
Crude Oil
Sulfur Content,
% Weight
0.20
1.63
0.22
0.21
0.96
1.56
1.28
1.70
2.80
2.50
0.21
0.13
1.40
1.60
0.20
0.20
0.07
2.44
1.51
0.55
Source: Arthur D. Little, Inc.
Exxon Corp.
18
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Table C.3-5
Characteristics of Crude Oil Residuums
Related to Ease of Catalytic Hydrodesulfurization
Ease of Desulfurization
I. Can be desulfurized directly
II. Can be desulfurized directly at
a higher catalyst cost than I.
III. Can be desulfurized directly,
at a process severity and/or
final sulfur level that is
considerably higher than I.
IV. Direct processing lowers
catalyst life substantially;
judged uneconomical to
desulfurize.
Crude Quality
Low metals, low asphaltenes
Moderate metals, low
asphaltenes
Moderate metals, high
asphaltenes
High metals, high asphaltenes
Example Crude
Arabian Light
Kuwait
Qatar
Iranian Light
Iraqi Kirkuk
Arabian Heavy
Arabian Khafji
Iranian Heavy
Venezuelan Tia Juana
Venezuelan Bachaquero
Source: "Management of Sulfur Emissions" R.E. Conser, DOP Process Division;
presented at NPRA 72nd annual meeting, Miami, April 1974.
-------
C.3.5 U.S. REFINERY PRODUCTION AND USE OF RESIDUUM
Crude characteristics are a major factor in the internal layout of a
refinery. In fact, most refineries are designed around a specific
group of crudes and would require major internal processing changes
to handle any significant change in crude intake. The second major
consideration in refinery design is the anticipated product demand.
Given a crude slate and thus a set of natural yields for each hydro-
carbon group, a refiner constructs the combination of processing units
that will transform the crude barrel's "natural" yield to the desired
product mix. Most U.S. refineries are the conversion type and are
designed to maximize gasoline production from light to moderately
light, low sulfur domestic crudes. These refineries would have excess
capacity if either gasoline demand dropped or the natural yield of
gasoline-range hydrocarbons in the input crude rose. As can be seen
in Figure C.3-2 most hydrodesulfurization units (HDU) in a U.S.
refinery are associated with feed to the catalytic reformer, which is
very sensitive to sulfur content, or with streams which are blended
into low sulfur distillate products such as kerosene and home heating
oil. There is very little desulfurization capacity used for the
residuum stream going to residual fuel oil. In contrast, the typical
Caribbean refinery, as depicted in Figure C.3-3, is of the hydroskimming
type designed to utilize the natural yield of heavy crudes to maximize
residual fuel oil production. Many Caribbean plants dedicated to the
U.S. market install residuum hydrodesulfurization facilities for the
atmospheric bottoms (650°F+ [343°C+]) stream.
The initial processing unit in both conversion and hydroskimming
refineries is the atmospheric distillation tower which thermally
separates hydrocarbon streams by the differing temperatures at which
each group vaporizes. Sulfur and metals tend to "fit" most securely
into the largest (heaviest) hydrocarbon molecules so that as the
lighter streams are boiled off in the distillation process most, up'
to 80%, of the sulfur and all of the metals remain in the residuum
20
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Figure C.3-2 Conversion Refinery Flow Diagram - Sweet or Sour Crude Intake
Cs TO IC>OOP
N>
PURCHASED NATURAL GAOLINE
&A.s> Oil. 375 -«>5O'F
IC4 FOR AJ.KY LOTION
PURCHAfctD
-------
tS3
M
375°
500°F
Sas Dili
Gas Recovery
Plant
Naphtha
Splitter and
Reformer
Gasoline
Blending
Kerosene
Desulfurizer
500° to
650°F
Atmospheric
Gas Oil
Desulfurization
Refinery fuel
LPG
_^ Petrochemical
Naphtha
Motor Gasoline
Kerosene/Jet Fuel
650°+F
Diesel/Gas Oil
Heavy Fuel Oil
-------
not vaporized at the typical maximum temperature of the distillation
tower, 650°F (343°C). Streams as they exit the tower may be divided
roughly into three groups:
• Gases and naphthas - these undergo further splitting and
are either blended directly into products (LPG, petro-
chemical feedstocks) or undergo an octane-upgrading
process (catalytic reforming) before being blended
into gasoline.
• Atmospheric gas oils - these may be split and/or
desulfurized and blended into distillate products
(aviation jet fuel, kerosene, home heating oil) or
be processed by chemically altering hydrocarbon chain
length (catalytic conversion) and reformed for gasoline
blending.
• Residuum or atmospheric bottoms - most of this stream
undergoes further thermal separation in a vacuum dis-
tillation tower and is either blended directly into
products (lubrication oils, waxes, road oil, asphalt,
coke,,residual fuel oil), burned in the refinery's
internal fuel system or upgraded through conversion
processing (catalytic cracking, etc.) into lighter
products. One conversion process, coking, yields a
heavy non-converted output, coke, which is sold directly
as a product.
Although general refinery design reflects crude input and product output,
each actual refinery's throughput and operating severity for each proces-
sing unit as well as exact blending "recipes" for each product are
extremely proprietary. Furthermore, detailed crude slates which are
reported to the Bureau of Mines by every U.S. refiner are not published
on either the national or PAD district level. The only publicly available
data relevant to a study of refiners' usage of residuum at the PAD
district level and their respective sources are:
23
-------
• Crude slates by percent foreign and domestic crude and
total crude input (Bureau of Mines).
• Percent yield of each hydrocarbon groups for individual
crudes (crude assays published by oil companies).
• Installed capacity by processing unit (Oil and Gas
Journal).
• Internal refinery usage of residuum for process heating
(Bureau of Mines).
• Product outputs (Bureau of Mines).
Missing from the available information is data on detailed crude slates
and yields of output streams from certain processing units by PAD
districts. To alleviate this problem, this information has been
derived from a recent EPA study of the U.S. refining industry* and was
used in the manner described below to give an estimate of domestic
refiners' 1973 usage of residuum which is presented in Tables C.3-6
and C.3-7. Note that both tables are identical, except that Table C.3-6
shows absolute volumes of residuum by source and use while Table C.3-7
presents this data as a percentage of crude charge.
The total amount of residuum available to domestic refiners by PAD
district (column 3) is the result of multiplying the volume of crude
charge (column 1) times the residuum yield on crude (column 2) both
listed by PAD district. Crude charge by district is a published Bureau
of Mines figure. Yield on crude is a composite yield which was obtained
by combining district crude slates (from the EPA study) with their
respective crude assays to generate the total residuum yield per
thousand barrels of crude charge. Disposition of this residuum supply
is given in columns 4-8 of each table and is based on Bureau of Mines
figures for liquid refinery fuel needs (column 4) and product outputs
*The Impact of S0y Emissions Control on Petroleum Refining-Industry by
Arthur D. Little, Inc. Prepared for the Environmental Protection
Agency December 1975. Contract No. 68-02-1332, Task Order No. 1.
24
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Table C.3-6
Estimated Domestic Refiners' Usage of Residuum Hydrocarbons (650° +F) in 1973
Residuum (MBBLS)
Yield
on Crude . Residuum Disposition
(1) (2) (3) <4> (5) (6) (7) (8)
Refinery
% Fuel Residual Asphalt Lubes To Con-
Crude Liquid Volume (Internal Fuel and and version
Charge Volume (MBBLS) Use) Oil Road Oil Waxes Units
PAD I 548,027 42.9 235,104 14,814 52,258 37,122 13,514 117,396
PAD II 1,271,998 40.3 512,615 20,112 71,120 61,741 11,919 347,723
K PAD III 1,844,698 39.8 734,190 2,140 88,455 41,497 43,131 558,917
PAD IV 151,521 53.0 80,306 2,004 9,864 11,155 485 56,798
PAD V 721,010 53.0 382,135 4,939 132,900 23,695 6,411 214,190
Total
U.S.A. 4,537,254 42.9 1,944,350 44,009 354,597 175,210 75,5101,295,024
% Crude
Charge 100.0 - 42.9 1.0 7.8 3.9 1.7 28.5
Source: Department of the Interior, Bureau of Mines, 1973 Annual Petroleum Statement
Conversion Use
(9) (10)
Catalytic
Cracker and
Coker Hydrocracker
Feed Feeds
23,183 94,213
64,840 282,883
83,625 475,292
8,362 48,436
70,082 144,108
250,092 1,044,932
5.5 23.0
Arthur D. Little, Inc.
-------
Table C.3-7
Estimated Domestic Refiners' Percent Use of Residuum Hydrocarbons (650° +F) in 1973
Residuum
Yield
on Crude
PAD I
PAD II
(1) (2)
%
Crude Liquid
Charge Volume
100.0 42.9
100.0 40.3
PAD III 100.0 39.8
PAD IV
PAD V
Total
U.S.A.
Total
U.S.A.
(MBBLS)
Source
100.0 53.0
100.0 53.0
(%)100.0 42.9
4,537,254 -
: Department of
(3) (4)
Refinery
Fuel
Volume (Internal
(MBBLS) Use)
235,104 2.7
512,615 1.6
734,190 0.1
80,306 1.3
382,135 0.7
1,944,350 1.0
1,944,350 44,009
(% Crude Charge)
Residuum Disposition
(5)
Residual
Fuel
Oil
9.5
5.6
4.8
6.5
18.4
7.8
354,597
the Interior, Bureau of Mines,
(6)
Asphalt
and
Road Oil
6.8
4.9
2.3
7.4
3.3
3.9
175,210 75
1973 Annual
07)
Lubes
and
Waxes
2.5
0.9
2.3
0.3
0.9
1.7
,510 1
(8)
To Con-
version
Units
21.4
27.3
30.3
37.5
29.7
28.5
,295,024
Conversion Use
(9)
Coker
Feed
4.2
5.1
4.5
5.5
9.7
5.5
250,092
(10)
Catalytic
Cracker and
Hydrocracker
Feeds
17.2
22.2
25.8
32.0
20.0
23.0
1,044,932
Petroleum Statement
Arthur D. Little, Inc.
-------
(columns 5-7). Residuum channeled to conversion units is the remainder
of column 3 after usages represented by columns 4-7 have been subtracted
out. Conversion uses have been further broken down into coker feed and
catalytic cracker/hydrocracker feed. Bureau of Mines 1973 coke produc-
tion divided by the estimated coke yields by PAD districts generate the
regional coker feeds in column 9.
This estimated 1973 refiners' usage of residuum has assumed that heavy
product blends and liquid refinery fuel are entirely from "straight-run"
residuum; that is, that no lighter hydrocarbon streams such as gas oils
are downgraded. We also assume that residuum entering a conversion unit
is lost to the internal refinery fuel and product blending system. This
simplification is not entirely accurate as the heaviest output from the
catalytic cracker, a conversion unit oriented toward gasoline production,
remains in the residuum system and is typically burned as liquid refinery
fuel, blended into residual fuel oil product or fed into the coking unit.
In addition, heavy gas oils and naphthas may be blended into residual
fuel oil if their supply is in excess of demand, their sulfur content is
too high for distillate product specifications or if the density require-
ments of residual fuel oil require the addition of lighter hydrocarbons.
Thus, feed to conversion units (column 8) may be underestimated and
should be considered residuum volume upgraded to lighter products net
of "recycling" and hydrocarbon downgrading.
Two important comments on the availability and usage of residuum should
be made:
• Usages given in columns 4-8 are equivalent and sub-
stitutive. That is, the output for any given product,
such as residual fuel oil, is essentially a blending
choice and not limited by process capacity.
• Refineries, especially on the Gulf and West Coasts,
burn gaseous as well as liquid fuels and as the
supplies of natural gas decline, liquid hydrocarbons
27
-------
(most likely 650° + F) will be diverted into the
refinery fuel system and reduce the residuum blending
flexibility noted above.
The fact that residual fuel oil production is a blending choice is in
direct contrast to gasoline production which is process-intensive and
limited by a refiner's conversion and reforming capacities. With little
additional investment a refiner can trade increased fuel oil production
(at a sulfur level that is proportional to the crude sulfur level) for
decreased output of competing products or usages. Thus from 1970 to
1974 the Gulf Coast increased its fuel oil production by 72 MMBBLS (119%)
to 132 MMBBLS per year. Production of low sulfur resid can be accom-
plished by preferential blending, provided that other residuum usages or
products are insensitive to sulfur content and can absorb high sulfur
streams. Usually asphalt serves as the refinery's sulfur sump as high
sulfur content and qualities beneficial to asphalt production often
co-exist in the residuum streams. In addition coke products can tolerate
fairly high sulfur contents, although the steel industry has been
tightening coke sulfur specifications in the last few years. The West
Coast produced almost one-half of its 1974 fuel oil output of 124 MMBBLS
as very low sulfur resid. This sulfur content was accomplished partially
by preferential blending of residuum streams derived from sweet Indonesian
crude and partially by direct desulfurization of these streams.
Other than residuum products, drains on the residuum blending pool
include the use for upgrading to lighter products and for internal
refinery fuel. In 1973, U.S. refineries derived 71.3% of their internal
energy requirements from gaseous fuels, 36.2% from natural gas and 35.1%
from internally produced refinery gas (see Table C.3-8). We anticipate
that natural gas supplies will eventually be unavailable for use as
refinery fuel causing refiners to divert more liquid hydrocarbons
(most likely residuum) into the refinery fuel system. In 1973, Gulf
and West Coast refineries derived 54% and 31%, respectively, of their
total internal energy requirements from natural gas. If 1973 gaseous
28
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S3
VO
Table C.3-8
Fuels Consumed by Refineries
Area
PAD District I
PAD District II
PAD District III
PAD District IV
PAD District V
Total U.S.
Total B.T.U.
Requirement
(billion BTU)
353,395
714,596
1,426,446
96,592
466,747
3,057,776
natural pas
by PAD District
Energy
Natural
GasCD
9.4
19.0
53.5
29.1
31.3
36.2
- i .n
Refinery
Gasd)
38.5
41.4
29.6
34.7
40.0
35.1
Tl R.T.TI./ri
1973
Source, percent total B
Coke(D
14.4
16.9
10.7
18.5
12.6
13.1
ihi r f nnt .
Residual
Fuel Oil^1)
26.4
17.7
0.9
13.0
6.7
9.0
.T.U.
Other(2>
11.3
5.0
5.3
4.7
9.4
6.6
Total
Fuel Source
100.0
100.0
100.0
100.0
100.0
100.0
(2)
refinery gas - 990 B.T.U./cubic foot.
coke - 30,120,000 B.T.U./short ton (5 bbl per short ton).
residual fuel oil - 6,287,000 B.T.U./bbl.
Includes crude oil, liquified petroleum gas, coal, purchased electricity and purchased steam.
Source: Department of The Interior, Bureau of Mines,
1973 Annual Petroleum Statement.
-------
volumes on the Gulf and West Coasts were totally replaced by residuum
an additional 121 and 23 MMBBLS, respectively, would be diverted from
those districts' residuum pools. For the entire U.S. refinery industry
in 1973 this figure would be 176 MMBBLS which would have been 9% of the
total available residuum for that year. Diversion of residuum to con-
version units is a function of complex forces, including product
quality requirements. For example, if gasoline sulfur contents must
be reduced without lowering octane levels additional catalytic reforming
of desulfurized streams will be required. Because reforming units yield
less than 100% of their liquid input as gasoline product, intake volumes
will have to be increased to replace these processing losses. The
tendency of these forces to increase residuum upgrading and decrease the
residuum blending pool is uncertain but is certainly influenced by
economics.
As long as a refiner can make more money by sending residuum to conver-
sion units this is the preferred course of action, and this has been
the normal situation for years for U.S. refineries. Since the advent
of the Crude Oil Entitlements Program the economics have shifted and
refineries have seen an opportunity to sell lower cost residuum in a
market where prices are primarily set by higher-priced foreign imports.
This has led to the marked increase in residual fuel oil production by
domestic refiners. In the same way, higher values assigned to lubes or
asphalts or use of residuum for petrochemical feedstock, say, would
tend to pull production from residual fuel oil to those products. Thus
relative economics, rather than physical processing capacities, is one
of the main driving factors in determining residuum use.
C.3.6 1974 SUPPLY OF RESIDUAL FUEL OIL BY PAD DISTRICT
Having outlined the general forces affecting U.S. production of residual
fuel oil, we will now focus on regional supplies. Tables C.3-9 through
C.3-13 summarize 1974 supply by PAD district and have been developed
from detailed analyses of residual fuel oil supplies which are shown
in Table C.3-14. Table C.3-14 has data for each year from 1970 to the
30
-------
Table C.3-9
Source of Residual Fuel Oil Demand by PAD District in 1974
(Expressed as Percentage
Refinery Output
(% Self-
sufficiency) Imports
I
II
III
: IV
V
9
77
142
101
86
40
.0
.2
.9
.3
.6
.8
85
9
12
0
15
59
.2
.3
.8
.0
.1
.9
of Consumption)
Inter-PAD
Transfers
(net)
6.
12.
(53.
(3.
0.
0.
2
6
6)
0)
5
0
Otherb
0.
0.
(2.
1.
(2.
(0.
4
9
1)
7
2)
7)
Total Local
Consumption
% MBBLS
100.
100.
100.
100.
100.
100.
0
0
0
0
0
0
624,664
85,239
92,371
12,231
143,306
957,811
Area
PAD District I
PAD District II
PAD District II
PAD District IV
PAD District V
Total U.S.
Includes foreign crude oil burned directly as fuel (1.3% of total U.S.
imports in 1974).
Stock changes and domestic crude oil burned directly as fuel minus
exports.
Source: Department of the Interior, Bureau of Mines, 1974 Monthly
Petroleum Statement.
31
-------
Table C.3-10
Distribution of Domestic Production of Residual
Area
PAD District I
PAD District II
PAD District III 19
PAD District IV 18
PAD District V
Fuel Oil by Sulfur Content - 1974
% Sulfur
a
Low Sulfur
<0.50 0.51-1.00
19 38
4 41
19 34
18 30
46 4
bv Weight
High
1.01-2.
24
34
10
18
44
Sulfur3
00 >2.00
19
21
37
34
6
Total
Production
% MBBLS
100 56,164
100 65,775
100 132,002
100 12,396
100 124,154
Total
U.S.A.
25
26
27
22
100 390,491
low sulfur is defined as less than .50% weight; very high sulfur
greater than 2.00% weight.
Source: Department of The Interior, Bureau of Mines,
1974 Monthly Petroleum Statement.
32
-------
Table C.3-11
Imports of Residual Fuel Oil by Sulfur Level and Exporting Country 1974
(MBBLS)
% 1974 % Sulfur by Weight
Total Low Sulfurb High Sulfur0 Total
Country of Origin3 Imports <0.50 0.51-1.00 1.01-2.00 >2.00 Imports
Bahamas 7.3 14,183 9,033 4,206 11,763 39,185
Canada 5.1 9,169 3,773 3,663 10,860 27,465
Italy 2.3 8,678 1,598 585 1,191 12,052
Netherland West Indies 23.4 40,371 39,584 6,234 39,058 125,248
Trinidad 7.2 15,307 9,997 10,428 3,058 38,790
Venezuela 29.5 33,887 25,956 27,552 69,937 157,332
Virgin Islands 19.3 55,051 11,188 19,964 16,685 102,885
Other 5.9 19,588 5,552 3,113 3,123 31,376
Total Imports0 100.0 196,234 106,681 75,745 155,675 534,335
% 1974 Total Imports - 36.7 20.0 14.2 29.1 100.0
a
Country exporting directly into the United States; not necessarily
refinery location or crude source.
Very low sulfur is defined as <0.50% weight.
Very high sulfur is defined as >2.0% weight.
c
Excludes bonded and military imports (39,417) whose volumes are not
available by sulfur content.
Source: Department of the Interior, Bureau of Mines, Mineral Industry
Surveys, Availability of Heavy Fuel Oils by Sulfur Levels
Monthly 1974.
33
-------
Table C.3-12
Interdistrict Movements of Residual Fuel Oil Between PAD Districts in 1974
(MBBLS)
Movement From Total Total
Destination PAD I
PAD District I
PAD District II
PAD District III
PAD District IV
PAD District V
Total Shipments
PAD I PAD II PAD III PAD IV PAD V
2,450 36,023
13,209
—
—
316 365
0 2,450 49,548 365 0
Receipts
38,473
13,209
0
0
681
52,363
Receipts
73.5
25.2
0.0
0.0
1.3
100.0
Source: Department of Interior, Bureau of Mines, 1974 Monthly
Petroleum Statements.
34
-------
Table C.3-13
Estimated Percent Availability
of Residual Fuel Oil by Sulfur Content 1974
% Sulfur by Weight'
Area
PAD District I
PAD District II
PAD District III 15
PAD District IV
PAD District V
Low
< 0.50
33
9
15
18
51
Sulfur
0.51-1.00
24
41
26
31
4
High
1.01-2.00
15
29
12
18
39
Sulfur
>2.00
28
21
47
33
6
Total
Availability
% MBBLS
100 591,338
100 87,176
100 87,648
100 12,342
100 140,111
Total U.S.A.
32
23
19
26
100 918,615
aThe split between low and high sulfur is 1.00% weight. Very low sulfur
is defined as less than 0.5% weight; very high sulfur as greater than
2.00% weight.
Based on refinery output, non-military and non-bonded imports, ship-
ments from PAD III to other districts and stock changes (94.7% of 1974
supply). Excludes military and bonded imports, shipments from all
districts except PAD III, domestic crude burned directly as fuel and
exports.
Source: Department of Interior, Bureau of Mines, 1974 Monthly Fuel Oil
Availability.
35
-------
Table C.3-14
Detailed Residual Fuel Oil Domestic Supply and Consumption by PAD Districts - 1970-1974
u>
PAD District I
Refinery output
Imports - residual fuel oil
- crude burned directly
Total Imports
Domestic crude burned
Domestic receipts from
- PAD II
- PAD III
- PAD V
Total domestic receipts
Stock changes
Total PAD supply
Exports
Local PAD consumption
Stock year-end
PAD District II
Refinery output
Imports - residual fuel oil
- crude burned directly
Total Imports
Domestic crude burned
1970
35,059
N.A.
N.A.
536,968
0
1,210
28,704
0
29,914
3,024
598,917
872
598,045
24,136
62,839
N.A.
N.A.
4,207
579
(MBBLS)
1971
37,125
N.A.
N.A.
558,771
0
1,009
32,588
40
33,637
3,097
626,436
606
625,830
27,233
58,890
N.A.
N.A.
3,953
576
1972
37,582
607,051
9,939
616,990
0
1,798
30,389
160
32,347
(2,935)
689,854
1,502
688,352
24,298
65,848
4,978
480
5,458
578
1973
52,258
626,457
13,154
639,611
0
796
16,960
0
17,756
1,120
708,505
87
708,418
25,418
71,120
4,152
1,916
6,068
578
1974
56,164
527,563
4,787
532,350
0
2,450
36,023
0
38,473
2,221
624,766
102
624,664
.27,639
65,775
5,209
2,721
7,930
578
1974
(6 mos)
28,336
272,481
241
272,722
0
1,470
14,791
0
16,261
1,437
315,882
55
315,827
26,518
32,661
1,866
352
2,218
289
1975
(6 mos)
36,126
207,540
200
207,740
0
1,470
24,064
0
25,534
11,024
258,376
5
258,371
37,542
35,906
6,842
427
7,269
289
Domestic receipts from
- PAD III
7,785
4,732
7,407
10,523
13,209
5,835
6,190
-------
Table C.3-14 Detailed Residual Fuel Oil Domestic Supply and Consumption by PAD Districts - 1970-1974 (Cont'd)
(MBBLS)
PAD District II (Cont'd)
Stock changes
Total PAD supply
Domestic shipments
Exports
Local PAD consumption
1970
2,508
72,902
1,210
316
71,376
1971
565
67,586
1,009
316
66,261
1972
(1,304)
80,595
1,798
511
78,286
1973
226
88,063
796
179
87,088
1974
(261)
87,753
2,450
64
85,239
1974
(6 mos)
(211)
41,214
1,470
24
39,720
1975
(6 mos)
1,211
48,443
1,470
23
46,950
Stock year-end
PAD District III
Refinery output
Imports - residual fuel oil
- crude burned directly
Total Imports
Domestic crude burned
Domestic receipts
Stock changes
Total PAD supply
Domestic shipments
Exports
Local PAD consumption
Stock year-end
PAD District IV
Refinery output
Imports - residual fuel oil
- crude burned directly
Total Imports
8,806
6,119
9,371
7,244
8,067
8,293
8,032
6,064
7,066
10,072
6,522
9,995
7,733
60,342
N.A.
N.A.
11,029
1,785
0
763
72,393
36,494
4,211
31,688
60,894
N.A.
N.A.
6,553
1,783
0
1,125
68,105
37,320
3,167
27,618
65,047
6,212
0
6,212
1,781
0
(1,180)
74,220
37,796
4,667
31,757
88,455
10,471
0
10,471
1,784
0
1,002
99,708
29,381
2,127
68,200
132,002
11,805
0
11,805
1,784
0
3,006
142,585
49,548
666
92,371
54,070
6,598
0
6,598
892
0
2,935
58,625
20,942
60
37,623
80,803
2,557
0
2,557
892
822
(383)
85,457
31,271
219
53,967
9,612
9,100
N.A.
N.A.
52
9,886
N.A.
N.A.
41
9,152
0
0
0
9,864
0
0
0
12,396
2
0
2
5,571
2
0
2
6,545
0
0
0
-------
Table C.3-14 Detailed Residual Fuel Oil Domestic Supply and Consumption by PAD District - 1970-1974 (Cont'd)
CO
oo
(MBBLS)
PAD District IV (Cont'd)
»
Domestic crude burned
Domestic receipts
Stock changes
Total PAD supply.
Domestic shipments
Exports
Local PAD consumption
1970
252
0
72
9,332
365
0
8,967
1971
252
0
404
9,775
730
3
9,042
1972
252
0
(533)
9,937
365
0
9,572
1973
252
0
495
9,621
365
0
9,256
1974
252
0
54
12,596
365
0
12,231
1974
(6 mos)
126
0
384
5,315
219
0
5,096
1975
(6 mos)
126
0
(56)
6,727
219
0
6,508
Stock year-end
PAD District V
Refinery output
Imports - residual fuel oil
- crude burned directly
Total Imports
Domestic crude burned
Domestic receipts from
- PAD III
- PAD IV
Total domestic receipts
Stock changes
Total PAD supply
Domestic shipments
Exports
Local PAD consumption
515
919
386
881
935
961
905
90,170
N.A.
N.A.
5,589
1,701
5
365
370
(10,768)
108,598
0
14,386
94,212
107,889
N.A.
N.A.
8,382
1,954
0
730
730
496
118,459
40
9,125
109,294
114,890
8,741
0
8,741
711
0
365
365
1,487
123,220
160
5,380
117,680
132,900
16,040
4,035
20,075
3,512
1,898
365
2,263
(4,579)
163,329
0
6,114
157,215
124,154
21,665
0
21,665
2,137
316
365
681
1,194
147,443
0
4,137
143,306
60,798
13,945
0
13,945
1,068
316
219
535
1,535
74,811
0
2,017
72,794
70,231
6,126
0
6,126
1,068
1,017
219
1,236
(27)
78,688
822
2,082
75,784
Stock year-end
14,418
14,914
16,401
11,822
13,016
13,895 13,868
-------
Table C.3-14 Detailed Residual Fuel Uil Domestic Supply and Consumption by PAD Districts - 1970-1974 (Cont'd)
(MBBLS)
Total U.S.A.
Refinery output
Imports - residual fuel oil
- crude oil burned
Total Imports
Domestic crude burned
Stock changes
Total U.S. supply
Exports
Domestic consumption
1970
257,510
N.A.
N.A.
557,845
4,317
(4,401)
824,073
19,785
804,288
1971
274,684
N.A.
N.A.
577,700
4,565
5,687
851,262
13,217
838,045
1972
292,519
626,982
10,419
637,401
3,322
(4,465)
937,707
12,060
925,647
1973
354,597
661,155
15,070
676,225
6,126
(1,736)
1,038,684
8,507
1,030,177
1974
390,491
566,244
7,508
573,752
4,751
6,214
962,780
4,969
957,811
1974
(6 mos)
181,436
294,892
593
295,485
2,375
6,080
473,209
2,156
471,060
1975
(6 mos)
229,611
223,065
627
223,692
2,375
11,769
443,910
2,329
441,580
u>
Stock year-end
53,994
59,681
55,216
53,480
59,694
57,891 69,660
rAD consumption of crude for direct burning estimated for PAD I-IV (BOM estimates)
Estimated from BOM daily statistics for year
Source: Department of the Interior, Bureau of Mines, Mineral Industry Surveys, Crude Petroleum,
Petroleum Products, and Natural Gas Liquids, 1973; Annual Petroleum Statements, 1970,
1971. 1972. 1973; Monthly Petroleum Statements. 1974. 1975.
-------
first six months of 1975 by PAD district. Figures C.3-4 through C.3-8
present graphically the 1974 supply data for each PAD district which is
presented in tabular form in Table C.3-14. Note that 1974 is being used
here since it is the latest available full year of residual fuel oil
supply information. For further discussion about data availability
see C.2.
C.3.6.1 Overview at PAD Districts
The United States, in particular the East Coast, imports most of its
residual fuel oil needs (Table C.3-9). In 1974, 60% of total U.S.
domestic fuel oil supplies were derived from product imports. Dis-
trict IV imported no resid while District I imported 85% of its
requirements. The balance of domestic supply was produced at U.S.
refineries with approximately 1% being supplied by stock changes and
direct burning of domestic crude oil. Domestic resid production in
1974 was evenly split between the West Coast, the Gulf Coast and the
rest of the U.S. and was distributed fairly evenly along a spectrum
ranging from very low to very high sulfur content as shown in
Table C.3-10. However, the demand profile by sulfur content did not
match the production profile and imports of low sulfur fuel oil were
needed to balance demand. Table C.3.11 shows that 37% of 1974 imports
were low sulfur with 77% originating in the Caribbean or Venezuela.
Sulfur level demand by PAD districts also did not match the production
profile and resulted in fuel oil imports to the East Coast and inter-
district transfers from the Gulf to the East Coast. Virtually all (99%)
of the imports listed in Table C.3-11 and most (74%) of the interdistrict
transfers detailed in Table C.3-12 were destined for the East Coast.
Also to be noted is the fact that the Gulf Coast was a net supplier of
residual fuel oil in 1974, shipping 50 MMBBLS (35%) of the district's
supplies (production plus imports) of 143 MMBBLS to other districts.
The final estimated percent availability of residual fuel oil by sulfur
content and by PAD district for 1974 is given in Table C.3-13.
40
-------
While reading the following district-by-district discussion, frequent
reference should be made to Tables C.3-9 through C.3-13. Table C.3-9
shows how self-sufficient each district was in residual fuel oil
supplies. Tables C.3-10 and C.3-11 break down local production and
imports by sulfur level while Table C.3-12 shows movements between
districts. The result is Table C.3-13 which shows the 1974 supply of
residual fuel oil by sulfur content levels by PAD district. It should
be noted that some estimating was required to derive Table C.3-13
since data about the sulfur content of 5.3% of total U.S. supply was
not available.
C.3.6.2 PAD District I - The East Coast (Figure C.3-4)
The East Coast is the least self-sufficient of all districts, having
produced only 9% (56 MMBBLS) of its 1974 needs, imported 85% (532 MMBBLS)
and received 6% (38 MMBBLS) from interdistrict transfers (Table C.3-9).
Virtually all (99%) of the fuel oil imported into the U.S. was destined
for the East Coast and most (74%) originated in the Caribbean and
Venezuela. A historical relationship has developed between Caribbean
hydroskimming refiners and East Coast fuel oil consumers, principally
public utilities. Extensive desulfurization capacity in the Caribbean
is dedicated to the processing of high sulfur Venezuelan crudes into
low sulfur residual fuel oil. Imports of North African and other low
sulfur crudes into Caribbean refineries is earmarked for the production
of very low sulfur residual which is needed by East Coast utilities to
satisfy air quality regulations. In 1974, local PAD District I produc-
tion of low sulfur fuel oil (32 MMBBLS) was supplemented by large imports
of low sulfur oil (277 MMBBLS) and some transfers from other districts
(28 MMBBLS) or almost 75% of such movements. The distribution of fuel
oil availability by sulfur content given in Table C.3-13 reflects
regional differences in sulfur regulations which will be discussed in
detail in C.5. Briefly described, these regulations require
the burning of very low sulfur fuel oil in most urban areas (Boston,
metropolitan New York City, Philadelphia) and all of Connecticut. Low
41
-------
Figure C.3-4
Supply
Refinery Output
Imports
Domestic Receipts
Stock Changes
Dom. Crude Burned
Total
PAD District 1
1974 Residual Fuel Oil Product Position
(MBBLS)
56,164
532,350
38,473
2,221
624,766
Disposition
Local Consumption 624,664
Domestic Shipments
Exports 102
Total 624,776
District II
Receipts 2,450
District III
Receipts 36,023
Includes all military and bonded
imports of residual fuel oil.
Imports
N.W.I 121,588
Venezuela,150,844
Virgin Is. 97,460
Other3 162.458
Total 532,350
Source: Department of the Interior, Bureau of Mines,
1974 Monthly Petroleum Statements.
42
-------
sulfur resid is required in most of New England, all of New Jersey,
Maryland and the District of Columbia. High sulfur fuel oil may be
burned in Maine, New Hampshire, the Virginias, the Carolinas, Georgia
and Florida.
C.3.6,3 PAD District II - The Midwest (Figure C.3-5)
In 1974 this area was 78% self-sufficient in fuel oil supply, imported
9% of local demand from Canada and received 13% from PAD District III.
PAD Districts II and III are the only major interdistrict shippers of
residual fuel oil, the Midwest having sent 2 MMBBLS to the East Coast
in 1974. Sulfur regulations are typically more lenient in PAD Dis-
trict II than in PAD District I allowing the burning of high sulfur
fuel oil in most states and in all non-urban areas. Only low sulfur
fuel oil may be burned in Oklahoma and Illinois, yet no legislation
currently in force in PAD District II restricts combustion of fuel oil
to very low sulfur levels.
C.3.6.4 PAD District III - The Gulf Coast (Figure C.3-6)
The Gulf Coast is a net shipper of fuel oil, having produced 143% of its
own district demand in 1974 and imported another 13%. The excess supply
was shipped to other districts, 36 MMBBLS to PAD District I and 13 MMBBLS
to PAD District II. Comparison of PAD District III production by sulfur
content (Table C.3-10) and final availability (Table C.3-13) reveals that
most of the shipments out of the Gulf Coast in 1974 were of low sulfur
fuel oil even though sulfur regulations in Texas and Louisiana require
the burning of low sulfur oil. However, New Mexico, Arkansas, Mississippi
and Alabama allow the burning of high sulfur fuel oils.
C.3.6.5 PAD District IV - The Rocky Mountains (Figure C.3-7)
This district was fully self-sufficient in residual fuel oil in 1974.
Its refinery output of 12 MMBBLS was split evenly between low and high
sulfur as was its final availability of fuel oil by sulfur content.
Both imports and interdistrict transfers were minor in 1974. In all
states except Colorado the burning of high sulfur fuel oil is permitted.
43
-------
Figure C.3-5
PAD District II
1974 Residual Fuel Oil Product Position
(MBBLS)
Imports
Canada 7,483
Venezuela 447
Total 7.930
Supply
Refinery Output 65,775
Imports 7,930
Domestic Receipts 13,209
Stock Changes (261)
Dom. Crude Burned 578
Total 87,753
Disposition
Local Consumption 85,239
Domestic Shipments 2,450
Exports 64_
Total 87,753
:::>
>K^:y»-^J
District III
Receipts 13,209
District I
Shipments 2,450
Source: Department of the Interior, Bureau of Mines,
1974 Monthly Petroleum Statements.
44
-------
Figure C.3-6
PAD District III
1974 Residual Fuel Oil Product Position
(MBBLS)
Supply
Refinery Output 132,002
Imports 11,805
Domestic Receipts
Stock Changes 3,006
Dom. Crude Burned 1,784
Total 142,585
Disposition
Local Consumption 92,371
Domestic Shipments 49,548
Exports 666
Total
District II
Shipments 13,209
District V
Shipments 316
District I
Shipments 36,023
Imports
Bahamas
Venezuela
Virgin Is.
Other3
Total
1,765
1,289
3,429
5,322
11,805
Includes all military and bonded imports
of residual fuel oil.
Source: Department of the Interior, Bureau of Mines,
1974 Monthly Petroleum Statements.
45
-------
Figure C.3-7
PAD District IV
1974 Residual Fuel Oil Product Position
(MBBLS)
District V
Shipments 365
Supply
Refinery Output 12,396
Imports 2
Domestic Receipts
Stock Changes 54
Dom. Crude Burned 252
Total 12,596
Disposition
Local Consumption 12,231
Domestic Shipments 365
Exports . —
Total 12,596
Source: Department of the Interior, Bureau of Mines,
1974 Monthly Petroleum Statements.
46
-------
C.3.6.6 PAD District V - The West Coast (Figure C.3-8)
The West Coast produced 87% of its 1974 fuel oil consumption, imported
15% and received a small amount from interdistrict transfers. (These
figures sum to 100% when exports of 2% are netted out.) Approximately
one-third of both total 1974 U.S. fuel oil production and U.S. produc-
tion of low sulfur fuel oil originated in this district. PAD District V
1974 fuel oil production and final availability by sulfur content shows
a bulge in the very low sulfur and high sulfur categories. This dis-
tribution corresponds to current sulfur regulations of .5% in urban
California areas and 1.9% in non-urban areas.
47
-------
Figure C.3-8
PAD District V
1974 Residual Fuel Oil Product Position
(MBBLS)
Imports
Indonesia 4,910
Venezuela 4,752
Other* 12.003
Total
21,665
Supply
Refinery Output 124,154
Imports 21,665
Domestic Receipts 681
Stock Changes 1,194
Dom. Crude Burned ' 2,137
Total 147,443
Disposition
Local Consumption 143,306
Domestic Shipments 681
Exports 4,137
Total 147,443
District IV
Receipts 365!
District III
Receipts 316
"HY^U.
^Includes all military and bonded imports of residual fuel oil.
Source: Department of the Interior, Bureau of Mines,
1974 Monthly Petroleum Statements.
48
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C.4 DOMESTIC DEMAND FOR RESIDUUM PRODUCTS
C.4.1 INTRODUCTION
Marketed residuum products, comprising residual fuel oil, lubricants,
waxes, coke, asphalt, and road oil, represent approximately one fifth
of demand for all refined petroleum products in the United States (see
Table C.4-1). Residual fuel oil, accounting for approximately three-
quarters of this product grouping, is obviously the major determinant of
the overall demand for the entire category. Consequently, this discussion
of historical demand will concentrate on residual fuel oil and will briefly
summarize the remaining products.
Information on fuel oil sales, which is used as a proxy for demand, is
available in very complete detail at the state level. All of the relevant
state data has been assembled and included in Tables C.4-9 to 14. To be
consistent with other sections of the report, the state-by-state data has
been aggregated to the PAD District level for analysis. Tables C.4-9 to
14 provide an up-to-date data base for any in-depth state-by-state analysis
that may be conducted in the future, as well as displaying the information
availabilities at the state level. While our actual discussion of demand
highlights some of the significant characteristics of the states, the
*
main focus is at the regional and national levels.
c.4.2 OVERVIEW ON MARKET DEMAND
In the last few years, developments related to the petroleum industry
*
See Chapter C.2 on data availability for a full explanation of sources,
etc.
49
-------
Table C.4-1
The Importance of Residual Oil Products in
Domestic Consumption of Petroleum Products
1970-1974
Demand Levels Demand Levels
(MMBBLS) (Percentage Distribution)
Petroleum Products 1970 1973 1974 1970 1973 1974
Gasoline 2131.3 2452.7 2402.4 39.7% 38.8% 39.6%
Jet Fuel 353.0 386.6 362.6 6.6 6.1 6.0
Ethane 83.8 119.4 124.6 1.6 1.9 2.0
Liquefied Gases 363.1 409.3 388.2 6.8 6.5 6.4
Kerosene 96.0 78.9 64.4 1.8 1.3 1.1
Petrochemical Feedstocks 101.2 129.9 132.5 1.9 2.1 2.2
Special Naphthas 31.4 32.2 32.0 0.6 0.5 0.5
Distillate Fuel Oil 927.2 1128.7 1072.8 17.3 17.9 17.7
Residual Fuel Oil
Lubricants
Waxes
Coke
Asphalt
Road Oil
Subtotal Residuum Oil
Products
804.3
49.7
4.6
77.2
153.4
9.6
1098.9
1030.2
59.2
6.9
95.2
182.6
7.8
1381.9
957.8
56.7
6.8
87.1
168.7
6.9
1284.0
15.0
0.9
0.1
1.4
2.9
0.2
20.5
16.3
0.9
0.1
1.5
2.9
0.1
21.8
15.8
0.9
0.1
1.4
2.8
0.1
21.2
Still Gas 163.9 176.8 175.7 3.1 2.8 2.9
Miscellaneous 14.8 18.9 24.3 0.3 0.3 0.4
Plant Condensate NA 1.9 6.1 NA — 0.1
Total Petroleum Products 5364.5 6317.3 6069.5 100.0 100.0 100.0
Notes: Columns may not sum to totals due to rounding.
NA indicates data not available.
—indicates value less than 0.05.
Source: U.S. Department of Interior, Bureau of Mines, Mineral Industry
Surveys: Petroleum Statement, Annual (1970, 1973), Monthly
(December, 1974).
50
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have resulted in dramatic changes in the market for petroleum products,
both in market size and structure. Obviously, the primary development
was the spiraling prices for foreign crude petroleum. The impact rippled
through every facet of the petroleum industry and caused alterations in
all aspects of petroleum product usage. Conservation measures, reinforced
by the widespread economic recession in the U.S. and most other parts of
the world, fostered an unprecedented turnaround in demand for petroleum
products.
Growth in petroleum product demand, which had been advancing at an annual
rate of 5.6 percent from 1970-1973, actually declined nearly 4 percent in
1974, down from 6.3 billion barrels to 6.1 billion barrels. Marketed
residuum products exhibited an even more remarkable falling off, absorbing
nearly half of the drop in demand. Demand for all residual oil products
dropped nearly 100 million barrels in 1974, down to 1284 million barrels
from a level of 1382 million barrels a year earlier. Growth in that
year was a negative 7 percent, after having advanced at an annual rate of
nearly 8 percent for the preceding three years. Residual fuel oil, it-
self, which had been growing at closer to 9 percent per annum, also
dropped 7 percent in 1974, compared to 1973 consumption. The only
petroleum products to show any increase in 1974 were related to the
manufacture of petrochemicals. Table C.4-1 shows the domestic demand
levels for all refined petroleum products for 1970, 1973, and 1974 and
also provides the breakdown of demand by product group. By scanning
the percentage distribution columns, it becomes apparent that percent
demand by product categories has been remarkably stable with only
residual oil products showing any noticeable increase in demand share,
rising from 20.5 percent in 1970 to 21.2 percent by 1974. The only
other product categories to register any gain in demand share were
distillate fuel oil, petrochemical-related products, and miscellaneous.
On a geographic basis, as defined by the five PAD Districts, the East
Coast was the largest regional consumer of residual oil products,
commanding nearly 60 percent of total domestic demand. PAD District II
51
-------
and V each accounted for about 15 percent of the total, while the Gulf
Coast region represented approximately 10 percent; the Rocky Mountain
region (PAD District IV) held the remaining 2 percent of national demand.
This is shown in Table C.4-2, which shows average calendar day demand.
C.4.3 RECENT HISTORY OF NON-ENERGY DEMAND FOR RESIDUUM-BASED PRODUCTS
Residuum-based products other than residual fuel oil fall into three
product groupings:
Lubricants and Waxes
Coke
Asphalt and Road Oils
Together they account for approximately 5.5 percent of total petroleum
product demand. Individually, asphalt and road oils are the largest
with 3.0 percent; coke accounts for approximately 1.5 percent; and
lubricants and waxes, the remaining 1.0 percent.
These residuum products are predominantly used for non-energy purposes.
Including petrochemical feedstocks (most of which are not residuum),
nearly two-thirds of the non-energy petroleum products have historically
been consumed in the industrial sector for the manufacture of petro-
chemicals, for aluminum fabrication, as lubricants and waxes, and for
other miscellaneous purposes. An additional 30 percent has been
accounted for by the commercial sector, mostly as asphalt and road oil,
and the remaining 5 percent as lubricants in the transportation sector.
Asphalt and road oil constitute the second largest use of petroleum as
a raw material after petrochemical usage; these products are used
extensively for paving roads, manufacturing shingles and other building
materials, waterproofing, and miscellaneous uses. The growth in demand
for these products is governed to a great extent by both the highway
construction program and general building activity.
52
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Table C .4 -2
Domestic Demand for Residuum; by Product Type, by PAD District
1973
(MBCD)
PAD
District
I
II
III
IV
V
U.S. Total
PAD
District
I
II
III
IV
V
U.S. Total
PAD
District
I •
II
III
IV
V
U.S. Total
Residual
Fuel Oil
1,940
239
187
26
430
2,822
Percentage
Residual
Fuel Oil
88.8
42.1
45.5
35.6
78.5
74.5
Percentage
Residual
Fuel Oil
68.8
8.5
6.6
0.9
15.2
100.0
Lubricants
66
39
40
17
162
Breakdown of
Lubricants
3.0
6.9
9.7
3.1
4.3
Breakdown of
Lubricants
40.7
24.1
24.7
10.5
100.0
Wax
7
3
6
3
19
Product
Wax
0.3
0.5
1.5
0.6
0.5
Product
Wax
36.8
15.8
31.6
15.8
Coke
30
99
87
11
34
261
Usage
Coke
1.4
17.4
21.2
15.1
6.2
6.9
Usage
Coke
11.5
37.9
33.3
4.2
13.0
100.0 100.0
Asphalt
141
176
91
34
58
500
by PAD
Asphalt
6.5
31.0
22.1
46.6
10.6
13.2
Across
Asphalt
28.2
35.2
18.2
6.8
11.6
100.0
Source: U.S. Department of Interior, Bureau of Mines,
Surveys: Crude Petroleum Statement, 1973.
Road
Oil
2
12
2
6
22
District
Road
Oil
0.1
2.1
2.7
1.1
0.6
Total
Residual
Oil
2,186
568
411
73
548
3,786
Total
Residual
Oil
100.0
100.0
100.0
100.0
100.0
100.0
PAD Districts
Road
Oil
9.1
54.5
9.1
27.3
100.0
Mineral
Total
Residual
Oil
57.7
15.0
10.9
1.9
14.5
100.0
Industry
53
-------
The principal uses for petroleum coke have been for refinery fuel and
the making of electrodes of which a significant amount has been for
metallurgical electrodes used in aluminum reduction plants and for
electrodes incorporated in electric motor brushes. Approximately
one quarter of U.S petroleum coke production has been exported,
mainly to Japan, Canada, and Europe.
The demand for lubricants and waxes reflects some technical trends:
improved quality of all types of lubricating oils and greases lengthens
their useful life and enables them to withstand harder use; changes
in engine and other equipment design reduce lubricant requirements.
In addition, a decline in exports caused by increased foreign manufacture
has led to a decline in lubricants and wax demand on domestic refineries
as a percent of refinery output. These reasons account for the decline
in lubes and waxes from 2 percent of total petroleum demand to the
current 1 percent share.
C.4.4 DOMESTIC DEMAND FOR RESIDUAL FUEL OIL
C.4.4.1 On The National Level
The domestic market for residual fuel oil is broken into the following
market segments:
• Residential/Commercial and Industrial users
• Electric Utilities
• Railroads and Vessels and
• Military and Miscellaneous.
In addition to this sales market, real residual fuel oil demand also
includes resid retained for use within the oil companies, especially
for refinery fuel. Although there are other internal refinery uses,
mainly the diversion of potential residual fuel oil to alternative
residuum-based products, this is perceived as a supply factor rather
than a demand usage and has been discussed accordingly in the supply
section of this report.
54
-------
As previously stated, total U.S. demand for residual fuel oil, as
measured by the Bureau of Mines sales information, increased at an
average annual rate of 8.6 percent from 1970-1973. (See Table C.4-3)
While decreases in its use by Railroads and the Military have occurred
during that period, all other consuming sectors registered gains from
slightly more than 1 percent for Residential/Commercial to the nearly
18 percent shown for Electric Utilities. However, the year to year
rates of growth during this period were not stable. In 1971, all major
user categories, except Electric Utilities, actually experienced a
reduction in demand relative to 1970. While the other sectors of demand
were still showing the effect of the 1970 economic slowdown, the Electric
Utilities demand for residual fuel oil was being supported by the EPA's
efforts to convert electric power plants to oil from coal for environ-
mental reasons. This trend continued until the oil embargo in 1973, when
the reverse process was instituted due to the shortage of oil. The net
result was that Electric Utilities were the only major user-category to
experience any expansion in demand share from 1970-1973; its share of
total residual fuel oil sales rose from just under 40 percent in 1970
to nearly 50 percent in 1973. (See Table C.4-4 which contains the same
information as Table C.4-3 but expressed in percentage terms.) In terms
of market share, the second most significant user-category is Industrial,
which represents an additional 20 percent of residual fuel oil demand and
includes oil company use of residual as well as any external sales to
industry for heating and/or processing purposes.* The industrial share
of the market went from 22 percent in 1970 to approximately 20 percent
since that year. The other significant user-category is Residential/
Commercial, whose share of fuel oil sales also declined from 1970 to
1973, with 23 percent in 1970 and 19 percent in 1973.
*The Bureau of Mines solicits fuel oil sales information using a direct
mail survey involving companies which sell in excess of 10,000 barrels
of fuel oil and kerosene during the year in question. While industrial
sales are requested to be stated excluding fuel oil for heating, this
has typically not been the case. Consequently, industrial sales are
commonly considered to include industrial fuel oil sales for heating.
Likewise, the category presented as fuel oil sales for heating use is
perceived as being more closely representative of fuel oil sales to the
Residential/Commercial sector only.
55
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Table C.4-3
Residual Fuel Oil Use In the United States; 1970-1974
Ul
(MBBLS)
Average Annual
Rates of Change
Use
Residential/Commercial
Total Industrial
Industry
Oil Company Use
Electric Utility
Transportation Total
Railroads
Vessels
Other Total Use
Military
Other Misc.
Total United States
1970
185,831
177,965
139,647
38,318
312,420
92,072
2,222
89,850
35,999
28,704
7,295
804,287
Includes Navy grade and crude oil
2Data for 1974 excludes 26,683,000
1973 data excludes approximately 25
Source : U.S. Department
1971
182,062
168,847
136,221
32,626
371,820
79,989
1,262
78,727
35,326
29,217
6,109
1972
191,111
186,611
142,320
44,291
435,348
79,069
1,137
77,932
33,508
24,622
8,886
1973
192,252
202,919
152,267
50,652
509, 4572
93,629
1,214
92,415
31,920
22,892
9,028
1974
167,415
193,962
143,726
50,236
475, 2042
92,304
1,176
91,128
28,926
20,423
8,503
838,044 925,647 1,030,177 957,811
burned as fuel.
barrels of distillate fuel oil used at
,323,000 barrels of distillate fuel oil
of Interior, Bureau
of Mines,
Mineral
1970-1973
1.1
4.5
2.9
9.7
17.7
0.6
-18.2
0.9
- 3.9
- 7.3
7.4
1973-1974
-12.2
- 4.4
- 5.6
- 0.8
- 6.7
- 1.4
- 3.1
- 1.4
- 9.4
-10.8
- 5.8
8.6 - 7.0
steam-electric plants. The
used at steam-electric plant:
Industry Surveys : Sales
of Fuel Oil and
Kerosene, 1970, Table 3.
-------
Ui
Table C.4-4
Percentage Residual Fuel Oil Use In the United States; 1970-1974
Use
Res ident ial/Commercial
Total Industrial
Industry
Oil Gompany Use
Electric Utility
Transportation Total
Railroads
Vessels
Other Total Use
Military
Other Misc.
Total United States
1970
cial 23.1
22.2
17.4
4.8
38.8
:al 11.5
0.3
11.2
4.5
3.6
0.9
:S 100.0
irtment of Interior, Bureau
1971
21.7
20.2
16.3
3.9
44.4
9.6
0.2
9.4
4.2
3.5
0.7
100.0
of Mines,
1972
20.6
20.2
15.4
4.8
47.0
8.5
0.1
8.4
3.7
2.7
1.0
100.0
Mineral Industry
1973
18.7
19.7
14.8
4.9
49.5
9.1
0.1
9.0
3.1
2.2
0.9
100.0
Surveys : Sales
1974
17.5
20.2
15.0
5.2
49.6
9.6
0.1
9.5
3.0
2.1
0.9
100.0
of Fuel Oil
and Kerosene. 1970, Table 3.
-------
The quadrupling of OPEC prices initiated dramatic changes in the tradi-
tional patterns of residual fuel oil consumption in the United States;
most notably the decline in every category of end-use. The residual
fuel oil industry has been further affected by turnarounds in the supply
situation of its traditional competitor, natural gas. Curtailments of
natural gas supplies have forced users, especially electric utilities,
to secure alternative fuel sources. With an inadequate transportation
network and production capacity limiting the ability of coal producers
to absorb this new demand, the residual fuel oil suppliers have been
confronted with a potentially growing market, while trying to accommodate
their existing market in the face of reduced crude petroleum supplies.
A result of this new operating environment has been altered demand through-
out the residual fuel oil market, with every user category responding
with reduced consumption at the national level. For 1974, these reductions
ranged from less than 1 percent for Oil Company usage to over 12 percent
for Residential/Commercial. Other significant cutbacks appeared in
Military (down 11 percent) and Electric Utilities, whose usage dropped
nearly 7 percent. In terms of absolute volume, the utilities registered
the largest 1974 decline, 34.6 million barrels; this is equal to almost
half of the total decline in residual fuel oil sales. One reason for
the drop in Electric Utility usage of residual fuel oil is the decline
in demand for electricity itself in 1974 and zero growth in 1975. How-
ever, from 1973 to 1974, the Electric Utility share of total demand for
residual fuel oil remained fairly stable at 49.5 percent of the total;
the demand share attributed to the Industrial sector actually increased
to 20.2 percent in 1974, from 19.7 percent in 1973. Vessel usage, which
is predominantly composed of Bunker C sales, also rose in 1974 to a
demand share of 9.6 percent, up from 9.0 percent in 1973. This increase
in bunker demand was probably the result of domestic crude prices being
at a controlled level which was under parity with international oil
market prices. However, Bunker C demand is typically the most volatile
segment of the residual fuel oil market, so that short-term fluctuations
may not indicate a continuing trend.
58
-------
While the Bureau of Mines detail data for annual fuel oil sales were not
available for 1975 for inclusion in this report, other sources estimate
the 1975 level of residual fuel oil demand at a total of approximately
923.4 million barrels, i.e. a 3.6 percent decline from the 1974 level.
Total petroleum product demand was shown to be off only 1.3 percent.
This second consecutive year of decline in petroleum product consumption
is generally attributed to the impact of the economic recession. Industry
expectations in the fall of 1975 were for petroleum product demand to
make a significant turnaround in 1976 and, in fact, to again approach
the 1973 level of demand. Residual fuel oil was expected to experience
the highest rate of growth among the major product categories and again
top the billion barrel mark for the year. However, the economic recovery
has been somewhat slower than originally anticipated and the traditional
heating season, including IV Quarter, 1975 and I Quarter, 1976, has thus
far experienced warmer than normal temperatures. Consequently, slack
demand for residual fuel oil has appeared among the Residential/Commercial,
Industrial, and Electric Utility users. The Oil and Gas Journal, which
periodically reviews the fuel demand situation, currently envisions fuel
oil demand to be off over 4 percent for the I Quarter 1976 relative to
the comparable period a year ago. The I Quarter demand for residual
fuel oil typically accounts for approximately 27-30 percent of the year's
total; but this can be reduced when warmer than normal weather exists.
The long range outlook for residual fuel oil will be discussed separately
in a later section of the report.
Petroleum Industry Research Foundation, Inc. (FIRING), "FIRING sees
rising energy, oil demand," Oil and Gas Journal, November 24, 1975.
The Oil and Gas Journal, January 12, 1976, "No serious fuel shortages
seen in U.S. this winter".
59
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C.4.4.2 Regional Demand for Residual Fuel Oil
Residual fuel oil consumption has historically been concentrated in the
coastal regions of the United States, primarily due to considerations
of supply availability and transportation economics, vis-a-vis alternative
fuels. Another reason for the concentration of residual fuel oil
consumption along the coasts is that residual fuel oil is very difficult
to transport. As shown in Table C.4-5 PAD Districts I and V represented
80 percent of total residual fuel oil consumption in 1974. While the
East Coast has remained the single, largest regional consumer through
recent history, its share has fallen off in the last few years, dropping
from nearly three-quarters of the total in 1970 to less than two-thirds
in 1974. Although detailed sales data by PAD district were not available
from the Bureau of Mines for the entire year of 1975, data available
for the five month period running April through August indicate that this
*
share may have been even further reduced, to less than 60 percent.
From 1970-1974, the Pacific Coast share has risen slightly, from 12
percent to 15 percent. The region in the United States that has shown
the most significant increases in residual fuel oil consumption is the
Gulf Coast area, whose demand share has risen from 4 to 10 percent over
the same period. The April-August 1975 data indicate a further expansion
in this share to almost 13 percent.
As was true at the national level, abrupt regional changes have appeared
after 1973 in the consumption pattern for residual fuel oil. This was
especially true in the East Coast region where demand dropped 12 percent
in 1974, after having grown at an average rate of nearly 6 percent per
year from 1970-1973. This reflects warmer heating seasons and a major
decline in electricity demand, due to the economic slowdown. The Pacific
Coast also registered a significant decline in 1974, down 9 percent, having
grown at nearly 19 percent annually during the preceding three year period.
Department of Interior, Bureau of Mines, Mineral Industry Survey, U.S.
PAD Districts Supply/Demand, monthly, April, August, 1975; this survey
was published in April, 1975 for the first time.
60
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Table C.4-5
The United States Residual Fuel Oil Demand
by PAD District. 1970-Z4
(MBBLS)
PAD District 1970 1971
1972
1973 1974
II
III
IV
V
United States
596,834 625,857 686,554
72,586 66,261 80,084
31,688 27,617 31,757
9,195 9,347 9,622
93,984 108,962 117,630
708,412 622,214
87,088 87,689
68,206 92,371
9,456 12,452
157,015 143,085
Average Annual
Rates of Change
1970-73 1973-74
5.9% -12.2%
6.3
29.2
0.9
18.7
PAD District 1970
I 74.2%
II 9.0
III 3.9
IV 1.1
V 11.7
United States
Total
1971
74.7%
7.9
3.3
1.1
13.0
1972
74.2%
8.7
3.4
1.0
12.7
1973
68.8%
8.5
6.6
0.9
15.2
1974
65.0%
9.2
9.6
1.3
14.9
0.7
35.4
31.7
-8.9
Total 804,287 838,044 925,647 1,030.177 957,811 8.6 -7.0
Table 4.a
Percentage of Residual Fuel Oil in the United States
by PAD District. 1970-74
(MBBLS)
100.0 100.0 100.0
100.0 100.0
Source: U.S. Department of Interior, Bureau of Mines, Mineral
Industry Surveys, Sales of Fuel and Kerosene, Annual
1970-1974.
61
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By contrast, the Gulf Coast has shown dramatic increases in its residual
fuel oil consumption. This district's usage grew at an overall rate of
29 percent per year from 1970 to 1973, and grew 35 percent in 1974, which
predominantly reflects the decreased availability of natural gas supplies.
The Rocky Mountain region, although a relatively small consumer, had a
rate of demand growth above 30 percent for 1974.
It is possible to identify some of the driving forces in the changing
demand picture by reviewing the distinct usage patterns for the individual
regions. Table C.4-6 presents the actual levels of demand for the five
PAD Districts; illustrative distribution and growth calculations appear
on Tables C.4-7 and C.4-8.
Comparative analysis of regional end-usage for the years 1970 and 1974
reveals some of the apparent demand trends. (See Table C.4-7.) The
most striking variation in the usage pattern over this period is
evidenced by the continuing erosion of the East Coast's (District I)
dominant position in its demand share in all the end-use categories.
Thus by 1974, the Gulf Coast had increased its share for every category,
and, in fact, assumed the position of largest regional consumer of
residual fuel oil for transportation purposes with 43% of Transportation
demand occurring in District III. This reflects the cheaper cost of
Bunker C relative to the Caribbean, where international crude prices
(as opposed to domestically-controlled crude prices) set the market
price.
While Transportation remains the major use of residual fuel oil within
District III, its share of the district total has declined relative to
other sectors, especially Electric Utilities. The shift in Electric
Utility usage towards residual fuel oil is the result of the declining
availabilities of natural gas. At the end of 1972, 95 percent of all
generating equipment in service in the region serviced by the Southwest
Power Pool and the Electric Reliability Council of Texas was designed
62
-------
Table C.4-6
Profiles of Regional Residual Fuel Oil Demand,
by End Use Category, 1970-1974
(MMBBLS)
1970 1971 1972 1973 1974
Residential/Commercial 151.0 152.0 155.5 156.9 122.7
Industrial 109.6 107.8 111.8 116.9 107.1
Electric Utilities 271.0 301.8 354.5 369.0 343.6
Transportation 41.8 39.3 39.2 42.5 31.7
Other 23.3 25.0 25.5 23.2 17.2
District I Total 596.8 625.9 686.6 708.4 622.2
Residential/Commercial 22.7 17.6 19.8 19.1 23.2
Industrial 33.1 27.9 40.3 42.6 40.0
Electric Utilities 12.8 18.7 17.1 22.3 21.1
Transportation 2.2 1.1 1.3 1.4 2.0
Other 1.9 1.0 1.6 1.6 1.5
District II Total 72.6 66.3 80.1 87.1 87.7
Residential/Commercial 0.7 0.6 1.4 2.7 6.4
Industrial 4.6 3.7 6.6 14.1 16.9
Electric Utilities 2.7 5.5 5.2 19.9 23.1
Transportation 21.5 16.6 16.9 27.2 39.4
Other 2.1 1.2 1.7 4.3 6.6
District III Total 31.7 27.6 31.8 68.2 92.4
Residential/Commercial 1.6 1.7 1.7 1.9 3.2
Industrial 4.5 4.8 5.5 6.0 7.3
Electric Utilities 2.1 2.3 1.9 1.1 0.9
Trarisporation 0.6 0.3 0.3 0.3 0.3
Other 0.4 0.2 0.2 0.2 0.6
District IV Total 9.2 9.3 9.6 9.5 12.5
Residential/Commercial 9.8 10.2 12.7 11.7 11.8
Industrial 26.2 24.7 22.5 23.3 22.8
Electric Utilities 23.8 43.5 56.7 97.2 86.6
Transportation 25.9 22.7 21.4 22.2 18.9
Other 8.4 7.9 4.5 2.6 3.0
District V Total 94.0 109.0 117.6 157.0 143.1
Note: Columns may not sum to totals due to rounding.
Source: U.S. Department of Interior, Bureau of Mines, Mineral Industry
Surveys: Sales of Fuel Oil and Kerosene, Annual, 1970-1974.
63
-------
Table C.4-7
Residual Fuel Oil Demand by
End-Use Category by District, 1970 and 1974
1970
End-Use Category
Residential/Commercial
Industrial
Electric Utilities
Transportation
Other
Total Residual Fuel
Oil
81.2%
61.6
86.
45
7
,4
64.7
74.2
PAD Districts
,2
.6
II
12.
18.
4.1
2.4
5.3
9.0
III
0.4
2.6
0.9
23.3
5.8
IV
0.9
2.5
0.7
0.7
1.1
V
5.3
14.7
7.6
28.1
23.3
3.9 1.1 11.7
U.S. Total
100.0
100.0
100.0
100.0
100.0
100.0
1974
End-Use Category
Residential/Commercial
Industrial
Electric Utilities
Transportation
Other
73.3
55.2
72.3
34.3
59.5
PAD Districts
II
13.9
20.6
4.4
2.2
5.2
III
3.8
8.7
4.9
42.7
22.8
IV
1.9
3.8
0.2
0.3
2.1
7.0
11,
18.
20.
10.4
U.S. Total
100.0
100.0
100.0
100.0
100.0
Total Residual Fuel
Oil 65.0 9.2
9.6 1.3 14.9
100.0
Note: Columns may not sum to 100.0 due to rounding.
Source: U.S. Department of Interior, Bureau of Mines, Mineral Industry
Surveys: Sales of Fuel Oil and Kerosene, Annual, 1970, 1974,
reflects data shown in Tables I.B-4. and i.B-5.
64
-------
Table C.4-8
Growth Profile of Regional Fuel Oil Demand by End-Use Category. 1970-1974
Average Annual Rates
of Growth
Percentage distribution by end use in Demand
Residential /Commercial
Industrial
Electric Utilities
Transportation
Other
District I Total
Residential/Commercial
Industrial
Electric Utilities
Transportation
Other
District II Total
Residential/Commercial
Industrial
Electric Utilities
Transportation
Other
District III Total
Residential/Commercial
Industrial
Electric Utilities
Transportation
Other
District IV Total
Residential/Commercial
Industrial
Electric Utilities
Transportation
Other
District V Total
1970
25.3
18.4
45.4
7.0
3.9
100.0
31.3
45.6
17.6
3.0
2.6
100.0
2.2
14.5
8.5
67.8
6.6
100.0
17.4
48.9
22.8
6.5
4.3
100.0
10.4
27.9
25.3
27.6
8.9
100.0
1971
24.
17.
48.
6.
4.
100.
26.
42.
28.
1.
1.
100.
2.
13.
19.
60.
4.
100.
18.
51.
24.
3.
2.
100.
9.
22.
39.
20.
7.
100.
3
2
2
3
0
0
6
1
2
7
5
0
2
4
9
1
3
0
3
6
7
2
2
0
4
7
9
8
2
0
1972
22.
16.
51.
5.
3.
100.
24.
50.
21.
1.
2.
100.
4.
20.
16.
53.
5.
100.
17.
57.
19.
3.
2.
100.
10.
19.
48.
18.
3.
100.
6
3
6
7
7
0
7
3
3
6
0
0
4
8
3
1
3
0
7
3
8
1
1
0
8
1
2
2
8
0
1973
22.1
16.5
52.1
6.0
3.3
100.0
21.9
48.9
25.6
1.6
1.8
100.0
4.0
20.7
29.2
39.9
6.3
100.0
20.0
63.2
11.6
3.2
2.1
100.0
7.5
14.8
61.9
14.1
1.7
100.0
1974
19.7 ,
17.2
55.2
5.1
2.8
100.0
26.5
45.6
24.1
2.3
1.7
100.0
6.9
18.3
25.0
42.6
7.1
100.0
26.0
59.3
7.3
2.4
4.9
100.0
8.2
15.9
60.5
13.2
2.1
100.0
1970-73
1.
2.
10.
0.
- 0.
5.
- 5.
8.
20.
-14.
- 5.
6.
57.
45.
95.
8.
27.
29.
5.
10.
-19.
-21.
-21.
0.
6.
- 3.
60.
- 5.
-32.
18.
3
2
8
6
1
9
6
8
3
0
6
3
0
0
0
2
0
2
9
1
4
0
0
9
1
8
0
0
0
7
1973-74
-21.
- 8.
- 6.
-25.
-25.
-12.
21.
- 6.
- 5.
42.
- 6.
0.
137.
19.
16.
44.
53.
35.
68.
21.
-19.
0.
200.
31.
0.
- 2.
-10.
-14.
15.
- 8.
8
4
7
4
9
2
5
1
4
9
2
7
0
9
1
9
5
4
4
7
2
0
0
7
9
1
9
9
4
9
Note: Percentage columns may not sum to 100.0 due to rounding.
Source: U.S. Department of Interior, Bureau of Mines, Mineral Industry
Surveys: Sales of Fuel Oil and Kerosene, Annual, 1970-1974.
65
-------
strictly for continuous operation on natural gas. In response to
increasingly heavy curtailments of gas supply for power plant use, these
electric utility groups lessened their natural gas dependency primarily
by shifting to oil. Hence, use of residual fuel oil by utilities
in District III expanded at an average annual rate of approximately 95
percent over the three year period 1970-1973. (See Table C.4-8.) Since
the oil embargo, the area has tried to limit further dependence on oil;
this is reflected in the 1973-1974 rate of change, which moderated
substantially to 16 percent, vis-a-vis more than tripling in 1972-1973.
Another distinguishing feature of the Gulf Coast's usage of residual fuel
oil is that it was the only district not to register a decline in at
least one of its major consumption categories, again because natural gas
supplies were being curtailed. In direct contrast, the East Coast showed
significant declines in residual fuel oil usage in every category in 1974,
as compared with 1973, again reflecting the warmer heating season, the
economic slowdown, and conservation measures.
In all Districts except District IV (Rocky Mountain), Electric Utilities
usage showed the highest rate of growth from 1970-1973 of any of the
end-use categories. In the Rocky Mountain region, Industrial use
captured that rank. Interestingly, Industrial Users in the Rocky
Mountain region expanded their demand for residual fuel oil faster than
comparable users in other districts, due to the acute natural gas supply
situation in that area of the country.
C.4.4.3 State Detail on Demand for Residual Fuel Oil by End-Use Category
Detailed data on the level of residual fuel oil demand at the state and
district level for the years 1970-1974 are presented in Tables C.4-9
through C.4-14. State information is provided for each of the end-use
categories in the following order:
66
-------
C.4-9 Total Demand, all end-use categories
C.4-10 Residential/Commercial Demand
C.4-11 Industrial Demand
C.4-12 Electric Utilities Demand
C.4-13 Transportation Demand
C.4-14 Other Demand
As shown in Table C.4-9, there were only two states which consumed in
excess of 100 million barrels of residual fuel oil in 1974; they were New
York (in District I), with 153 million barrels, and California (District
V), with 106 million barrels. Together, these two states represented
27 percent of the total U.S. demand in that year, although they have
only 19 percent of the U.S. population.
If New England is regarded as one "state", it, too, would have a 1974
level of demand which surpassed the 100 million barrels mark (134 million
barrels). This would push the combined demand of large consumer-states
to approximately 40 percent of the national total. By comparison, total
district demand for Districts II, III, and IV were all less than 100 million
barrels and these districts represent 26 of the 50 states.
There were three states consuming between 50-100 million barrels of
residual fuel oil in 1974. They were Florida (75 million barrels), New
Jersey (64 million barrels), and Pennsylvania (56 million barrels); all
three states are in District I. All together, the six "states" mentioned
account for approximately 60 percent of the U.S. total demand. A summary
of the demand breakdown for these states is presented in Table C-4-9.
By individual, end-use categories, other states qualify as the leading
users. This is especially evident in Transportation, in which Texas
and Louisiana represent over one-third of the national total; virtually
all of these states' transportation demand for residual fuel oil is
for tanker traffic using Bunker C.
67
-------
Table C.4-9
Total Sales of Residual Type Fuel Oils in the United States
(MBBLS)
1970
1971
1972
1973
1974
1975
oo
District I
New England
Connecticut
Maine
Mas s achuse 11 s
New Hampshire
Rhode Island
Vermont
Subtotal New England
Delaware
Washington, B.C.
Florida
Georgia
Maryland
New Jersey
New York
North Carolina
Pennsylvania
South Carolina
Virginia
W. Virginia
District I Total
Total U.S.
36,057
11,693
86,063
5,514
9,739
903
149,969
6,581
11,148
55,169
10,255
22,446
80,840
152,487
6,922
60,389
5,328
33,236
2,064
596,834
804,287
34,564
18,331
82,917
6,016
10,036
898
152,762
6,194
10,748
62,414
10,488
30,059
75,213
159,069
10,433
59,973
5,493
40,565
1,906
625,857
838,044
40,706
21,365
87,930
5,961
9,811
954
166,727
9,640
10,656
76,325
12,960
38,273
80,761
164,123
15,926
58,490
6,395
44,530
1,748
686,554
925,647
43,180
19,860
86,282
5,382
8,376
876
163,956
13,117
11,200
82,873
13,888
42,534
79,204
169,669
15,393
59,371
9,636
46,123
1,448
708,412
1,030,177
38,223
15,272
69,385
4,786
6,216
535
134,417
12,632
7,03-7
75,440
12,954
38,910
63,917
152,627
13,819
56,101
9,577
43,074
1,709
622,214
957,811
14.0%
-------
Table C.4-9 - Total Sales of Residual Type Fuel Oils in the United States (MBBLS) (Cont'd)
1970 1971 1972 1973 1974 1975
District II
Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin
District II Total
Total U.S.
District III
Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas
District III Total 31,688 27,617 31,757 68,206 92,371
28,618
9,757
408
1,247
1,061
10,059
5,150
3,615
798
726
6,532
744
348
596
2,927
72,586
3,283
1,584
11,270
896
215
14,440
23,708
12,194
411
827
674
11,605
4,075
2,904
597
645
5,259
637
227
365
2,133
66,261
838,044
2,601
2,887
8,384
1,074
466
12,205
29,581
14,326
325
1,974
1,159
11,388
6,943
2,552
706
781
5,840
1,355
335
523
2,296
80,084
925,647
3,170
3,183
8,667
2,365
621
13,751
28,795
15,536
679
2,847
1,094
14,560
7,069
2,959
639
898
6,866
1,629
234
650
2,633
87,088
1,030,177
6,151
10,720
16,952
3,955
1,220
29,208
28,532
16,078
628
2,660
2,084
14,876
5,883
2,375
1,045
1,190
8,330
1,201
137
883
1,787
87,689
957,811
10,496
10,369
24,478
7,436
1,714
37,878
-------
Table. C.4-9 -Total Sales of Residual Type Fuel Oils in the United States (MBBLS) (Cont'd)
1970
1971
1972
1973
1974
1975
District IV
Colorado
Idaho
Montana
Utah
Wyoming
District IV Total
District V
Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington
1,531
276
1,249
4,657
1,482
9,195
1,034
94
65,503
10,162
144
6,679
10,368
1,572
276
1,236
5,030
1,233
9,347
1,043
723
80,467
10,631
272
6,538
9,288
1,984
246
1,485
4,538
1,369
9,622
1,166
1,139
83,978
11,316
242
7,977
11,812
2,317
243
1,705
3,649
1,542
9,456
1,051
4,288
121,059
11,580
612
7,439
10,986
3,179
597
2,290
4,295
2,091
12,452
1,098
6,943
105,814
11,495
690
6,650
10,395
District V Total
Total U.S.
93,984 108,962
804,287 838,044
117,630 157,015 143,085
925,647 1,030,177 957,811
Source: U.S. Department of Interior, Bureau of Mines, Annual Fuel Oil Sales.
-------
Table C.4-10
Use of Residual Type Fuel Oils in the United States for Residential/Commercial
Purposes for PAD District I
by State, 1970-1975
(MBBLS)
State
New England
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Subtotal N>iw
England
Delaware
District of Columbia
Florida
Georgia
Maryland
New Jersey
New York
North Carolina
Pennsylvania
South Carolina
Virginia
West Virginia
District Total
1970
47
675
8,104
422
830
67
10,145
258
751
197
1,079
1,474
1,984
1,483
696
6,552
132
349
507
25,537
1971
56
894
7,684
456
1,067
36
10,193
212
661
53
1,144
1,710
2,262
1,824
931
6,554
119
461
577
26,701
No. 5
1972
61
867
8,086
510
1,203
30
10,757
244
518
31
890
1,742
2,592
1,384
1,020
7,216
152
457
488
27,491
1973
68
794
7,921
488
1,200
30
10,501
285
559
20
875
1,936
2,480
1,300
1,302
7,471
245
480
285
27,739
1974
50
423
5,293
249
520
20
6,555
85
317
70
417
1,120
1,325
625
928
5,145
227
286
118
17,218
1975 1970
4,710
2,221
22,562
659
1,473
329
31,954
260
7,516
1,539
807
3,812
12,233
58,274
618
6,998
122
1,301
54
125 ,508
1971
4,606
3,055
21,655
1,027
2,085
395
32,823
252
6,858
1,631
1,614
3,774
11,377
57,291
880
7,626
20
1,039
65
125,250
No.
1972
4,916
3,151
22,694
1,613
2,221
504
35,099
252
5,190
2,696
1,687
3,777
11,301
57,768
809
8,068
55
1,282
71
128,055
6
1973
5,431
3,026
22,491
1,413
2,224
432
35,017
781
4,618
2,725
1,617
3,942
11,477
58,110
895
8,336
55
1,421
122
129,116
Total
1974
4,379
2,220
18,577
943
1,715
274
28,108
414
2,350
2,124
1,522
3,082
9,528
49,055
819
7,420
53
965
58
105,498
1975 1970
4,757
2,896
30,666
1,081
2,303
396
42,099
518
8,287
1,666
1,886
5,286
14,217
59,757
1,314
13,550
254
1,650
561
151,045
1971
4,662
3,949
29,339
1,483
3,152
431
43,016
464
7,519
1,684
2,758
5,484
13,639
59,115
1,811
14,180
139
1.500
642
151,951
1972
4,977
4,018
30,780
2,123
3,424
534
45,856
496
5,708
2,727
2,577
5,519
13,893
59,152
1,829
15,284
207
1,739
559
155,546
1973
5,499
3,820
30,412
1,901
3,424
462
45,518
1,066
5,177
2,745
2,492
5,878
13,957
59,410
2,197
15,807
300
1,901
407
156,855
1974
4,429
2 643
23,870
1 192
2,235
294
34,663
490
2,667
2,194
1,939
4,202
10,853
49,680
1,747
12,565
280
1,251
1 7fi
122,716
Total U.S.
42,837 39,181 41,108 41,120 32,922
142,994 142,881 150,003 151,132 134,493
185,831 182,062 191,111 192,252 167,415
-------
Table C.4-10 (Cont'd)
ro
State
Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin
1970
7,431
532
94
104
7
284
668
1,032
77
33
107
33
10
5
635
1971
3,359
384
101
86
—
264
394
763
63
40
111
66
2
—
417
No.
1972
4,163
592
82
23
—
356
410
740
99
93
117
32
4
16
313
5
1973
3,906
468
77
94
—
473
390
588
72
116
114
50
3
20
243
1974 1975
4,120
553
51
47
—
576
369
562
95
381
316
9
2
95
303
Use of Residual Type Fuel Oils in the United States for Residential/Commercial
Purposes for PAD District II by State. 1970-1975
(MBBLS)
No. 6
District Total 11,052 6,056 7,040 6,614 7,479
U.S. Total 42,837 39,181 41,108 41,120 32,922
1970
6,915
1,785
66
127
109
718
325
727
53
36
383
32
5
10
330
1971
5,598
3,923
81
65
128
352
221
531
51
18
207
72
—
2
273
1972
6,045
3,379
42
36
152
691
411
422
106
130
713
54
—
270
288
1973
5,642
3,186
226
38
211
717
399
508
170
187
580
55
182
380
1974 1975
6,472
4,343
394
34
315
904
434
577
138
356
915
59
__
395
385
11,621 11,522 12,739 12,481 15,721
142,994 142,881 150,003 151,132 134,493
Total
1970
14,346
2,317
160
231
116
1,002
993
1,759
130
69
490
65
15
15
965
1971
8,957
4,307
182
151
128
616
615
1,294
114
58
318
138
2
2
690
1972
10,208
3,971
124
59
152
1,047
821
1,162
205
223
830
86
4
286
601
1973
9,548
3,654
303
132
211
1,190
789
1,096
242
303
694
105
3
202
623
1974 1975
10,592
4,896
445
81
315
1,480
803
1,139
233
737
1,231
68
2
490
688
22,673 17,572 19,779 19,095 23,200
185,831 182,062 191,111 192,252 167,415
-------
Table C.4-10 (Cont'd)
Use of Residual Type Fuel Oils in the United States for Residential/Commercial
Purposes for PAD Districts
ulstrlct/
State 1970
District III
Alabama 78
Arkansas -
Louisiana 5
Mississippi 5
New Mexico 2
Texas 17
District Total 107
District IV
Colorado 129
Idaho 57
Montana 163
Utah 306
Wyoming 177
District Total 832
District V
Alaska 5
Arizona 7
California 939
Hawaii 114
Nevada 23
Oregon 1,971
Washington 2,250
Dist. Total 5,309
Total U.S. 42,837
1971
78
-
1
-
1
22
102
101
52
158
393
147
851
_
2
704
81
52
2,365 2
2,273 2
5,477 5
39,181 41
Note: Residential/Commercial
No.
1972
201
18
2
-
-
25
246
54
58
163
339
87
701
_
-
417
113
72
,605 2
,423 2
,630 5
,108 41
includes
5
1973
524
67
4
-
7
63
665
56
53
161
315
88
673
_
-
596
65
66
,586
,116
,429
,120
No. 5
Ill, IV,
and V,
by State,
1970-1975
(MBBLS)
No. 6
1974 1975
1,093
285
22
-
45
386
: 1,831
193
216
244
389
147
1,189
_
-
683 1
33
50
2,385 1
2,054 1
5,205 4
32,922 142
and 6 heating oils
1970 1971
— _
-
11
44 44
1 1
537 485
593 530
212 207
61 100
20 19
362 386
163 181
818 893
30 22
7 3
,444 1,478
141 100
17 21
,336 1,564
,479 1,498
,454 4,686
,994 142,881
1972
123
254
8
100
21
647
1,153
480
110
46
186
214
1,036
20
-
3,064
10
17
1,908
2,001
7,020
150,003
1973
449
400
11
66
60
1,091
2,077
555
112
47
242
230
1,186
13
-
3,573
19
15
1,220
1,432
6,272
151,132
1974
956
878
75
223
184
2,264
4,580
798
266
132
498
380
2,054
11
-
4,312
. 158
28
1,153
978
6,640
134,493
1975 1970
78
-
16
49
3
554
700
341
118
183
668
340
1,650
35
14
2,383
255
40
3,307
3,729
9,763
185,831
1971
78
-
1
44
2
507
632
308
152
177
779
328
1,744
22
5
2,182
181
73
3,929
3,771
10,163
182,062
Total
1972
324
272
10
100
21
672
1,399
534
168
209
525
301
1,737
20
-
3,481
123
89
4,513
4,424
12,650
191,111
1973
973
467
15
66
67
1,154
2,742
611
165
208
557
318
1,859
13
-
4,169
84
81
3,806
3,548
11,701
192,252
1974 1975
2,049
1,163
97
223
229
2,650
6,411
991
482
376
867
527
3,243
11
-
4,995
191
78
3,538
3,032
11,845
167,415
; data reflect sales.
-------
Table C.4-11
Use of Residual Type Fuel Oils In the United States for Industrial Purposes.
for PAD District I. by State. 1970-1975
(MBBLS)
General Industry
State
New England:
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Sub Total
New England
Delaware
District of Columbia
Florida
Georgia
Maryland
New Jersey
New York
North Carolina
Pennsylvania
South Carolina
Virginia
W. Virginia
District Total
U.S. Total
1970
9,800
2,494
9,689
1,823
1,727
480
26,013
3,358
60
6,620
6,619
2,111
12,951
16,516
4,221
13,239
1,152
2,015
1,055
95,930
139,647
1971
7,109
7,970
7,659
1,896
1,337
446
26,417
3,312
75
6,157
5,445
6,832
9,252
9,619
6,766
12,048
2,778
4,948
800
94,449
136,221
1972
7,036
8,237
7,249
1,580
1,398
397
25,897
3,371
119
7,248
6,449
6,981
9,015
9,212
9,534
10,818
3,486
6,659
495
99,284
142,320
1973
7,103
7,519
7,901
1,449
1,220
403
25,595
3,442
63
8,218
7,114
7,063
9,441
9,481
7,288
11,920
3,746
7,933
323
101,627
152,267
1974 1975
6,100
6,964
6,887
1,301
1,212
233
22,697
2,289
47
7,479
6,590
4,896
8,746
8,551
6,997
11,614
3,093
8,012
304
91,315
143,726
Oil Companies, exc. Actual Refining
Total Industrial
1970
81
17
109
1
68
1
277
72
7
305
1
491
6,654
112
58
5,340
118
258
10
1971
83
12
90
—
48
—
233
59
48
523
—
427
5,987
178
46
5,287
112
420
2
1972
87
64
62
2
49
1
265
31
7
223
89
191
4,795
526
41
6,023
101
139
50
1973
176
36
115
2
29
2
360
229
7
338
152
497
5,759
697
66
6,698
186
201
62
1974 1975
147
21
111
3
39
2
323
129
9
191
54
204
5,564
972
42
7,896
135
161
60
13,703 13,322 12,481 15,252 15,740
38,318 32,626 44,291 50,652 50,236
1970
9,881
2,511
9,798
1,824
1,795
481
26,290
3,430
67
6,925
6,620
2,602
19,605
16,628
4,279
18,579
1,270
2,273
1,065
1971
7,192
7,982
7,749
1,896
1,385
446
26,650
3,371
123
6,680
5,445
7,259
15,239
9,797
6,812
17,335
2,890
5,368
802
1972
7,123
8,301
7,311
1,582
1,447
398
26,162
3,402
126
7,471
6,538
7,172
13,810
9,738
9,575
16,841
3,587
6,798
545
1973
7,279
7,555
8,016
1,451
1,249
405
25,955
3,671
70
8,556
7,266
7,560
15,200
10,178
7,354
18,618
3,932
8,134
385
1974
6,247
6,985
6,998
1,304
1,251
235
23,020
2,418
56
7,670
6,644
5,100
14,310
9,523
7,039
19,510
3,228
8,173
364
109,633 107,771 111,765 116,879 107,055
177,965 168,847 186,611 202,919 193,962
-------
Table C.4-11 (Cont'd)
Use of Residual Type Fuel Oils In the United States for Industrial Purposes.
for PAD District IT, by State. 1970-1975
(MBBLS)
General Industry
1970
5,907
2,213
60
460
595
3,097
2,327
1,156
199
74
3,111
335
31
571
667
1971
4,083
3,714
57
300
200
2,657
2,041
990
171
38
2,767
289
23
354
587
1972
4,007
4,184
123
533
50
3,232
4,365
505
79
10
1,758
703
67
233
765
1973
4,455
5,310
125
499
59
2,604
3,894
511
42
10
2,256
953
53
264
655
1974 1975
4,178
4,781
137
380
539
2,166
3,242
471
96
14
2,324
758
47
300
562
State •
Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin
District II Total 20,803 18,271 20,614 21,690 19,995
U.S. Total 139,647 136,221 142,320 152,267 143,726
Oil Companies, exc. Actual Refining
1970
3,400
4,625
28
50
911
909
298
12
487
1,240
186
—
1
116
1971
2,948
3,440
25
25
620
709
267"
20
303
1,041
82
7
—
154
1972
7,547
5,549
940
620
628
869
410
63
518
2,083
219
18
—
246
1973
7,604
5,812
992
700
657
988
715
55
579
2,148
321
15
45
319
1974 1975
7,396
5,894
906
1,040
703
720
516
50
421
1,825
206
13
19
269
12,263 9,641 19,710 20,950 19,978
38,318 32,626, 44,291 50,652, 50,236
Total Industrial
1970
9,307
6,838
60
488
645
4,008
3,236
1,454
211
561
4,351
521
31
572
783
1971
7,031
7,154
57
325
225
3,277
2,750
1,257
191
341
3,808
371
30
354
741
1972
11,554
9,733
123
1,473
670
3,860
5,234
915
142
528
3,841
922
85
233
1,011
1973
12,059
11,122
125
1,491
759
3,261
4,882
1,226
97
589
4,404
1,274
68
309
974
1974 1975
11,574
10,675
137
1,286
1,579
2,869
3,962
987
146
435
4,149
964
60
319
831
33,066 27,912 40,324 42,640 39,973
177,965 168,847 186,611 202,919 193,962
-------
Table C.4-11 (Cont'd)
Use of Residual Type Fuel Oils in the United States for Industrial Purposes
Dis t r ic t /S t3t£
District III
Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas
District III Total
District IV
Colorado
Idaho
Montana
Utah
Wyoming
District IV Total
District V
Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington
District V 1'otal
for PAD Districts
General Industry
1970
1,410
165
960
22
2
507
3,066
656
116
109
1,870
252
3,003
770
36
10,613
530
17
1,826
3,053
16,845
1971
970
163
930
11
2
401
2,477
774
116
225
2,007
257
3,379
762
72
11,724
466
17
1,662
2,942
17,645
1972
1,033
576
1,005
270
163
1,785
4,832
730
70
227
1,953
130
3,110
842
69
6,028
551
74
2,793
4,123
14,480
1973
2,014
1,445
2,045
719
472
3,280
9,975
742
66
243
1,974
301
3,326
640
240
6,466
595
40
3,060
4,608
15,649
1974 1975
2,109
2,262
2,775
950
575
4,750
13,421
878
91
465
2,336
288
4,058
679
287
6,296
305
34
2,581
4,755
14,937
III, IV,
and V,
by State, 1970-1975
(MBBLS)
Oil Companies, exc. Actual Refining
1970
21
17
105
195
10
1,184
1,532
54
—
792
265
371
1,482
17
—
6,925
776
—
292
1,328
9,338
1971
21
17
210
53
15
947
1,263
81
—
732
276
304
1,393
15
—
4,640
737
—
274
1,341
7,007
1972
151
184
159
597
13
620
1,724
120
—
967
738
573
2,398
3
2
5,364
744
—
283
1,582
7,978
1973
200
442
326
685
50
2,452
4,155
180
—
1,112
737
639
2,668
2
1
5,495
563
—
189
1,377
7,627
1974 1975
203
223
639
322
113
1,955
3,455
252
—
1,307
799
871
3,229
21
4
5,810
639
—
185
1,175
7,834
1970
1,431
182
1,065
217
12
1,691
4,598
710
116
901
2,135
623
4,485
787
36
17,538
1.306
17
2,118
4,381
26.183
Total Industrial
1971
991
'180
1,140
64
17
1,348
3,740
855
116
957
2,283
561
4,772
777
72
16,364
1,203
17
1,936
4,283
24,652
1972
1,184
760
1,164
867
176
2,405
6,556
850
70
1,194
2,691
703
5,508
845
71
11,392
1,295
74
3,076
5,705
22,458
1973
2,214
1,887
2,371
1,404
522
5,732
14,130
922
66
1,355
2,711
940
5,994
642
241
11,961
1,158
40
3,249
5,985
23.276
1974 1975
2,312
2,485
3,414
1,272
688
6,705
16,876
1,130
91
1,772
3,135
1,159
7,287
700
291
12.106
944
34
2,766
5,930
22,771
U.S. Total
139,647 136,221 142,320 152,267 143,726
38,318 32,626 44,291 50,652 50,236
177,959 168,847 186,611 202,919 193.962
Note: Data reflect sales.
Source: U.S. Department of Interior, Bureau of Mines, Annual Fuel Oil Sales.
-------
Table C.4-12
Sales of Residual Type Fuel Oils in the United States for Electric Utility Company Use.
in PAD Districts I and II. by State. 1970-1975
(MBBLS)
District/State
District I
Mew England:
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Subtotal New England
Delaware
District of Columbia
Florida
Georgia
Maryland
New Jersey
New York
North Carolina--
Pennsylvania
South Carolina
Virginia
W. Virginia
District 1 Total
1970
21
4
42
2
3
73
1
2
43
1
10
37
57
22
2
16
271
,025
,872
,327
,538
,017
23
,802
,541
,776
,335
,536
,371
,826
,224
603
,535
,041
,982
432
,004
1971
22
4
42
2
2
74
1
3
51
2
13
36
72
1
22
21
301
,221
,764
,387
,601
,598
18
,589
,612
,097
,606
,120
,768
,593
,075
,311
,046
921
,632
461
,831
1972
27
5
46
2
2
84
4
4
64
3
22
41
79
4
20
1
24
354
,963
,542
,284
,215
,655
17
,676
,162
,673
,050
,572
,038
,193
,855
,048
,055
,385
,171
643
,521
1973
29
4
44
2
2
83
5
5
68
3
25
40
82
5
17
4
26
368
,380
,900
,751
,009
,375
4
,419
,915
,438
,755
,489
,260
,090
,605
,497
,504
,126
,284
584
,971
1974
26
3
36
2
1
71
7
3
63
3
25
32
81
4
17
5
25
1
343
,782
,982
,929
,262
,886
1
,842
,611
,509
,070
,715
,888
,488
,094
,785
,137
,342
,960
.136
,577
1975
1970
1971
1972
District II
Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin
3,942
212
57
506
121
4,528
843
185
194
25
796
3
291
—
1,127
7,014
453
119
331
271
7,594
678
302
105
213
733
55
191
—
655
7,139
397
78
304
333
5,862
751
341
155
26
825
25
246
—
610
6,513
566
251
1,098
121
9,347
975
492
118
2
1,529
193
163
—
960
5,692
82
46
1,222
188
9,796
622
79
483
16
2,446
142
75
—
181
District II Total 12,830 18,714 17,092 22,328 21,070
Total U.S.
371,820 435,348 509,457 475,204
1975
Total U.S.
312,420 371,820 435,348 509,457 475,204
-------
Table C.4-12 (Cont'd)
Sales of Residual Type Fuel Oils in the United States for Electrical Utility Company Use,
In PAP Districts III. IV and V. by State. 1970-1975
•vl
oo
IMBBLS)
District/State
District III
Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas
District III Total
District IV
Colorado
Idaho
Montana
Utah
Wyoming
District IV Total
District V
Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington
District V Total
Total U.S.
Note: Data are based on Federal
1970
—
1,347
273
609
81
428
2,738
269
—
9
1,775
9
2,062
21
8
16,871
6,717
81
79
9
23,786
312,420
1971
—
2,652
905
934
386
611
5,488
284
—
—
1,890
82
2,256
4
599
35,218
7,434
181
94
.1
43,531
371,820
Power Commission
1972
—
2,081
959
1,244
396
506
5,186
484
—
16
1,272
111
1,883
2
936
47,340
8,236
75
17
60
56,666
435,348
1973
—
8,229
3,694
2,054
389
5,508
19,874
646
—
71
327
72
1,116
6
3,903
84,183
8,523
485
14
54
97,168
509,457
1974
—
6,521
5,449
5,200
373
5,527
23,070
629
__
3
126
169
927
3
6,515
70,613
8,790
571
—
68
86,560
475,204
Statistics.
1975
Data for 1972 exclude approximately 13,000,000 barrels of distillate
fuel oil used at steam-electric plants; data for this fuel use, formerly
included as a residual fuel oil sale have been reclassifled as a distillate
fuel oil sale since 1972.
Source: U.S. Dept. of Interior, Bureau of Mines, Annual Fuel Oil Sales.
-------
Table C.4-13
Use of Residual Type Fuel Oils in the United States for Transportation Purposes
for PAD District I by State 1970-1975
Railroad
State
New England:
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Subtotal
New England
Delaware
District of
Columbia
Florida
Georgia
Maryland
New Jersey
New York
North Carolina
Pennsylvania
South Carolina
Virginia
W. Virginia
District I Total
Total U.S.
1970
10
26
10
-
23
—
69
26
1
9
8
1
2
67
7
113
10
7
5
325
2,222
1971
7
26
5
-
25
—
63
26
-
4
-
1
3
76
7
82
2
6
—
270
1,262
1972
_
-
-
-
13
—
13
34
2
-
-
2
1
98
5
57
2
7
—
221
1,137
1973
_
26
2
-
3
—
31
28
4
-
-
5
1
45
2
40
1
11
—
168
1,214
1974 1975
_
29
2
-
2
-
33
27
2
-
-
2
1
16
1
42
2
8
— . •
134
1,176
(MBBLS)
Vessel Bunkering
1970 1971 1972 1973 1974 1975
102 102 191 714 592
1,357 1,536 3,399 3,459 1,557
1,733 1,404 1,262 1,483 795
2 - - - 11
194 142 113 102 47
-----
3,388 3,184 4,965 5,758 3,002
53fr 327 793 801 1,087
2 - - 32 113
2,067 1,291 1,521 2,458 2,223
148 121 83 396 559
3,517 2,638 2,642 2,988 3,013
6,051 6,627 8,603 6,789 4,044
16,632 16,796 13,687 14,999 10,676
201 76 78 143 114
4,015 3,694 3,119 3,602 3,521
1,386 1,275 1,009 1,028 540
3,581 3,044 2,496 3,344 2,643
- - - - -
41,524 39,073 38,996 42,338 31,535
89,850 78,727 77,932 92,415 91,128
Total Transportation
1970
112
1,383
1,743
2
217
-
3,457
562
3
2,076
156
3,518
6,053
16,699
208
4,128
1,396
3,588
5
41,849
92,072
1971
109
1,562
1,409
-
167
-
3,247
353
_
1,295
121
2,639
6,630
16,872
83
3,776
1,277
3,050
-
39,343
79,989
1972
191
3,399
1,262
-
126
-
4,978
827
2
1,521
83
2,644
8,604
13,785
83
3,176
1,011
2,503
-
39,217
79,069
1973
714
3,485
1,485
-
105
-
5,789
829
36
2,458
396
2,993
6,790
15,044
145
3,642
1,029
3,355
-
42,506
93,629
1974 1975
592
1,586
797
11
49
-
3,035
1,114
115
2,223
559
3,015
4,045
10,692
115
3,563
542
2,651
—
31,669
92,304
-------
Table C.4-13 (Cont'd)
Use of Residual Type Fuel Oils in the United States for Transportation Purposes
for PAD District II by State 1970-1975
(MBBLS)
00
O
Railroad
1970
177
104
26
2
144
70
18
10
223
41
292
59
6
3
2
1971
59
52
6
13
48
43
2
10
171
18
105
30
4
1
6
1972
117
—
—
26
—
88
7
4
180
—
—
—
—
—
51
1973
122
—
—
41
—
30
8
5
166
—
—
—
—
1
50
1974 1975
129
—
—
29
—
133
9
6
173
—
—
—
—
3
24
Vessel Bunkering
State
Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin
District II Total 1,117 568 473 523 506
U.S. Total 2,222 1,262 1,137 1,214 1,176
1970
84
192
—
1
352
1
—
1971
123
165
_ _
1
33
—
—
1972
92
166
_ _
4
189
110
20
1973
83
103
_ _
3
211
401
19
1974
96
261
12
2
242
487
13
1975
Total Transportation
414
187
196
89
318
3 3 3 11 56
1,047 512 780 920 1,487
89,850 78,727 77,932 92,415 91,128
1970
261
296
26
2
145
422
19
10
223
41
706
59
6
3
5
1971
182
217
6
13
49
76
2
10
171
18
292
30
4
1
9
1972
209
166
—
26
4
277
117
24
180
—
196
—
—
—
54
1973
205
103
—
41
3
341
409
24
166
—
89
—
—
1
61
1974 1975
225
261
—
41
2
375
496
19
173
—
318
—
—
3
80
2,164 1,080 1,253 1,443 1,993
92,072 79,989 79,069 93,629 92,304
-------
oo
Table C.4-13 (Cont'd)
Use of Residual Type Fuel Oils in the United States for Transportation Purposes
for PAD Districts III,
IV, and V, by
State,
1970-1975
(MBBLS)
District/State
District III
Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas
District III Total
District IV
Colorado
Idaho
Montana
Utah
Wyoming
District IV Total
District V
Alaska
Arkansas
California
Hawaii
Nevada
Oregon
Washington
District V Total
Railroad
1970
__
2
5
—
11
21
39
99
2
74
4
468
647
8
—
30
—
—
33
23
94
1971
__
—
—
—
7
10
17
50
—
40
10
234
334
5
—
25
—
—
22
21
73
1972
__
—
—
. —
—
14
14
22
—
32
20
244
318
6
—
57
8
-—
29
11
111
1973
__
5
—
—
—
150
155
20
—
28
24
200
272
7
—
54
6
— —
23
6
96
1974
„
7
—
—
—
103
110
42
—
44
37
223
346
6
—
48
2
—
21
3
80
1975 1970
1,538
2
8,678
3
—
11,267
21,488
—
—
—
—
—
124
—
21,611
1,738
—
868
1,450
25,791
Vessel Bunkering
1971
1,369
— .
5,687
—
—
9,478
16,534
—
—
—
—
—
—
220
—
19,708
1,755
—
229
696
22,608
1972
1,454
—
5,746
154
—
9,559
16,913
—
—
—
—
—
226
—
18,897
1,289
— —
137
694
21,243
1973
2,438
2
9,109
431
—
15,043
28,023
—
—
—
—
—
—
313
—
19,356
1,380
—
166
919
22,134
1974
5,166
6
12,886
741
—
20,485
39,284
—
—
—
—
—
—
326
—
16,212
1,062
—
194
1,028
18,822
1975 1970
1,538
4
8,683
3
11
11,288
21,527
99
2
74
4
468
647
132
—
21,641
1,738
—
901
1,473
25,885
Total Transportation
1971
1,369
—
5,687
—
7
9,488
16,551
50
—
40
10
234
334
225
—
19,733
1,755
—
251
717
22,681
1972
1,454
—
5,746
154
—
9,573
16,927
22
—
32
20
244
318
232
—
18,954
1,297
—
166
705
21,354
1973
2,438
7
9,109
431
—
15,193
27,178
20
—
28
24
200
272
320
—
19,410
1,386
——
189
925
22,230
1974 1975
5,166
13
12,886
741
—
20,588
39,394
42
—
44
37
223
346
332
'
16,260
1,064
—
215
1,031
18,902
U.S. Total
2,222 1,262 1,137 1,214 1,176
89,850 78,727 77,932 92,415 91,128
Source: U.S. Department of Interior, Bureau of Mines, Annual Fuel Oil Sales. Selected Years.
-------
Table C.4-14
Sales of Residual Type Fuel Oils in the United States for Unspecified Use.
(including Military) for PAD District I. by State. 1970-1975
(MBBLS)
Military
Miscellaneous
Total Unspecified
State
District I
1970
1971
1972
1973
1974 1975 1970 1971 1972 1973 197A 1975 1970
New England
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
oo Subtotal New
England
Delaware
Washington, D.C.
Florida
Georgia
Maryland
New Jersey
New York
North Carolina
Pennsylvania
South Carolina
Virginia
W. Virginia
246
29
1,465
67
2,297
2
4,106
108
10
163
16
405
3,009
1,712
136
1,408
206
8,387
—
337
30
1,996
35
2,654
2
5,054
130
5
346
12
389
2,956
1,360
68
2,126
103
8,542
—
346
50
1,793
40
2.108
2
4,339
104
145
267
155
669
3,109
1,324
50
1,985
90
8,653
—
245
50
1,301
20
1,200
2
2,818
409
477
225
200
719
3,052
2,164
37
2,719
207
6,110
—
140
55
673
15
787
3
1,673
114
687
161
77
692
2,151
1,518
79
2,585
141
4,770
—
36
2
64
2
110
1
215
422
5
1,004
41
264
130
467
382
189
161
356
1
43
44
37
1
80
1
206
264
4
803
32
520
156
390
348
510
163
473
1
106
55
500
1
51
3
716
649
2
289
35
231
152
269
341
1,149
115
666
1
63
50
317
1
23
3
457
1,227
2
134
45
124
115
268
163
1,081
42
334
72
33
21
118
2
8
2
184
876
3
122
20
13
70
120
54
741
44
269
33
District I Total
U.S. Total
19,666 21,091 20,890 19,137 14,648
28,704 29,217 24,622 22,892 20,423
3,637 3,870 4,615 4,064 2,549
7,295 6,109 8,886 9,028 8,503
1971
1972
1973
1974 1975
282
31
1,529
69
2,407
3
4,321
530
15
1,167
57
669
3,139
2,179
518
1,597
367
8,743
1
23,303
35,999
380
74
2,033
36
2,734
3
5,260
394
9
1,149
44
909
3,112
1,750
416
2,636
266
9,015
1
24,961
35,326
452
105
2,293
41
2,159
5
5,055
753
147
556
190
900
3,261
1,593
391
3,134
205
9,319
1
25,505
33,508
308
100
1,618
21
1,223
5
3,275
1,636
479
359
245
843
3,167
2,432
200
3,800
249
6,444
72
23,201
31,920
173
76
791
17
795
5
1,857
990
690
283
97
705
2,221
1,638
133
3,326
185
5,039
33
17,197
28,926
-------
Table C.4-14 (Cont'd)
Sales of Residual Type Fuel Oils in the United States for Unspecified Use.
00
u>
State
District II
Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin
District II Total
U.S. Total
(including Military)
for PAD
District II, by State, 1970-1975
(MBBLS)
Military
1970
206
33
—
6
—
4
10
153
2
—
50
16
—
—
1
481
1971 1972
167 20
18 13
—
37
—
— •— c
2
15 30
—
—
23 8
3 297
—
—
7 ™
235 410
1973
68
26
—
25
—
83
—
29
—
—
8
37
—
131
—
407
1974 1975
103
34
—
10
—
87
—
65
—
—
10
15
—
63
—
387
1970
616
61
105
14
34
95
49
54
38
30
139
80
5
6
46
1,372
1971
357
45
47
7
1
42
28
26
16
15
85
40
—
8
31
748
Miscellaneous
1972
451
46
—
75
—
337
20
80
24
4
140
25
—
4
20
1,226
1973
402
65
—
60
—
338
14
92
16
4
142
20
—
7
15
1,175
1974 1975
346
130
—
20
—
269
—
86
10
2
176
12
—
8
7
1,066
1970
822
94
105
20
34
99
59
207
40
30
189
96
5
6
47
1,853
Total Unspecified
1971
524
63
47
7
1
42
30
41
16
15
108
43
—
8
38
983
1972
471
59
—
112
—
342
20
110
24
4
148
322
• —
4
20
1,636
1973
470
91
—
85
—
421
14
121
16
4
150
57
—
138
15
1,582
1974 1975
449
164
—
30
—
356
—
151
10
2
186
27
—
71
7
1,453
28,704 29,217 24,622 22,892 20,423
7,295 6,109 8,886 9,028 8,503
35,999 35,326 33,508 31,920 28,926
-------
Table C.4-14 (Cont'd)
Sales of Residual Type Fuel Oils in the United States for Unspecified Use.
00
District/State
District III
Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas
District III Total
District IV
Colorado
Idaho
Montana
Utah
Wyoming
District IV Total
District V
Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington
District V Total
U.S. Total
(including Military) for PAD Districts III, IV, V, by State, 1970-1975
(MBBLS)
Military
1970
137
1
996
—
—
354
1,488
„
—
45
21
—
66
3
—
6,282
2
1
167
548
1971
62
578
—
—
145
785
„
—
45
24
—
69
6
—
6,371
—
—
204
456
1972
26
—
569
—
—
154
749
8
—
32
10
—
50
12
—
2,126
—
4
108
273
1973
100
—
1,176
•
—
524
1,800
37
—
16
5
—
58
10
—
1,134
—
5
103
238
1974 1975
375
—
1,717
—
—
1,044
3,136
66
—
80
19
—
165
6
—
1,711
—
4
116
250
1970
99
50
237
18
108
125
637
112
40
37
54
42
285
56
36
788
144
5
107
228
1971
101
55
73
32
54
106
421
75
8
17
44
28
172
9
47
599
58
1
124
60
Miscellaneous
1972
182
70
219
—
28
441
940
86
8
2
20
10
126
55
132
685
365
—
97
645
1973
426
130
587
•
242
1,097
2,482
81
12
27
25
12
157
60
144
202
429
1
78
236
1974 1975
594
187
915
—
424
1,364
3,484
321
24
15
111
13
484
46
137
129
506
3
15
84
1970
236
51
1,233
18
108
479
2,125
112
40
82
75
42
351
59
36
7,070
146
6
274
776
Total Unspecified
1971
163
55
651
32
54
251
1,206
75
8
62
68
28
241
15
47
6,970
58
1
328
516
1972
208
70
788
—
28
595
1,689
94
8
34
30
10
176
67
132
2,811
365
4
205
918
1973
526
130
1,763
— -
242
1,621
4,282
118
12
43
30
12
215
70
144
1,336
429
6
181
474
1974 1975
969
187
2,632
—
424
2,408
6,620
387
24
95
130
13
649
52
137
1,840
506
7
131
334
7,003 7,037 2,523 1,490 2,087
28,704 29,217 24,622 22,892 20,423
1,364 898 1,979 1,150 920
7,295 6,109 8,886 9,028 8,503
8,367 7,935 4,502 2,640 3,007
35,999 35,326 33,508 31,920 28,926
Source: U.S. Department of Interior, Bureau of Mines, Annual Fuel Oil Sales. Selected years.
-------
C.5 GOVERNMENT FACTORS
C.5.1 INTRODUCTION TO DISCUSSION OF FACTORS AND TRENDS
This, and the next five chapters, discuss various factors and trends
which will influence the future need for residual fuel oil. Of
particular focus are those factors that would change the supply
patterns, alter the supply potential, affect demand or change the
technical environment of residual fuel oil usage. Specific chapters
discuss:
• Government factors
• Foreign factors
• Energy production trends
• Technological trends
• Handling problems
• Demand trends
C.5.2 OVERVIEW ON GOVERNMENT FACTORS
In the present domestic petroleum market, the direction of government
policy and the numerous federal energy programs have an important impact
on the availability and consumption of oil products. The significance
of government policies is heightened in the case of residual fuel oil,
because historic policies have resulted in supply and demand patterns
for this product which are unique by comparison with other petroleum
products. In this chapter we will describe the major ways in which
federal policy has influenced the supply and demand for residual fuel
oil in the past and give a general forecast as to the future impact
of governmental regulations.
85
-------
As a result of a series of events and government policies which are
described in detail in the "Domestic Refining" section below (See
C.5.3), the United States has come to be dependent upon foreign
sources (primarily Caribbean and Canadian) for 60% of its residual
fuel oil requirements in 1974. At the same time, consumption of
residual fuel oil has come to be concentrated on the East Coast due to
a combination of the scarcity of indigenous domestic energy substitutes,
a relaxed import policy, relative supply economics, and government air
pollution control regulations. The details behind these factors, as
well as a discussion of the probable impact of current and projected
government policies are presented in this chaptert The specific
topics to be covered are:
• Domestic refining — how the government's policies
have and will influence the amount of domestic re-
fining capacity and the yield of residual fuel oil
from this capacity.
• EPA regulations — trends in restrictions on the
quality of residual fuel oil which can be burned and
how these regulatory trends will impact on the supplies
of residual fuel oil
• FEA's mandatory conversion program — the impact of
the mandatory conversion program on residual fuel
consumption.
• Promotion of research — the direction of government-
funded research efforts as an indication of what
substitutes may be able to replace residual fuel
oil fired operations.
Another important governmental factor, that of regulation and control
of the natural gas industry, is discussed in C.7, Energy Production
Trends.
86
-------
C.5.3 DOMESTIC REFINING
C.5.3.1 Introduction
In line with its objective of increasing domestic energy self-sufficiency,
the FEA has announced a goal of encouraging increased domestic oil
refining capacity. However, the precise incentives and program with
which the FEA hoped to induce construction of additional capacity
have never been clearly or consistently defined. Since the inception
of the Project Independence ethic by President Nixon in May of 1973, re-
finers or would-be refiners have been faced with a constantly changing
short-term situation and an equally uncertain longer-term outlook.
Domestic product demand has remained below 1973 levels for two con-
secutive years. At the same time, the direction of future government
policy has been extremely ambiguous with regard to such critical
matters as import controls on crude and products, continued close
federal government regulation of the petroleum industry, EPA re-
strictions on refinery siting and emissions, and taxation of refining
profits. Given such uncertainty, refiners found it difficult to obtain
financing or sign long-term crude supply contracts for new refining
capacity. As a result, many refiners responded by postponing or
cancelling plans to expand existing capacity or build new capacity.
With the passage of the Energy Policy and Conservation Act in December,
1975 (the so-called "Omnibus Energy Bill"), only the outlook over the
short-term has been clarified. The longer-term questions such as the
degree and terms of government regulation of the domestic petroleum
industry and the tariffs and levels for crude and product imports
remain unanswered. In addition, uncertainties regarding environmental
issues still have to be resolved—environmentalists' objections to
proposed sitings, refinery emission standards, and quality standards
for refined products (particularly, the lead and sulfur specifications
for gasoline).
This section will review current and projected refining capacity serving
87
-------
the U.S. market and discuss the impact of current government policies
on future refining capacity.
C.5.3.2 Current and Projected Domestic Refining Capacity
Table C.5-1 summarizes operable domestic refining capacity in the U.S.
by P.A.D. district as of January 1, 1975, and gives an estimate of
additional capacity which was scheduled to be completed during 1975.
As shown, almost 70% of the capacity is located in the Gulf Coast
(P.A.D. District III) and in the Midwest (P.A.D. District II), his-
torically the greatest production areas of domestic crude oil. By
contrast, only 47% of the total U.S. demand for petroleum products
is in Districts II and III.
Even without the uncertainties that exist in today's petroleum industry,
it would be difficult to construct long-range forecasts of future
increases in refinery capacity with great accuracy. Lead times required
to plan and execute refinery construction projects are normally two
to three years, but environmental opposition to proposed siting plans
have begun to cause considerable delays (if not total blockage) in
original deadlines. Thus, forecasts of capacity can be made with
reasonable accuracy for only two to three years into the future. Table
C.5-2 presents the FEA's latest forecast of refining capacity by
district through 1979. In addition to the capacities quoted in Table
C.5-2, the FEA lists another 4185 thousand barrels per day of capacity
which either has been judged uncertain or as in the early planning
stages, and a further 1900 thousand barrels per day of capacity being
held up by environmental opposition.
Beyond 1979, further expansion of capacity will be a function of
such factors as product demand growth, trends in government policy,
the general state of the economy, the availability of sufficient crude
supplies and worldwide refinery capacity.
88
-------
Table C.5-1
Present Operable U.S. Refining Capacity
By PAD District
(MBBLS/Day)
P.A.D. DISTRICT
II
III
IV
Total U.S.
Operable Capacity as
of January 1, 1975
1611.1 4012.8 6239.2
530.1 2357.5 14750.7
03
VO
Estimated New Capacity
added in 1975
84.0
105.2
163.2
3.0
30.0
385.4
TOTAL ESTIMATED CAPACITY
AS OF JANUARY 1, 1976
1695.1 4118.0 6402.4
533.1 2387.5 15136.1
Note: Figures indicate operable capacity. In reality, refineries do not operate constantly at 100% of
operable capacity. Instead, annual utilization of capacity rarely exceeds 90% of rated operable
capacity.
Source: Capacity as of January 1, 1975, from Office of Oil and Gas, FEA.
1975 capacity additions from "Trends in Refinery Capacity and Utilization," June, 1975, FEA.
-------
Table C.5-2
Forecast of U.S. Refining Capacity
vo
o
Estimated Capacity as
of January 1976
Net additions in 1976
Subtotal
Net additions in, 1977
Subtotal
Net additions in 1978
Subtotal
Net additions in 1979
Total Forecast Capacity
as of January 1980
By PAD District, 1975-1979
I
1695
42
1737
22
1759
22
1781
272
P.A.D,
II
4118
70
4188
54
4242
54
4296
54
(MBBLS/Day)
. DISTRICT
III
6402
511
6913
335
7248
485
7333
85
IV
533
7
540
7
547
7
554
7
V
2388
404
2792
47
2839
32
2871
32
Total
15136
1034
16170
465
16635
200
17235
450
2053
4350
7818
561
2903
17685
Note:
In addition to firm projects, the FEA added 200,000 barrels per day of capacity from 1976 onward to
account for small unannounced expansions. This allowance for small unannounced projects was distributed
among the districts in proportion to each district's share of current total capacity.
Source: "Trends in Refinery Capacity and Utilization," FEA, June 1975;. Arthur D. Little, Inc. estimates.
-------
C.5.3.3 Caribbean Refining Capacity
In addition to the onshore domestic capacity just described, the U.S.
has traditionally relied heavily on Caribbean refining capacity (in-
cluding Venezuela) to supply product, especially residual fuel oil, to
the U.S. East Coast. For example, in 1974, the Caribbean refineries
provided an average of 1.25 million barrels per day of residual fuel
oil, or 73% of PAD I residual fuel demand. Table C.5-3 details the
refining capacity currently available in the Caribbean.
The dependence of the East Coast on refineries in the Caribbean for
residual fuel has a long history. Under the terms of the Mandatory
Oil Import Program proclaimed by President Eisenhower in 1959, the
quantity of crude and product imports permitted into Districts I-IV
was restricted to 12.2% of estimated annual domestic production in those
districts (minus special exemptions for Canadian overland imports and
product imports from the Virgin Islands and Puerto Rico). Licenses
or tickets to import products were allocated to historic importers on the
basis of their proportion of 1957 imports. These controls on imports
were necessitated by the fact that the price of U.S. oil production
was controlled at the wellhead and was generally priced higher than
foreign crudes transported to the U.S. To provide economic justification
for higher crude costs, U.S. refiners maximize gasoline yield since
gasoline sales provide the greatest profit.
In 1966, the regulations of the Mandatory Oil Import Program were
amended to effectively permit free importation of residual fuel oil
into District I. This change merely recognized what was at that point
the prevailing supply mode for residual fuel oil on the East Coast.
Because of their access to .cheaper foreign crudes, their lower operational
and labor costs, arid the availability of deepwater terminal sites,
91
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Table C.5-3
Caribbean Area
Refinery Processing Capacities
As at
1/1/75
(MB/CD)
Country
Antigua
Bahamas
Barbados
Colombia
Costa Rica
Dominican
Republic
El Salvador
Guatemala
Honduras
> Jamaica
Martinique
Neth. Antil.
Nicaragua
Panama
Puerto Rico
Trinidad
Venezuela
Virgin Is.
Total
Company
W.I.O.C.
BORCO (NEPCO/SOCAL)
Mobil
(All Companies)
R.C.P.
Falconbridge & Refidomsa
Acajutla
Texas & Guatcal
Texaco
Exxon
S.A.R.A.
Shell & Lago (Exxon)
Exxon
Refpan
Gulf, Sun & COR
T.T.O.C. & Texaco
Chevron, CVP, Creole
(Exxon), Gulf, Mobil,
Phillips, Sinclair, Texas
Hess
Key to hydroprocessing: HDS — Catalytic
Atmospheric
Distillation
16.0
500.0
3.0
172.1
11.0
45.5
14.0
24.8
14.0
32.6
10.4
900.0
13.2
100.0
283.8
461.0
1,531.7
665.0
4,784.1
Thermal
Cracking
Catalytic (Visbreaking
Cracking & Coking)
-
48.5
-
-
-
35.0
47.8
26.5
48.6
206.4
-
17.5
3.0
-
-
-
379.0
22.0
22.0
109.8
553.3
hydrodesulfurization
HDT — Catalytic hydrotreating
Sources: Oil and Gas Journal surveys
Petroleum Times, January 24, 1975
Hydrocarbon Processing, February 1975
Trends in Refinery Capacity and Utilization, FEA, June 1975
Catalytic Hydrogen Processing
Reforming HDS HDT
2.0
2.0
1.5
7.0
2.6
5.5
1.8
3.0
2.5
15.0
2.6
7.5
75.5
27.0
20.6
55.0
230.7
7.5
262.0
193.6
853.3
3.5
67.0
442.0
Vacuum
Distillation
1.5
70.0
85.0
0.5
7.0
-
-
—
18.9
3.3
140.0
10.6
-
112.4
80.0
12.0
9.5
9.5
5.0
-
3.5
223.0
-
30.0
12.0
67.0
-
-
-
-
1.5
-
230.0
1.9
14.0
114.2
194.0
360.0
185.0
1,257.6
-------
the Caribbean refiners were in a position to supply the East Coast
residual fuel oil requirements at lower prices than domestic East or
Gulf Coast refiners running price-controlled U.S. crudes through ex-
pensive conversion refineries. Domestic refiners preferred to maximize
gasoline yields at the expense of heavier products due both to the
greater profit margins available from gasoline sales and their invest-
ment in conversion refining facilities. As a result, Caribbean refining
capacity emphasized residual fuel oil yields (typically 50-60% of crude
throughput) and total refining capacity in the area developed rapidly
at rates far in excess of growth in local Caribbean petroleum con-
sumption.
Over the period 1973-1975, Caribbean refiners have found themselves
severely affected by, first, the drop in U.S. and European demand for
residual fuel oil and, second, by the increased domestic residual fuel
oil yield prompted by lowered average domestic crude costs under the
Entitlements Program compared to the now very high foreign crude prices.
As a result, Caribbean refiners have been forced to operate at rates
well below capacity or, in some cases, cease operations entirely for
certain periods. Certain refiners, particularly Amerada Hess in ,the
Virgin Islands and, at times, NEPCO in the Bahamas, have found some
relief from their current predicament in the form of special entitle-
ment grants allowing them some relief from the higher costs of foreign
crude. However, if these special entitlement grants are not continued
in 1976 under the FEA regulations stemming from the new Energy Policy
and Conservation Act, the Caribbean refiners will be at a considerable
disadvantage in selling residual fuel oil to U.S. East Coast markets.
C.5.3.4 Present Government Policies and Programs Influencing Growth
In Refining Capacity
C.5.3.4.1 Import Fees - At the time of the signing of the Energy Policy
and Conservation Act, President Ford removed the supplemental license
fees of $2.00/Bbl on imported crude. Thus, at present, there remain
two types of fees on imported crude and product. The first is an import
93
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tariff levied on the following schedule:
Source of Import
Most-Favored
Type of Import Nations Other Nations
(Tariff) (
-------
Any volumes above the 1973 import levels are automatically subject to
the import license base fees. The importer is allowed to credit any
Customs tariffs paid against the import license base fees owed under
the above schedule.
The base license fees were originally conceived as a means of encouraging
domestic oil production and refining by making imported crude and,
particularly, imported products, pay a substantial import penalty. The
base license fee did result in an initial flurry of interest in expanded
refinery capacity; however, the Arab oil embargo and OPEC price hikes
of 1973/1974 instigated a period of such uncertainty about the future
that many of the initial positive effects on refining capacity were
overridden. The feeling of uncertainty about the future outlook for
domestic refining was not alleviated during 1974 and 1975 under the
various FEA programs such as the Buy/Sell and Entitlements Programs,
even though these programs were established to assure all refiners
adequate crude supplies at approximately equal costs. The uncertainty
has recently been reduced for the next 3-1/4 years with the signing
of the Energy Policy and Conservation Act, which provided for the con-
tinuation of FEA controls on domestic crude acquisition and costs (see
analysis of impact below). However, most of the longer-term uncertainties
remain unresolved and this environment may continue to obstruct refinery
expansion.
C.5.3.4.2 Impact of Energy Policy and Conservation Act (EPCA) - In
December 1975, the Administration ended the long struggle between itself
and Congress over the future course of U.S. energy policy by signing into
law the Energy Policy and Conservation Act (EPCA) or Omnibus Energy Bill.
The passage of the EPCA represents a considerable compromise of the
Administration's position that higher energy prices are necessary to
encourage conservation and stimulate production. Instead of the gradual
decontrol of domestic oil prices which the President desired, the EPCA
provides for the maintenance of an average controlled price for domestic
95
-------
oil (initially $7.66) which can be raised a maximum of 10%* per annum
over the 40-month life of the EPCA. According to the implementation
regulations currently proposed by the FEA, the average domestic oil
price would be realized by holding old oil (i.e., the proportion of
domestic oil equivalent to average 1973 production) at the controlled
price of $5.25 per barrel and allowing new oil prices (i.e., price of
oil volumes produced in excess of 1973 average production) to be at
a level such that the weighted average of the two is equivalent to the
mandated domestic average. This has the effect of rolling back current
new oil prices by about $1.30 per barrel. In effect, the current FEA
implementation strategy would indicate a three tier pricing system in
the U.S.: old domestic oil, controlled at $5.25; new domestic oil,
initially priced at $11.28; and foreign oil, at international levels.
The result of the domestic three tier pricing structure is that U.S.
refiners will, on average, obtain their supplies at prices below inter-
national oil parity. According to current FEA plans, the benefits of
these lower average crude costs will be spread equally among all refiners
as a modified version of the Entitlements Program is perpetuated. Other
FEA programs initiated under the Emergency Petroleum Allocation Act (1973),
such as the Buy/Sell Program (which assists all refiners to have physical
access to sufficient crude supplies) and the dollar-for-dollar cost
increase pass-through to products, are also expected to continue in some
form under the EPCA. Thus, at least for the 40-month duration of the
EPCA, there would appear to be a strong incentive for domestic refiners
to maximize their output and reduce supplies from traditional import
sources. This incentive for domestic refiners to address the whole
domestic demand barrel rather than just meet gasoline demand was already
evident under the original Entitlements Program. Domestic refiners'
*
The amount of the annual increase includes a factor for inflation (as
measured by the GNP deflator) plus a 3% oil industry incentive increase.
If the situation arises in which those two factors together exceed the
annual 10% increase or if the President wishes to increase the percentage
for industry incentive, Congressional approval can be sought.
96
-------
yields of residual fuel oil have increased over the last year or so as
refiners modified their gasoline-maximizing yield strategies in favor
of a more balanced outturn. Other evidence of this incentive is the
fact that U.S. refiners are building refineries or considering refinery
projects involving high fuel oil yield processing schemes. For example,
the Energy Company of Louisiana's (ECOL) new 200 MBCD refinery at
Garyville, Louisiana, which is scheduled to be completed in 1976, will
have a 67% fuel oil yield on crude input, as compared to a historic
average residual fuel oil yield on crude for the U.S. Gulf Coast refineries
of 4.5%.
In summary, the EPCA provides that over the next 3-1/4 years, crude costs
to domestic refiners will be subject to continued FEA regulations and
will likely, as a result of the EPCA requirement for a controlled
domestic crude price, be lower than those prevailing on the international
market. Over this period, there will, therefore, be an economic incentive
for increased domestic refining activity, and also for an inducement for
domestic refiners to lower gasoline yields and increase fuel oil yields.
C.5.3.5 Domestic Refining Trends
Beyond the purview of the Omnibus Bill, it is difficult to forecast the
forces which influence domestic refining. If domestic crude prices
continue to be regulated at a level below international market prices
and the level of domestic product demand warrants, the incentives for
domestic refiners would presumably hold and Caribbean refineries would
be at a disadvantage. If domestic crude prices are completely de-
controlled with the expiration of the EPCA, the current motivation for
increased U.S. activity would evaporate. In large part the longer-term
outlook will depend upon the relative levels of domestic and foreign
crude costs and U.S. Government policy.
It is expected, however, that U.S. refining capacity will continue to
expand over the next decade and that the expansions will favor the
97
-------
production of fuel oil over conversion processing to make gasoline.
In addition, new refining capacity will probably be designed to accept
sour crude oils, so will include desulfurization equipment. U.S. refinery
growth may not keep up with increases in petroleum demand, but offshore
refining capacity (see Chapter C.6 for a more detailed analysis) appears
more than adequate in the next decade to handle new U.S. petroleum
product demands, especially for residual fuel oil.
C.5.4 EPA AIR QUALITY REGULATIONS
C.5.4.1 Introduction
Air quality has become a prime concern in the United States since air
quality directly affects human health and the biosphere in which we
live. Regulations to control air pollution have been developed primarily
in the last decade and it is not yet clear what the final rules and
regulations will be or how they will affect fuel consumption patterns.
Here we look at the development of current air quality laws both at a
federal and state level and look at some of the current issues regarding
air pollution control in order to draw some conclusions about probable
future air quality control measures.
C.5.4.2 Development of Current Air Quality Regulations
Prior to 1955 the responsibility for maintenance of air quality rested
with state and local governments. For the most part, the control measures
initiated in these early years were smoke abatement measures since smoke
was the most evident form of air pollution. However, beginning in 1955,
the federal government began increasingly to involve itself in air
pollution control programs. Initially, federal efforts were confined to
research programs and counseling to assist state pollution control pro-
grams. In 1963, Congress passed the landmark Clean Air Act, which
authorized more massive federal financial assistance for the establish-
ment and improvement of state and local control programs, sanctioned
federal interstate abatement actions and provided for a massive federal
research effort to study and publicize the effects of pollution. In
98
-------
1965, the original Clean Air Act was amended to give the federal
government the authority to curb auto pollution emissions.
The Air Quality Act of 1967 signaled a new and more comprehensive
approach to air pollution control. It mandated the federal government
(through the National Air Quality Control Administration) to designate
air quality regions on the basis of meteorological and urban factors
and to publish documents describing the effects of various pollutants
accompanied by analyses of the types and costs of available source
control techniques. On the basis of the federally-generated information,
the states were required to establish air quality standards and prepare
plans for meeting such standards.
In 1970, the role of the federal government in air pollution control
became even broader with the passage of the Clean Air Act Amendments
directing the newly created Environmental Protection Agency (EPA) to
set national ambient air quality standards. The states, in turn, would
be required to submit for EPA approval their control plans for achieving
the national air quality standards. In accordance with the 1970 amend-
ments, EPA published, in April 1971, the national standards for six types
of air pollutants: sulfur oxides, particulate matter, carbon monoxide,
photochemical oxidants, nitrogen oxides, and hydrocarbons. These
standards were stated for two levels: the primary standards were
designed to prevent hazardous health conditions; and the secondary
standards were intended to prevent any other detrimental effects (on
animals, vegetation, visibility, aesthetics, etc.). It is important to
note that these federal standards are stated for ambient air quality
measured at ground level. They are not emission standards which measure
pollution levels at their source (e.g., at the stack tip). The compli-
ance strategies submitted by the states were to include plans for attaining
and maintaining the primary standards within three years and the secondary
standards within five years. As a part of their compliance programs the
states had the right to set emission levels which they thought would
enable them to meet federal ambient air quality standards.
99
-------
The structure of the U.S. federal air pollution control laws as described
above has always allowed the state and local governments the ultimate
discretion to determine what control action would be appropriate for
their particular pollution levels, meteorological conditions, fuel supply
options, etc. As a result, the current regulations regarding the quality
specifications for fuels which may be burned vary widely throughout the
country, and even within individual states. Also, because the federal
regulations do not restrain the state and local authorities from enforcing
air quality standards superior to the national standards, many state
and metropolitan areas have promulgated more stringent standards and
control requirements than enacted by the EPA. In particular, the densely
populated urbanized regions along the East Coast have passed very strict
regulations regarding emission levels of pollutants.
C.5.4.3 State Regulations
According to the EPA's charter, the authority to establish specific
pollution control measures was delegated to individual states rather
than to the regional or federal EPA officials. These state regulations
were intended to translate the EPA's primary air quality standards into
practical operating guidelines for potential polluters. Typically,
for existing stationary sources, the states chose to stipulate the
maximum quantity of pollutants that could be emitted from a source over
a particular time period—the reading of emission levels taking place
at the stack tip. With experience, these stack-tip readings were trans-
lated into fuel input standards; for example, maximum sulfur concentra-
tions in fuel oils, ash content for coals, etc. Large new boilers
(with capacities greater than 250 MMBTU/hr. [263.7 Gigajoules/hr.]),
however, were required to meet federally set fuel standards which
translated into approximately 0.8% sulfur in residual fuel oil burning
boilers. All state regulations were subject to review and final
acceptance by regional and federal EPA authorities to certify that, at
a minimum, federal air quality standards were being met.
100
-------
Beginning in mid-1970 and carrying through 1971, the first state imple-
mentation strategies became effective. As might have been expected,
the densely-populated areas were generally the first to act. As early
as October 1, 1971, the greater New York and Boston metropolitan areas
required residual fuel oil users to burn fuel oil with less than 0.5%
sulfur, while Philadelphia and Washington, D.C. limited sulfur content
to under 1%. Congested West Coast areas were also quick in establishing
stringent sulfur specifications for residual fuel oils—with both Los
Angeles and San Francisco restricting sulfur in fuel oil to less than
0.5% in the fall of 1971. Other less populated or developed areas tended
to set more lenient sulfur restrictions or to establish standards
applicable only to new equipment or to ignore sulfur limitations in
their immediate implementation regulations. Sulfur restrictions in
critical air pollution areas—primarily, the metropolitan areas of the
East and West Coasts—gradually become more comprehensive and stringent,
so that virtually all the fuel oil consumed in these areas was below
1% sulfur and much of it below 0.5% sulfur.
The regulations devised by the states were not and still are not
necessarily uniform throughout each state. More stringent sulfur speci-
fications tend to apply to fuel oil burned in metropolitan areas than
to oil burned in the more rural areas. Table C.5-4 describes in detail
the sulfur specifications which currently apply in individual states
within PAD Districts for the burning of residual fuel oil and indicates
each state's proposed revisions (if any) to current regulations.
C.5.4.4 Current Issues Surrounding Air Pollution Control
Largely as a result of the higher oil prices, the Arab Oil Embargo and
the subsequent policy of U.S. energy independence, U.S. energy consumers
have begun to question the stringency of local air pollution regulations,
particularly as they dictate the use of very low sulfur, and typically
foreign-produced, fuel oils (or natural gas) as opposed to less costly
and domestically available coal. In the wake of the recent upheaval in
the world energy market, some of the larger fuel consumers are either
101
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Table C.5-4
Slit*
Ponton of Stall
Alabama Category I Counties Oil All
and Jefferson County
Alaska All
Arizona
All
Fuel
Type Fuel Uta
Oil All
Coal
Oil All
Coal
Oil All
Coal All
Oil Existing
Oil (high Existing
sulfur)
Coal Existing
Oil New
Coal New
Sulfur
Limit
(WI.M
175(1)
166(2)
•1 08(3)
39(1)
37 (2)
24 13)
1.00(4)
0.85 (5)
0.98(1)
0.93 (2)
2.15(1)
2 04 (2)
060(3)
078 (1)
074 (2)
0.48 (3)
Eflocllve
Dtl*
1-31-75
1-31-75
1-31-75
1-31-75
1-31-75
1-31-75
5-26-72
5-26-72
5-30-72
5-30-72
•
•
5-30-72
5-30-72
5-30-72
5-30-72
Futl
SUM Portion ol SIM* Typ«
California Air Basin:
(continued) (continued)
Sacramento Valley: All
(Tehama County only)
San Joaquin Valley All
Southeast Desert: All
(Less eastern & southern
portion of Kern County)
San Diego All
Mountain Counties: All
(Tuoleme County only)
Other Counties: All
(Less Madera &
Manposa Counties)
Colorado All Oil
Coal
Connecticut All All
Delaware All Distillate
New Castle County All
Fix
All
All
All
All
All
All
All
All
All
All
All
Sulfur
Limit Effective
(Wt.S) Date
'Proposed 10-15-75. Hearingsheld 12-75. Now awaiting Slate certification. High
Sulfur Oil - Fuel Oil containing 0.90% or more by weight of sulfur.
District of All
Columbia
All
0.5
1.9
0.5
0.5
1.9
3.6
078 (I)
0.74 (2)
072. (3)
0.5
0.30
1.00
0:5
11-5-71
1-1-75
10-18-71
11-5-71
1-1-75
1-1-75
4-5-75
4-5-75
4-5-75
4-1-73
1-7-72
1-7-72
7-1-75
Arkansas
California
The only regulations adopted by the State require
that SOi concentrations do not exceed 0.20 ppm in
the ambient air at any places Ddyond the premises
on which the source ot the emissions is located.
Florida
Air Basins:
North Coast: (Less
Mendocina & Sonoma
Counties)
San Francisco Bay
North Central Coast
South Central Coast
Stjuth Coast
Northeast Plateau:
(Lassen County only)
All
Oil
Coal
Oil
Coal
All
AM
All
All
All
Existing
Existing
New:
> 250 MBTuhr.
New:
> 250MUTU.hr
All
All
All
All
19
0.60 (4)
0.51 (5)
0.78(1)
0.74 (2)
0.72 13)
0.5
0.5
0.5
0.5
1-1-75
11-5-71
11-5-71
12-74
12-74
12-74
11-5-71
11-5-71
11-5-71
11-5-71
Georgia
All
•Units with a heal
Oil
Coal
Oil
Coal
> 250 MBTU/hr.-
Existing
Existing
New '
New
107(1)
1.02(2)
0 90 (3)
0.78 (1)
0.74 (2)
0.72 (3)
7-1-75
7-1-75
7-1-75
1-18-72
1-18-72
1-18-72
input ol less than 250 fiBTU/hr. must use "latest reasonably
available technology."
All
All
Oil
Coal
< 100 fvTBTUAlr.
> 100 MBTUAir
> 250 MBTU/hr.
New
New
2.50
3.00
074 (2)
0.72 (3)
11-30-75
11-30-75
11-15-74
11-15-74
(1) Sultur content greater than the above may be allowed provided lhat
the source utilizes So. removal and the S0> emission does not ex-
ceed that allowed by the above sulfur content limitations utilizing
no SOi removal.
102
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Table C.5-4 (Cont'd)
Sill*
Hawaii
Idaho
Illinois
Portion ol Slit*
(2) Large fuel
Fuel
Type FIM) Ui*
burning sources are limited by a
SOi emission level expressed in pounds per
Sulfur
Limit Effective
(Wl.%) Oat*
maximum allowable
hour. The allowable
Fuel
Slit* Ponton ol Slit* Type Fuel Us*
Kansas All > 250 MBTU
Oil New
Coal New
level varies with size and location ol the facility and with stack
height.
Sulfur
Limit Eltactlv*
(WI.M
2.78 (2)
1.80(3)
0*1*
1-1-72
1-1-72
Kentucky Note: Fuel sulfur regulations are expressed on a sliding scale based on size ol
All
All
All
Chicago. St. Louis and
Peoria Regions
Rest ot the State
No. 1 »
No. 2 All
No. 4 All
All All
All > 250 MBTU.hr.
No. 1 All
No. 2 All
Residual All
Coal ALL
Distillate New
Existing
Residual New
< 250 MBTUtlr.
> 250 MBTu.-hr
Existing
Coal New
< 250 MBTU.'hr.
> 250 MBTU.'hr
Coal Existing
Coal Existing
'If annual arithmetic average
the tacility. Values lor typical units are given below:
0.5 Proposed
1 .0 Proposed
20 6-1-74
05 6-1-74
0.30 1-1-73
050 1-1-73
1.75 1-1-74
1.00 1-1-73
0.29(1) 12-20-73
0.29(1) 5-30-75
0 93 (2) 12-20-73
0 74 (2) 12-20-73
0 93 (2) 5-30-75
1.08(3) 4-14-72
0.72(3] 4-14-72
1 08 (3) 5-30-75
3 60 (3) 5-30-75
1 08 (3) 6-1-75'
SOi level is greater
All Oil New
S 10 MBTU/hr.
50 MBTU/hr.
100 MBTU.'hr.
» 250 MBTU.hr.
Coal New
as 10 MBTU/hr.
50 MBTU/hr.
100 MBTU/hr.
» 250 MBTU/hr.-
Priority 1 (Louisville Oil & Existing
Area) Coal
Priority 11 (Cincinnati. Oil Existing
Paducah-Cairo, S 500 MBTU/hr.
Evansville-Henderson) < 500 MBTU/hr.
Coal Existing
9 500 MBTU/hr.
< 500 MBTU/hr
Priority III (Hunlington- Oil Existing
Ashland. Bluegrass. 1000 MBTU/hr
Appalachian. Norm < 1000 MBTU/hr.
Central, South Central) Coal Existing
1000 METU.hr.
< 1000 MBTU/hr.
2.31 (2)
1.29(2)
1.02(2)
0 74 (2)
2.40 (3)
1.44 13)
1 02 (3)
0.72 (3)
Same as
New
1.39(2)
Same as
New
1.20(3)
Same as
New
1.85(2)
Same as
New
2.10(3)
Same as
New
4-9-72
4-9-72
4-9-72
4-9-72
4-9-72
4-9-72
4-9-72
4-9-72
7-1-77
7-1-78
7-1-78
7-1-78
7-1-78
7-1-79
7-1-79
7-1-79
7-1-79
than 0.02 ppm for any year ending prior to 5/30/76 or
0.015 ppm for any year ending on or after 5/30/76.
Louisianna All Oil All
Coal All
4 00 (4)
3.40 (5)
1-30-72
1-30-72
Indiana has stack emission linrts set tor each site on
the basis ol unit size, slack height, number ol stacks.
etc. The most resinci've limit would be about 1.11 (2)
vvt.% S in fuels.
Maine
East Chicago
Hammond
Oil All
Coal All
All All
1.66(2)
1 08(3)
1 50
7-1-72
7-1-72
10-13-74
Portland Peninsular
AOCR
Rest ol State
1.50
250'
11-1-75
11-1-73
' Limit does not apply to any emission source which through use ol SO* collect-
ing devices or other equipment reduces the emission ol SOi to the equivalent
ol burning such fuel with a sulfur content of 1.50%
All
Oil AH
Coal
24 |i|
2 3 (2|
36(3)
30(3)
7-31-75
7-31-75
7-31-75
7-31-78
Note: Less stringent standards lor solid luels ia>« oeen proposed to become
effective 7-1-76.
Maryland Areas I. II. V
and VI
Areas III' and IV
Distillate All
Residual All
Coal All
Distillaie All
Residual All
0.3
2.0
21
03
10
6-16-75
8-16-75
8-16-75
8-16-75
8-16-75
103
-------
Table C.5-4 (Cont'd)
Detailed Federal. State and Local Sulfur Regulations
SUM
Maryland
(continued)
Ponton of Stale
Fuel
Type Fuel U»
Coal Ail
Sulfur
Limit
(Wt.%)
0.5
1.0
Effective
Date
7-1-80
8-16-75
• Major fuel burners in Area III (Baltimore Metropolitan Area) are permitted to use
one per cent limit sulfur oil until July 1. 1976.
Slate Portion of Stale
Missouri St. Louis AQCR
(continued)
Green
Massachusetts
All
Boston Area'
Berkshire County
APCD
'No residual to be used in
NOTE: Amendments have
Boston. Pioneer
No. 2 All
Residual All
Coal All
Residual All
Coal All
All All
0.33(1)
1.02 (2)
066(3)
0 52 (2)
0.34 (3)
226
10-1-70
10-1-71
10-1-71
10-1-71
10-1-71
10-1-71
Sulfur
Fuel Limit Effective
Type Fuel Use (Wl.%) Dale
All < 2000 MBTU/hr. 2.0 12-68
Oil > 2000 MBTUfhr. 2.13 (2) 3-24-70
Coal > 2000 MBTU/hr. 138(3) 3-24-70
Coal Existing 3.6 (5) current
Coal New 0.8 (5) current
Note: The sullur limits for facilities < 2.000 MBTUrtir. are effective only lor the
period October
Montana All
through April.
Oil All 1.85 7-1-72
Coal All 1.20 7-1-72
units ol 6 MBTU/nr heal input 01 less alter 1-74.
i been proposed and are uiiiler
consideration lor the
Valley. Southeastern Massachusetts.
Merrimack
Valley, and Central Massachusetts APCD s
Michigan
Minnesota
Mississippi
Wayne (Detroit Area)
All
Minneapolis-St. Paul
AOCR
Rest ol State
All
Distillate All
Residual All
Coal-pul-AII
verized
Coal- All
other
All < 500 M IDs steam/
hr.
> 500 M :bs slaam/
hr.
Oil >250MBTU1lr
< 250M8rUlir
Coal > 250 MBTU.hi
< 250 MB ru.'tn
All > 250 MBlUIll
Distillate < 250MBTUnr.
> 250 MBTU/hi.
Residual < 250MBIUihr
> 250 MBTU tir
Coal < 250 MBTU.nr.
> 250 MBTU-hr.
030
1.00
0.70
1.25
1 00
0.50
20
1 5
1 5
10
1 SO
SOO
t SO
200
200
2.34(1)
468 (1)
2 22 (21
4.44 (2)
1.44 (3)
2 88 I3I
8-1-72
8-1-73
8-1 -76
8-1-75
8-1-76
8-1-74
7-1-75
7-1-78
7-1-75
7-1-78
6-1-74
6-1-74
6-1-73
6-1-74
6-1-74
5-11-72
5-11-72
5-11-72
5-11-72
5-11-72
5-11-72
Nebraska All
Nevada Washoe County:
, Cities of Reno and
Sparks.
Rest ol State
New AM
Hampshire
Oil All 2.4(1) 2-26-74
2.3 (2) 2-26-74
Coal All 15(3) 2-26-74
All < 250 MBTU/hr. 1.0 7-1-70
All > 250 MBTU/hr. ' 8-19-75
' Allowable emissions calculated by use of the For-
mula, y = 0.105x. where x =- minimum heal input.
number of millions ol BTUs -per hour, and y -
allowable rate of sulfur dioxide emission In pounds
per hour.
All All
•Maximum allowable rate of SO. calculated by use
ol the formula Z = 0.15X. where Z = allowable rate
of SOi emission in pounds per hour and X = max-
imum heat input in MBTU/hr.
No. 2 All 0.40 10-1-72
No. 4 All 1.00 10-1-72
No 5 & All 2.00 10-1-73
6'
Coal Existing 1.68(3) 10-1-70
New 0.90 (3) 4-15-70
•New Hampshire portion ol the Androscoggin Valley AOCR is permitted to use
No. 5 4 6 oil with a 2.20 wt% sullur.
Missouri
All except cities ol
St. Louis and St. Charles
and Si. Louis. Jefferson.
FranKlin. Clay. Cass.
Buchanan. Ray. Jackson
Plane and Green Count. e
Oil Existing
.Coal Existing
Oil Now
Coal New
s
100 (4)
340 (5)
1 00 (4|
065 15)
2-9-72
2-9-72
2-9-72
2-9-72
New Jersey Atlantic. Cape May. No 2 All 0.3 5-1-68
Cumberland. Hunterdon. No. 4 All 0.7 5-1-68
Ocean. Sussex and No. 546 All 1.0 5-1-68
Warren Counties Coal All 0.2 10-1-71
104
-------
Table C.5-4 (Cont'd)
Detailed Federal. State and Local Sulfur Regulations
State
New Jersey
(continued)
New Mexico
Fuel
Portion of Slit* Type Fuel Us*
Rest of State No. 2 All
Residual All
All Oil > 1,000.000 MB TU,tir
Coal > 250 MBTU/hr.
New
Existing
Coal > 3000 MBTU/hr
Existing
Sulfur '
Limit Effective
(Wt.S) Date sut.
0.2 10-1-71 North
0.3 10-1-71 Dakota
1
.0.31 (2) 1-10-72 . On'°
1
0 20 (3) 3-25-72'
7-31-77
7-1-77
•SOi emissions to the atmosphere may not be in excess ot 35% by weight of
the SOi which would be produced upon combustion of the coal prior to any
pretreatment.
"SOi emissions to the atmosphere may not be in oxctiss ot 15% by weight of
the SOt which would be produced upon combustion uf the coal prior to any
pretrealment.
•
Portion of Slat*
All
Priority 1 Regions
(Cleveland. N.W. Ohio,
Steubenville. Toledo, &
Zanesville Regions)
'Priority II Regions
(Dayton, Marion-
Mansfield, Marietta,
Cincinnati, &
Youngstown Regions)
'Priority III Regions
(Columbus. Portsmouth,
Sandusky & Wilmington-
Chillicothe Regions)
Fuel
Type
No. 142
Residual
Coal
Sources
Oil
Coal •
Oil
Coal
Oil
Coal
Fuel Use
All
All
All
> 250 MBTU/hr
Existing
Existing
Existing
Existing
Existing
Existing
Sulfur
Limit
(Wl.%)
0.&
2.78 (2)
1.80(3)
0.98 (1)
0 92 (2)
0 60 (3)
1.56(1)
1.48(2)
0.96 (3)
3.12(1)
2 96 (2)
1.92(3)
Effective
Date
7-1-70
7-1-70
7-1-70
7-17-72
7-17-72
7-17-72
7-17-72
7-17-72
7-17-72
7-17-72.
7-17-72
7-17-72
' Effective 7-1-75 Pri. II & III Regions must meet the limits currently established
New York1
New York City Distillate All
Residual All
Coal All
Nassau, Rockland and Oil All
Westchester Counties Coal All
Suffolk County— towns Oil All
ot Babylon, Brookhaven, Coal All
Huntington, Islip &
Smithtown
Erie & Niagara Counties Oil All
Coal All
Rest of State Oil All
Coal All
All except New York > 250 MBTUMir.
City. Nassau. Rockland Oil New
and Westchester Coal New
Counties)
020 9-26-74
0.30 9-26-74
020 9-26-74
0.37 9-26-74
0 20 9-25-74
1 0 9-26-74
06 9-26-74
1.1 10-1-75
1.7 10-1-74
2 0 9-26-74
25 9-26-74
0 75 9-26-74
0 72 (3) 9-26-74
•It Is anticipated that sulfur limits will be amended in 1976,
North
Carolina
All All New
All Existing
All Existing
1.55(1) 7-1-71 1
93 (2) 7-1-71
.96 (3) 7-1-71 i
22J 11) 7-1-71 1
2 13 (2) 7-1-71
1.38(3) 7-1-71
1 55 (1) 7-1-80
93 (2) 7-1-80
.96 (3) . 7-1-80
tor Priority 1 Regions.
All
Allen, Ashtabula.
Columbiana, Cuyahoga,
Jefferson, Lucas, Summit
' and Trumbull Counties
Belmonl Butler,
Coshocton, Erie,
Hamilton. Henry. Lake,
Lawrence, Lorain,
Mahoning, Monroe,
Montgomery, Pickaway,
Richland. Tuscarawas.
Washington and Wayne
Counties
Franklin, Hancock.
Hocking. Holmes, Knox,
Licking, Morgan, Ross,
Seneca and Shelby
Counties
Athens, Auglaize,
Carroll, Clinton.
Defiance, Fairlield.
Fayette, Greene,
Hardin. Harrison,
Highland, Huron,
Jackson, Marion,
Mercer. Miami,
Muskingum. Paulding.
Oil
Coal
OH&
Coal
Oil i
Coal
Dili
Coal
OilS,
Coal
New
^ 100 MBTU/hr.
New
< 100 MBTU/hr.
Existing
« 250 MBTU/hr.
New
< 100 MBTU/hr
Existing
S 250 MBTU/hr.
New
< 100 MBTU/hr.
Existing
S 250 MBTUAlr.
New
< 100 MBTU/hr.
Existing
« 250 MBTU/hr.
0.98(1)
0.92 (2)
0 60 (3)
0.92 (2)
0.96 (3)
1.48(2)
0.60 (3)
2.96 (2)
1.92(3)
3.70 (2)
2.40 (3)
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
2-1-74
105
-------
Table C.5-4 (Cont'd)
Detailed Federal, State and Local Sulfur Regulations
sot*
Portion of Slat*
Fuel
Type
FuelUM
Sulfur
Limit Effective
(Wl.%) Dal*
Slal*
Portion of Slat*
Fuel
Typ*
FuelUte
SuNur
Limit Effective
(Wl.%) Dal*
Ohio Sandusky. Union.
(continued) Vinton, Williams and
Wood Counties
All remaining counties
Cincinnati & Toledo
Akron
0.14
Coal
All
Oil
New
< 100 MBTU.hr.
Existing
S 250 MBTU.hr.
All
> 10.000 MBTU/hl
10-10.000 N"BTU..tlr.
4 44 (2)
288(3)
100
078(1)
1 9 to
0.78(1)
2-1-74
2-1-74
11-22-72
1-1-75
1-1-75
Pennsylvania
(continued)
Note: Hearings will be held in January 1976 on pnposed changes to make
standards generally less stringent
Oklahoma All
Oil
Coal
New
New
0 74 (2)
0 72 13)'
7-1-72
12-1-74
'The regulation prohibits any emission ol SOt tiurn existing equipment which
results in an ambient air concentration of SO* at any given point in excess ot
0 52 ppm in a five minute period of any hour..
Oregon
All
No 1 All
No. 2 All
Residual All
Coal All
03
0.5
1.75
1 0
> 150 <250MBTU.tir.
Oil
Coal
Oil
Coal
Pennsylvania Pittsburgh area
(Allegheny County,
Beaver Valley. &
Monongahela Valley Air
Basins) and Southeast
Pennsylvania Air Basin
(Bucks. Chester.
Delaware. Montgomery.
& Philadelphia
Counties)
Oils.
Coal
New
New
> 250 MBTU
New
New
< 2.5 MBTO.hr
2.5-50 MBTU iu.
1.37 (1)
1.30 (2)
.96(3)
.78(1)
.74 (2)
72(3)
370 (2)
2 40 (3)
0 92 (2)
060(3)
7-1-72
7-1-72
7-1-74
7-1-72
1-1-72
1-1-72
1-1-72
1-1-72
1-1-72
1-1-72
3-19-72
3-19-72
3-19-72
3-19-72
50-2.000 MflTu hr use Formula:
A = 1 7E-" " ivneis
A = allowable emission in pounds SOi
per million BTU neat input.
E - heal input in MBTU's per hour.
> 2.000 MBTJ/hr 0.55 (2) 3-19-72
036(3) 3-19-72
Oil*
Coal
< 2.5MBTU/11I.
2.5-50 MBTu/hr.
3 70 (2)
2.40 (3)
2 78 (2)
1 60 (3)
3-19-72
3-19-72
3-19-72
3-19-72
A = 5.1E-'" where
A = allowable emission in pounds SOi
per million BTU heat input.
E = heat input in MBTU'S per hour
> 2.000 MBTU/tu. 1.67(2) 3-19-72
108(3) 3-19-72
50-2.000 MBTu lit Use formula:
Pueno Rico
Rhode Island
South
Carolina
Philadelphia
All
• Actual percentage value
system.
All
Class I (Charleston
County)
Class II (Aiken and
Anderson Counties)
Class III (All remaining
Counties)
No 142 All
No 4 All
No. 546 All '
Coal All
All < 8 MBTU/hr.
S 8 MBTU.tir.
0.3
02
0.4
0.3
05
03
03
25
i, not to exceed 31% is assigned through
Distillate All
Residual All
Coal All
Oil « 10 MBTU/hr.
Coal * 10 MBTU/hr.
Oil > 10 MBTU/hr.
Coal > 10 MBTU/hr.
Oil . < 1000 MBTU/hr.
Coal < 1000 MBTU/tir.
Oil S lOOOMBTUrtir.
Coal » 1000 MBTUitir.
Oil All
Coal All
1.07(1)
1.02(2)
.66 (31
3.41 (1)
3 24 (2)
2.10(3)
2.24 (1)
2.13(2)
1.38(3)
3.41 (1)
3.24 (2)
2.10 (3)
224(1)
213(2)
1.38(3)
3.41 (1)
3.24 (2)
210(3)
5-1-70
10-1-76
10-1-72
10-1-76
10-1-72
10-1-76
10-1-72
1-1-75
1-1-75
the permit
5-8-74
5-8-74
5-8-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
1-30-74
Nole: Variances granted on a case by case basis.
South
Dakota
Tennessee
All
Class 1 (Sullivan, Roane.
Maury and Polk
Counties)
Oil All
Coal All
New
Oil < 250 MBTUAir.
Coal New
< 250 MBTUAr.
2.78 (2)
1.8013)
148(2)
0.96 (3)
7-10-73
7-10-73
1-1-73
1-1-73
106
-------
table C.5-4 (Cont'd)
Detailed Federal, State and Local Sulfur Regulations
Slat* Portion of Slate
Tennessee
(Continued)
Class II (Humphrey's
County)
Class III (Remaining
Counties)
All
Roane & Humphrey
Counties
Class 1 (Polk County)
Class II (Humphreys.
Maury. Roane
' Counties)
Class III (Sullivan
County)
Class IV (Shelby
County)
Class V (Anderson.
Davidson. Hamilton.
Hawkins. Knox. Rnea)
Class VI (All other
Counties)
Class IV (Shelby County)
All
Fuel
Type Fuel Die
Oil Existing
Coal Existing
Oil New
< 250 MBTU.hi
Coal New
< 250MBTU'hr.
Oil Existing
Coal Existing
Oil New
< 250 MBTU'hr
Coal New
< 250MQTb.hr
Oil NBW
> 250MBIU.hr.
Cos) Nsw
> 250 MBTU.hr
All > 1000 MBTU.hr.
Distillate > 1,000 MBTUtor.
< 1.000MBTU,h>.
Residual > t.OOOMBTUhr
< 1.000 MBTU.hr
Coal > 1 000 MBTU hi
< 1.000 MBTU.'hi.
Distillate > 1,000 MBTu.hr
< 1.000 MBTU hi.
Residual > 1.000 MBTulir
< 1.000 MBTU.hr.
Coal > 1.000 MBTU.hr.
< 1.000 MBTb.hr.
Distillate All
Residual All
Coal All
Distillate All
Residual All
Coal All
Distillate All
Residual All
Coal All
Distillate All
Residual All
Coal All
New Facslii.es
Distillate < 250MBIUhr.
Residual v 250 MBTU.hi
Coal < J50 MBTUIii.
New FaciiuiQa
Dislillate > 250 MH ru.-hi
Residual > 2SOMB1U1"
Coal > 250 MB F JIu
Sulfur
Limit
(Wl.%)
1.48(2)
0 96 (3)
2 78 (2)
1 80 (3)
2 78 (2)
1.80(3)
3.70 (2)
2.40 (3)
0.74 (2)
0.72 (3)
1.11 (2)
1.17(1)
1.56(1)
1.11 12)
.1.48(2)
72 (3)
.96(3)
1 17 (1)
488 (1)
111 (2)
4.63 (2)
.72 (3)
3 00 (3)
234(1)
2 22 12)
1.44 (3)
49(1)
2.50 (2)
2,40 (3)
390(1)
3.70 (2)
2.40 (3)
4.88(1)
4 63 (2)
300(3)
390 ID
3.70 (2)
2.40 13)
78(1)
74 (2)
.72 (3)
•Recently adopted by the Tennessee Air Politic n Control Board.
Effective
Dal*
7-1-75
7-1-75
1-1-73
1-1-73
7-1-75
7-1-75
•
1-1-73
1-1-73
1-1-73
1-1-73
9-9-74
•
Slat* Portion ol Slat*
Utah All
Vermont All
Virginia AQCR 7
Rest of State
Washington Puget Sound Area:
King. Kitsap. Pierce &
Snohomish Counties
Rest of. State
Fuel
Type Fuel Us*
Oil All
Coal All
All All
Oil All
Coal All
Oil All
Coal All
No. 1 All
No. 2 All
Oil-Other All
Coal All
Oil New
Existing
Coal All
Sulfur
Limit Effective
(WI.S) Dal*
1.50 9-26-71
100 9-26-71
2.0 3-16-75
1.03(1) 6-1-75
0.98 (2) 6-1-75
0.63(3) 6-1-75
2.57(1) 6-1-75
2.44 (2) 6-1-75
1.58(3) 6-1-75
0.30 2-21-74
0.50 2-21-74
2 00 (4) 2-21-74
1.00 2-21-74
2.00 (4) 2-24-72
2.00 (4) 7-1-75
1.70(5) 7-1-75
West The State of West Virginia Regulation 16-20. Series x. Section 3 sets SOi weight
Virginia emission standards tor fuel burning units by Priority Regions. In addition the
West Virginia Air Pollution Control Commission "strongly recommends" that the
following fuel sulfur contents be met by fuel suppliers:
•
•
Expected to
.AH
Wisconsin Southeast Wisconsin
Intraslate AQCR
Racine County
All
Oil All
Coal All
Standby Fuel: •
Distillate All
Residual All
Coal All
Oil All
Coal All
New or modified Facilities:
Distillate > 250 MBTU/hr.
Residual > 250 MBTU/hr
Coal > 250 MBTUAir.
•Standby tuel is defined as a luel normally 'used less that
1.50 6-30-75
0.50 6-30-78
2.00 6-30-75
1.00 6-30-76
0.70 4-1-72
1.00 4-1-72
1.50 4-1-72
2.31 (2) 12-15-70
1.50 (3) 12-15-70
0.78 4-1-72
0.74 4-1-72
0.72 4-1-72
15 days per year.
become effective in early 1976
Texas All
Oil All
Coal Steam Generator
0 88 (4)
1.80(3)
3-5-72
3-5-72
Wyoming All
None
107
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Table C.5-4 (Cont'd)
Detailed Federal, State and Local Sulfur Regulations
NOTES
(1) No. 1 & 2 Oil — Regulastion expressed as Ibs. S or SO./M BTU. Equivalent weight percent
sulfur calculated using 19.500 BTU/lb.
(2) No. 4, 5. & 6 OIL — Regulation expressed as Ibs S 01 SO.'M BTU. Equivalent weight per.
cent sullur calculated using 18,500 BTU/lb.
(3) Coal — Regulation expressed as Ibs. S or SO..M BTU Equivalent weight percent sultur
calculated using 12.000 BTU/lb
(4) Oil — Regulation expressed as parts per million SOi in the flue gas. Equivalent weight per-
cent sulfur calculated using 25% excess air.
(S) Coal — Regulation expressed as parts per million SO. in the Hue gas. Equivalent weight
percent sulfur calculated using 25% excess air
(6) Oil — Regulation expressed as parts per million SO, in ihu flue gas. Equivalent weight per.
cent sullur calculated using 10% excess air
(7) Coal — Regulation expressed as parts per million SO, in the flue gas. Equivalent weight
percent sullur calculated using 10% excess air.
108
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burning lower quality fuels on a variance from existing air pollution
regulations or are attempting to obtain variances or to revise the
regulations.
In a recent survey of the major residual fuel-oil burning utilities
(primarily East Coast utilities), Arthur D. Little discovered some
common attitudes and recommendations regarding current air pollution
control regulations:
• State or local standards (largely expressed as emission
standards at stack tip) are excessively stringent in
relation to the federal ambient air quality standards
(measured at ground level). As a result, local and
state regulations should be relaxed.
• Now that air quality control authorities have had several
years of experience and data on the effects of emission
and fuel quality regulations, a review of existing
regulations should be carried out with an idea to
determining if the current controls are more stringent
than necessary.
• Since meteorological conditions vary over time, perhaps
fuel quality standards should be stringent in times of
adverse conditions and more lenient during normal
conditions. To realize such a fluctuating standard,
constant air quality monitoring would be required and
fuel burners would be required to maintain adequate
supplies of high quality fuel for use when measured air
quality deteriorates.
• There is a general aversion to installing stack gas removal
systems both because of the high costs and the perception
that the current stringent emission standards may eventually
be relaxed.
109
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C.5.4.5 Air Quality Control Trends
At this point in time, the outcome of the present debate over air quality
regulations is uncertain. However, it is possible to speculate about the
broad economic and political trends which are likely to influence the
outcome. For example, in the new era of high oil prices, the added
costs of burning very low sulfur fuel oils may well trigger reviews of
the necessity for such stringent regulations. At the same time, the
country is currently very concerned with the issue of domestic energy
independence. Given the declining domestic oil and gas reserves, greater
independence implies a greater reliance on coal. To the extent that
air quality regulations prohibit the burning of coal or make it uneconomic
as a result of costly stack gas removal requirements, it is likely that
political pressure will be exerted to reexamine the necessity for current
restrictions.
None of the above comments are meant to imply doomsday for environmental
concerns. Most of the existing variances from air quality regulations
are temporary and there are areas of the country (particularly, the
East and West Coasts) which are unlikely to grant or renew further
exemptions due to the more critical nature of air pollution problems
in those areas. However, on the whole, a gradual relaxation of air
pollution regulations in areas not presently experiencing significant
air pollution conditions will likely occur over the next five years.
For some areas, this trend will mean that the regulations intended to
implement secondary standards will simply not be implemented. In other
areas, current regulations will actually become less stringent, and
these more lenient regulations may be accompanied by better monitoring
systems to assure timely response to unfavorable meteorological develop-
ments. The air quality control regulations will probably become more
sophisticated and tailored to particular locations to maximize clean
air while minimizing the cost of maintaining it.
110
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C.5.5 MANDATORY FUEL CONVERSION PROGRAM
In June, 1974, Congress passed the Energy Supply and Environmental
Coordination Act (ESECA). This act provided for the creation of the
Office of Fuel Utilization (OFU) and empowered that office to order the
conversion of electric utilities and other major fuel burning installations
to the use of coal instead of oil or gas. In its initial one-year life
span, the OFU ordered the conversion to coal of some 74 power plants in
25 different states. On June 30, 1975, the original charter of the OFU
expired. However, with the passage of the Omnibus Energy Bill in
December, 1975, the operating lifetime of the Office has been extended
through June, 1977.
In its initial conversion orders, the OFU adhered to the following
criteria in selecting utilities for conversion:
• the utility must have a demonstrated capacity to burn
fuel other than oil or gas (i.e., the utility must
actually have burned coal in the past);
• there must be a source of supply for coal which is
reasonably accessible to the utility's generating
site (for example, there must be rail or barge
receiving facilities on the generating site);
• the conversion must be "economically feasible" (here
the impact on the individual utility of not only the
conversion costs but also future fuel costs associated
with coal were taken into account); and
• the conversion to coal must leave the utility in
conformity with EPA regulations.
The first conversion orders, issued to 25 utilities covering some 32
generating stations, were subject to EPA verification that such conversion
would not cause the utilities to be in violation of primary EPA air quality
standards. Since EPA verification of compliance with air quality
standards takes three to six months from the date of issue of the original
111
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conversion order and since most of the conversion orders were issued in
the final months of ESECA charter, the EPA certification process has
been going on since July 1975, and is expected to carry on into 1976.
It is by no means certain that the EPA will grant approval of all of the
conversion orders issued by the OFU. In addition, there is an appeals
provision where the utilities or other large fuel users may request
exemption from the conversion order if they feel that compliance would
be too costly or arduous. After the utilities have received the con-
version notice and EPA certification, they will be required to begin the
actual conversion process which, it has been estimated, may take as long
as two years to accomplish.
If all of the conversions which were ordered by the OFU prior to the
expiration of that office's initial charter in June, 1975, are eventually
complied with (a very large if), it will mean an estimated savings of
some 64 million barrels per year of residual fuel oil and 88 billion
cubic feet (2.5 billion cubic meters) of natural gas. Given that
utilities accounted for 475 million barrels of residual fuel oil con-
sumption in 1974 (or 50% of total residual fuel oil demand) and 3429
billion cubic feet per day (97.1 billion cubic meters per day) of natural
gas (or 18% of total marketed natural gas production) in 1974, the
quantities of those premium fuels potentially saved by the mandatory
coal conversion program to date are relatively small. However, in
addition to the conversion orders issued to operating generating plants,
the OFU singled out 41 utilities planning to build new generating stations
and ordered them to install coal burning capability, either as the only
capacity or as dual-burning capacity.
With the passage of the Omnibus Energy Bill in December, 1975, the OFU
received an additional 18 month charter. This additional time will be
utilized to expand the conversion program to include not only utilities
but other large fuel users (primarily large industrial customers). As
with the initial conversion orders, the conversions which are mandated
during the extension period will also require EPA approval.
112
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These mandated conversions will have the effect over the long-term of
reducing residual fuel oil demand. Whether the reduced demand is for
low or high sulfur fuel oil depends on the physical location of the
converted plants, so that there is no method to estimate the actual
impact of such conversions. It is likely that by 1985, the net effect
will be small and will be overshadowed by other fuel considerations,
such as the loss of natural gas for use by utilities.
C.5.6 PROMOTION OF FUEL USE RESEARCH
The Energy Research and Development Administration (ERDA) was established
under the Energy Reorganization Act of 1974 to bring together federal
activities in energy research and development and to assure coordinated
and effective development of all energy sources. The main impetus
for its creation was the Arab oil embargo of 1973 and the heightened
realization of the serious national security implications of such a
heavy reliance on imported energy. The national goal stated by Congress
in starting ERDA, which officially came into being on January 19, 1975,
was
"...effective action to develop, and increase the efficiency
and reliability of use of, all energy sources to meet the
needs of present and future generations, to increase the
productivity of the national economy and strengthen its
position in regard to international trade, to make the
nation self-sufficient in energy, to advance the goals
of restoring, protecting, and enhancing environmental
quality, and to assure public health and safety."
In June 1975 ERDA outlined its national plan, urging five major changes
in this country's energy R&D program:
(1) Increased efforts to overcome the technical problems inhibiting
expansion of presently available energy forms, notably coal
and light water reactors.
(2) An immediate focus on conservation efforts. Primary initial
113
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targets to be automotive transportation, buildings and
industrial processes.
(3) Acceleration of commercial capability to extract gaseous and
liquid fuels from coal and shale.
(4) Inclusion of solar electricity generation among the "inexhaus-
tible" resource technologies to be given high priority.
(5) Increased attention to the commercialization of under-used
technologies which can be rapidly developed, principally solar
heating and cooling and geothermal power.
A national ranking of R&D technologies was developed to identify priori-
ties for emphasis in the plan. These priorities are as follows:
• For the near-term (now to 1985) and beyond
- To preserve and expand major existing domestic energy
systems: coal, light water reactors, and gas and oil
both from new sources and from enhanced recovery
techniques.
- To increase the efficiency of energy used in all sectors
of the economy and to extract more usable energy from
waste materials.
• For the mid-term (1985-2000) and beyond
- To accelerate the development of new processes for
production of synthetic fuels from coal, and for
extraction of oil from shale.
- To increase the use of under-used fuel forms, such
as geothermal energy, solar energy for heating and
cooling, and extraction of more usable energy from
waste heat.
• For the long-term (past 2000)
- To actively pursue those candidate technologies which
will permit the use of essentially inexhaustible
114
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resources: nuclear breeders, fusion, and solar electric
energy from a variety of technological options, including
wind power, thermal and photovoltaic approaches, and the
use of ocean thermal gradients. (None of these technologies
is assured of large scale application.)
- To provide the technologies to use the new sources of
energy which may be distributed as electricity, hydrogen,
or other forms throughout all sectors of the economy.
(For example, long-term efforts are needed to develop
a full range of electric vehicle capabilities.)
ERDA's programs are divided into six major areas: fossil energy;
nuclear energy; environment and safety; conservation; national security;
and solar, geothermal and advanced energy systems. These programs,
which include research, development, demonstration, testing and (in
the case of special nuclear materials and weapons) production, are
conducted both at the more than 50 ERDA facilities and at industrial
and university sites around the country. ERDA's capability for carrying
out broad-based programs is based on funding and personnel transferred
from R&D programs in other federal agencies: the Atomic Energy Com-
mission, Department of the Interior, National Science Foundation, and
Environmental Protection Agency. For fiscal year 1975, ERDA's budget
estimate was about $3.7 billion of which about 50% was devoted to nuclear
energy development (only 3% to fusion studies), 5% to fossil energy
development, 10% to solar, geothermal and advanced systems. Conservation,
environment and safety were to use 6% of the budget and 29% was to go
for national security. It is evident that little federal research
money is now being devoted to fossil energy problems, indicating that
problems facing fossil energy usage will probably not be mitigated
rapidly.
115
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C.6 FOREIGN FACTORS AFFECTING RESIDUAL FUEL SUPPLIES IN THE U.S.
C.6.1 INTRODUCTION
During the first nine months of 1975, the U.S. imported some 1.21 MMBCD
of residual fuel oil—this was 50% of total supply. Historical U.S.
dependence on imports of foreign source residual fuel oil is summarized
in Table C.6-1. As the table shows, domestic manufacture of residual
fuel oil, which historically has been under 1.0 MMBCD, actually increased
to 1.05 MMBCD in 1974 and to 1.23 MMBCD in 1975, largely as a result of
federally mandated pricing policies which provided some price incentives
for domestic refiners to maximize residual fuel oil sales. Peak output
was over 1.4 MMBCD in January 1975, and between February and August 1975
domestic output either was equal to or slightly greater than imports.
Besides large imports of residual fuel oil, the U.S. is also heavily
dependent on crude oil imports, which accounted for 32% of crude input
to refineries in the first nine months of 1975. This import dependency
for crude oil has increased from 19% in 1972 to 26% in 1973 and 29% in
1974. Since residual fuel oil currently represents about 10% of refinery
output, it is apparent that residual fuel oil availability in the U.S.
is heavily dependent on a variety of foreign factors—over which the
U.S. has little, if any, real control.
It is therefore important to review some of the foreign factors which
affect crude oil and residual fuel oil in the foreign environment. These
factors can be summarized as follows:
• Sources of U.S. Crude and Fuel Oil Imports
• Foreign Crude Oil Availability
• Foreign Refining Capacity
• Foreign Crude Prices
117
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Table C.6-1
Residual Fuel Oil Consumption and Imports
(MMBCD)
1969 1970 1971 1972 1973 1974 1975A
Domestic Demand 1.98 2.20 2.30 2.53 2.82 2.62 2.44
Was Met by
Imported Oil 1.26 1.53 1.58 1.74 1.85 1.57 1.21
Domestic Oil 0.72 0.67 0.72 0.79 0.97 1.05 1.23
Import Dependency (%) 64 70 69 69 66 56 50
A - First nine months
118
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C.6.2 CURRENT SOURCES OF U.S. CRUDE AND FUEL OIL IMPORTS
C.6.2.1 Crude Oil
Table C.6-2 shows U.S. imports of crude oil by country of origin for 1973,
1974 and most of 1975. Note that 78% of oil imports in the first nine
months of 1975 derived from the OPEC countries. The principal exporter
to the U.S. was Nigeria in this period, followed by Saudi Arabia and
Canada. Canadian exports have declined steadily since 1973 and are now
scheduled to phase out completely by 1981, indicating that U.S. dependence
on the OPEC countries is likely to increase significantly in the years
ahead. Dependence on OPEC exports has increased from 65% in 1973 to
78% in 1975. Other trends in future sources are likely to be a decline
in Indonesian imports as Alaskan crude oil becomes available in 1977/78
with the completion of the Alyeska pipeline and an increase in imports
from Africa. The light African crudes (produced principally in Nigeria,
Libya, and Algeria) which in 1973 accounted for 0.70 MMBCD or 22% of
imports, now account for 1.21 MMBCD or 30% of imports, as the result
of not only pressure on low sulfur crudes for the manufacture of low
sulfur residual oil but more importantly due to the declining availability
of sweet light domestic crudes in Districts II and III. We anticipate
that this trend will increase in significance in future years, as
domestic production continues to decline in the lower forty-eight states,
and imports must increasingly be directed towards refineries in Districts
II and III. District I refineries are already heavily dependent on
imported crude and District V will be the main beneficiary of Alaskan
crude oil.
C.6.2.2 Residual Fuel Oil
During the last four years, the U.S. has increased its dependence on
Western Hemisphere (particularly Caribbean) nations for imports of
residual fuel oil. As shown in Table C.6-3, 93% of 1974 fuel oil imports
originated in the Western Hemisphere, as compared to 89% in 1972. Over
119
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Table C.6-2
Sources of U.S. Crude Oil Imports
1.
2.
3.
4.
5.
Arab OPEC
of which Saudi Arabia
Algeria
Libya
Non-Arab OPEC
of which Nigeria
Venezuela
Iran
Indonesia
Toal OPEC
Other Western Hem.
of which Canada
Other
TOTAL
1973
(MMBCD) %
0.83 26
0.46
0.12
0.13
1.26 39
0.45
0.34
0.22
0.20
2.09 65
1.07 33
1.00
0.08 2
3.24 100
1974
(MMBCD)
0.72
0.44
0.18
0.04
1.83
0.70
0.32
0.46
0.28
2.55
0.86
0.79
0.07
3.48
%
21
52
73
25
2
100
Source : Bureau of Mines
1975
(MMBCD)
1.24
0.61
0.27
0.21
1.87
0.73
0.40
0.26
0.37
3.05
0.76
0.58
0.10
3.97
31
47
78
19
_3
100
A -First 9 months.
120
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Table C.6-3
Sources of U.S. Residual Fuel Oil Imports
For Domestic Consumption
1972
Western
Hemisphere
of which Canada
Europe
Bahamas
Trinidad
NWI
Venezula
Virgin Is.
Other
Other Eastern Hem.
Total U.
domestic
S. Imports for
consumption
MMBCD
1.442
0.079
0.146
0.148
0.287
0.511
0.251
0.020
0.138
0.041
1.621
%
89
5
9
9
18
32
15
1
9
2
100
1973
MMBCD
1.487
0.091
0.122
0.127
0.394
0.521
0.217
0.015
0.135
0.079
1.701
1974
% MMBCD %
87
5
7
7
23
31
13
1
8
5
100
1.
0.
0.
0.
0.
0.
0.
0.
0.
0.
1.
359
075
107
106
343
431
282
015
055
050
464
93
5
7
7
24
30
19
1
4
3
100
1975B
MMBCD %
1.
0.
0.
0.
0.
0.
0.
0.
0.
0.
1.
033
054
132
063
250
234
181
119
019
068
120
92
5
12
5
22
21
16
11
2
6
100
A -Excludes military and bonded imports.
B -First eight months (243 days).
Source: Bureau of Mines,
Fuel Oil Availability
by Sulfur Levels.
121
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the same period, imports from Europe declined from 9% to 4% of total
imports. In this period, the Bahamas, Trinidad, and Venezuela reduced
shipments to the U.S. from a combined total of 0.805 MMBCD to 0.644 MMBCD
while imports from the Netherlands West Indies (NWI) and the U.S. Virgin
Islands increased from 0.538 MMBCD to 0.625 MMBCD. Combined imports
from the NWI refineries and Venezuela amounted to 50% of the total in
1972 and 54% in 1974, while the Caribbean as a whole provided 88% of
U.S. residual fuel oil imports. The Canadian Maritimes export refineries
supplied about 5% of residual fuel oil imports in each year.
Overall, imports into the U.S. dropped by 10% between 1972 and 1974 and
apparently dropped by 23% from 1974 to 1975 if the total imports for the
year remain at a level of 1.12 MMBCD. This has happened because overall „.
residual demand has dropped from 2.6 MMBCD in 1974 to about 2.4 MMBCD
in 1975 as a result of the economic downturn and because U.S. refineries
increased residual fuel oil production by about 15% in 1975 over 1974
as a result of the price incentive caused by the federal government
price policy.
It should be noted that Table C.6-3 excludes military and bonded imports
which represent about 7-8% of total imports and come primarily from the
NWI and Venezuela.
Most of the low sulfur (less than 1.0% sulfur) fuel oil imports and
virtually all the high sulfur (greater than 1.0%) fuel oil imports
originate in the Caribbean. The combined imports from the Virgin Islands,
NWI, and the Bahamas accounted for 67% of 1975 (first 8 months) low
sulfur imports and 56% of the 1974 total. Venezuelan exports alone were
36% of 1975 high sulfur imports (42% of 1974) and combined with shipments
from the NWI and Virgin Islands totaled 79% of 1975 and 78% of 1974 high
sulfur imports to the U.S.
122
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C.6.2.3 Summary of Discussion
This review indicates the historic U.S. dependence on the Caribbean
refineries as its major source of residual fuel oil. The reason for
this is that U.S. refineries had been designed to manufacture light
products. As demand for residual fuel oil increased on the East Coast,
this product had to be imported, and the natural source was the Caribbean,
initially the Venezuelan and NWI refineries operated by the major oil
companies. Air pollution regulations, discussed elsewhere in this
report, increasingly required East Coast industry and the utilities to
burn low sulfur products. This demand prompted the construction of
increased capacity in the Caribbean to use low priced foreign crude and
the large refineries in the Bahamas (BORCO) and the Virgin Islands (Hess)
plus some further capacity in Canada and Trinidad were built to supply
this demand.
C.6.3 FOREIGN CRUDE OIL AVAILABILITY
C.6.3.1 Recent Import Forecasts
As is pointed out in Chapter C.7, the U.S. will, according to all fore-
casts, become increasingly dependent on foreign source oil. While there
is some degree of disagreement between forecasters as to the level of
dependence, there is fundamental agreement by all forecasters about the
basic trend which can be clearly seen in a recent forecast by Exxon shown
in Table C.6-4. Exxon's forecast shows that actual oil imports in 1974
amounted to 6.1 MMBCD and that estimated imports in 1975 will be at a
level of 6.5 MMBCD. Exxon sees a tremendous increase in imports to 8.0
MMBCD in 1976 and 9.2 MMBCD in 1977, prior to Alaskan oil coming onstream.
Thereafter, the growth in oil imports, although curtailed, increases by
over 2% per year to reach 12.2 MMBCD by 1990. We should note that this
forecast was made prior to the Energy Policy and Conservation Act of
1975 becoming law. Most observers feel the new law will have the effect
of inducing increased oil demand because of the lower price levels mandated
for domestic crude oil. Due to the entitlements provisions, lower domestic
crude prices translate into lower oil product prices throughout the
123
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Table C.6-4
Exxon's Forecast of U.S. Energy Demand
MMBCD Oil Equivalent
Actual
Outlook
Total Energy Demand
of which:
Natural Gas
Coal
Non-fossil
OilA
of which:
Domestic Production
Oil Imports
£
Import Dependency (%)
B
1973
37.4
11.7
6.6
1.8
17.3
11.0
6.2
36
1974
36.7
11.4
6.5
2.2
16.6
10.5
6.1
37
1975
36.3
10.7
6.5
2.4
16.7
10.0
6.5
1980
41.9
9.4
8.3
3.9
20.3
9.6
10.5
1985
47.8
9.6
9.7
6.6
21.9
10.8
10.8
1990
56.0
9.7
11.4
10.4
24.5
11.9
12.2
39
52
49
50
A - Local Demand excluding exports.
B - Crude condenstate, NGL and synthetics.
C - Imports divided by oil demand.
Note; Domestic production and imports do not add to oil demand because of
net processing gain.
Source: Exxon Press Briefing, December 9, 1975.
124
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country, thus increasing the likelihood of increased consumption. This
incremental demand cannot be met quickly by domestic sources and must
therefore add to the import burden so that the Exxon forecast could well
be a conservative statement as to import needs. The levels of oil
import dependency shown in the Exxon forecast increase from 36% in 1973
to 39% in 1975, 52% by 1980, and thereafter remain at or slightly below
50% through to 1990.
An alternate view of future dependency is provided in Table C.6-5 which
is from a May 1975 study published by the Petroleum Industry Research
Foundation, Inc. (FIRING) entitled "Electric Power and U.S. Oil Import
Dependency: An analysis of the President's targets for nuclear
generating plants and oil imports in 1985". This study is much more
optimistic about future domestic oil production than the Exxon outlook,
in that it shows a potential 1985 production of 13.9 MMBCD versus only
10.8 MMBCD in the Exxon forecast. Note also that the FIRING forecast
of demand is 0.5 MMBCD less than that of Exxon. As a result of these
two factors, FIRING'S imports are at 7.0 MMBCD, showing an import
dependency level of only 33% in 1985.
In our view, the FIRING forecast of domestic production is optimistic
since it implies a heavy investment in secondary and tertiary recovery
(implicitly assuming no effective price control on old oil from enhanced
recovery) and the full development of the Gulf of Mexico's offshore areas.
The forecast also assumes the commencement of production from the Atlantic
OCS and new production from South Alaska and California offshore areas,
as well as 2.5 MMBCD from the North Slope. We believe that most experts
concur that 13.9 MMBCD of domestic production in 1985 is extremely
optimistic given that price controls have now been continued for a
further 40 month period. In our view, the import dependency is more
likely to tend towards the 50% level seen by Exxon.
Another view on future imports is provided by a recent Library of Congress
study by Dr. Herman T. Franssen which also gives an indication of where
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Table C.6-5
FIRING Forecast
Projected U.S. Oil and NGL Supply 1985
(million b/d)
Production from Existing Areas 10.0
Outer Continental Shelf 1.0
(Atlantic and Pacific)
Prudhoe Bay and Other North Slope 2.5
Synthetic Oil Production .4
(Shale oil and coal liquefaction)
Source: PIRNIC, May 1975.
Total Domestic Production 13.9
Refinery Processing Gains .5
Total Supply from Domestic Sources 14.4
Required Imports 7.0
Total Supply (Demand) 21.4
Oil Import Dependency 33%
126
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future oil imports might come from. In this forecast, shown in Table
C.6-6, dependence on the Arab countries of the Middle East and North
Africa will increase from 1.05 MMBCD in 1974 (16% of total oil imports)
to between 34% and 42% in 1985 representing between 2.9 and 4.2 MMBCD.
By adding Venezuela, Iran, Nigeria and Southeast Asia (primarily
Indonesia) to these totals, we can see that the U.S. was apparently
dependent upon OPEC countries for 65% of 1974 product and crude imports,
and by 1985 Dr. Franssen is forecasting a dependency on OPEC nations
of between 76% and 80%. The Library of Congress study shows total
imports of 8.5-9.9 MMBCD by 1985 which, coupled with the 21.0-22.4 MMBCD
oil demand in 1985, indicates an import dependence of 40-44%.
C.6.3.2 World Oil Production Potential
Against these forecasts of potential imports, we can examine current
and likely future trends in world oil production to determine whether
these import levels are likely to be attained. The FEA monitors crude
oil production in the major exporting countries and we reproduce in
Table C.6-7 the statistics shown in the November 1975 FEA Monthly Energy
Review. The table shows that most major exporting countries are currently
producing at levels considerably below capacity, and that OPEC as a
whole was about 25% under capacity in August 1975. Kuwait was estimated
to have 40% of capacity shut-in in August, Libya 30%, Qatar 41%, Saudi
Arabia 28.6%, Nigeria 29.6%, and Venezuela 26.5%. Other countries which
can be characterized as those with greater relative income requirements,
have much less capacity shut-in, with Algeria at 10% being the least
affected.
Since the major price increases of 1973/74, the OPEC member states have
faced severe strain in coping with the over-supply situation caused by
reduced demand due to the price increases and the worldwide economic
recession. As a consequence, the demand for OPEC crude has been much
reduced. Certain countries such as Kuwait and Libya have voluntarily
reduced production on the grounds of conservation and in pursuit of
political ends. Others have lost volume because of disparate pricing
127
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Table C.6-6
Forecast of U.S. Oil Imports
By Region
(MMBCD)
1974
1977
1980
1985
Western Hemisphere
Canada
Venezuela
Other
Middle East & N. Africa
Iran
Arab Countries
Eastern Hemisphere
Nigeria
Other Africa
Southeast Asia
Total
3.1
1.1
1.2
0.8
1.5
0.5
1.0
1.1
0.7
0.1
0.3
5.7
2.7
0.4
1.1
1.2
4.5 - 4.7
0.8
3.7 - 3.9
1.3
0.8
0.1
0.4
8.5 - 8.7
2.6
0.1
1.0
1.5
5.1 - 5.7
1.0
4.1 - 4.7
1.8
1.0
0.2
0.6
9.5 - 10.1
2.7
-
1.0
1.7
3.8 - 5.2
0.9 - 1.0
2.9 - 4.2
2.0
1.0
0.3
0.7
8.5 - 9.9
By Comparison
Exxon Totals
6.1
9.2
10.5
10.8
Sources: Dr. H. T. Franssen, Library of Congress Study
Note that total oil imports in 1974 do not agree with Exxon's assessment.
128
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Table C.6-7
Crude Oil Production
Crude Oil Production for Major Petroleum Exporting Countries - August 1975
Country Production
1973 1974 1975 August
(8 months)
In thousands of barrels per day
Algeria
Iraq
Kuwait*
Libya
Qatar
Saudi Arabia*
United Arab Emirates
Subtotal: Arab OPEC
Ecuador
Gabon
Indonesia
Iran
Nigeria
Venezuela
Subtotal: Non-Arab OPEC
Total: OPEC
Canada
Mexico
Total: OPEC, Canada,
Mexico
Total World
'Includes about one-half of Neutral Zone production which amounted
August.
Source: Central Intelligence Agency.
Production Capacity
August
1,070
1,964
3,024
2,187
570
7,607
1,518
17,940
204
147
1,339
5,861
2,053
3,364
12,968
30,908
1,798
465
33,171
55,715
940
1,820
2,550
1,520
520
8,480
1,680
17,510
160
180
1,380
6,040
2,260
2,970
12,990
30,500
1,695
580
32,775
55,855
922
2,211
2,110
1,384
423
7,014
610
15,674
155
210
1,266
5,441
1,695
2,475
11,242
26,912
1,440
785
29,141
52,869
900
2,260
1,960
2,100
410
8,210
1,870
17,710
210
210
1,380
5,510
1,760
2,280
11,350
29,060
1,520
840
31,420
55,360
1,000
2,600
3,500
3,000
700
11,500
2,400
24,700
240
250
1,700
6,500
2,500
3,100
14,290
38,990
2,016
840
41,846
Production Shut in
August
In percent
10.0
13.1
44.0
30.0
41.4
28.6
22.1
28.3
12.5
16.0
18.8
15.2
29.6
.26.5
20.6
25.5
24.6
0
24.9
to approximately 530,000 barrels per day in
Source: FEA Monthly Energy Review, November 1975.
129
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practices—from time to time the liftings of Abu Dhabi, Algeria, Nigeria,
Venezuela and Indonesia have been affected for this reason. Since mid-
1974, OPEC members have been discussing how to institute a more formal
method to achieve consistency between relative crude oil prices so as
to ensure that income requirements can be met.
C.6.3.2.1 Relative Crude Oil Pricing Considerations - Relative crude
oil prices are of importance because of their effect on OPEC and because
of the relative merits of heavy and light crudes.
Unless OPEC members can institute a system to control the actions of
individual states, there is the distinct possibility of rapid and un-
controlled price deterioration because of the current and projected
crude oil over-supply position. A situation could emerge, in other
words, in which individual producing countries, because of their short-
term revenue requirements, would continually discount prices in order
to achieve volume. Unless a major producer is prepared to act as a
flywheel on production, increasing it with demand and decreasing it
to equate supply to decreased demand, then pricing cohesion could fail.
In practice, Saudi Arabia has informally acted as the flywheel on OPEC
production, essentially enabling other members to produce according to
national ambitions, and agreeing to slow down its own production, al-
though as shown in Table C.6-7, other member countries have also
voluntarily reduced production by significant amounts.
Relative crude oil prices must also by definition address the question
of heavy crude prices versus light crude prices. This is vital to future
product price relationships and in particular to future price trends for
residual fuel oil, since the yield of fuel oil from a heavy crude is
much greater than that from a light crude (for example, to take two
extremes, 13° API Venezuelan Bachaquero crude has a residual fuel oil
yield of almost 78% versus a 27% fuel oil yield from a 44" API Algerian
crude oil). These considerations have been of great importance in
recent price trends for residual fuel oil since the economic recession
130
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has selectively hit heavy industry and utility demand for residual fuel
oil, thereby causing substantial oversupply of residual fuel oil and
reducing the demand for heavy crudes. Meanwhile, light product demand
has increased causing the value of light crudes to increase. OPEC
members have in some instances been noticeably slow to react to these
market trends, and Venezuela, for example, reportedly now holds large
volumes of unsold residual fuel oil. Since further analysis of historic
and future crude oil price trends follows in Section C.6.5, suffice it
to say here that most observers believe that so long as Saudi Arabia,
a producer of both light and heavy crude oils, is prepared to accept
the balancing role, then OPEC will be able to hold prices at least at
current levels, despite the current oversupply position.
C.6.3.2.2 Recent Foreign Crude Forecasts - Exxon's World Energy Fore-
cast (referred to above) shows oil supply in the free world increasing
from 49 MMBCD in 1974, to 59 MMBCD in 1980, and to 78 MMBCD in 1990.
Exxon estimates that OPEC supplied 31 MMBCD or 63% of total world
supplies in 1974, which will increase to 47 MMBCD (60%) in 1990. Thus,
free world dependency on OPEC (as currently defined) will increase
throughout this period, at the rate of 2.64% per year, slightly under
the growth in oil demand estimated at 2.95% per year (which accounts
for the slight decrease in dependence in % terms). The Exxon projection
of oil availability is shown in Figure C.6-1. Note that this forecast
is one of the few publicly available documents of this nature.
Exxon also estimates that of the total 78 MMBCD of oil required by the
free world in 1990, about two-thirds will derive from existing reserves
and about one-third will come from projected new discoveries. Known
resources in the U.S., Canada, and Western Europe are expected to cover
only about 10% of the world's needs in 1990.
In commenting on these future requirements, Exxon notes that OPEC's
production peaked at about 32 MMBCD in the two quarters immediately
preceding and following the 1973-74 embargo. By 1977, OPEC production
131
-------
Figure C.6-1
bo
N)
80
70
60
50
40
30
20
10
i
0
°~ 0
49
31
WORLD* OIL SUPPLY
MILLION BARRELS/DAY
78
59
37
47
OTHER
NON-OPEC
& EUROPE
/&USA 8
^CANADA
<|NET IMPORTS
78
34%
56%
10%
FUTURE
DISCOVERIES
DISCOVERED
BOTHER
A U.S., CAN.
V
. EUR.
1974-
I98O
1990
EXCLUDING COMMUNIST AREAS
Source: Exxon
-------
is forecast to again surpass this peak level and by 1990, OPEC will
be looked upon to supply 47 MMBCD. However, only a handful of countries
have reserves which can support the increased production and most notably
Saudi Arabia will be called upon to supply the bulk of this rapid increase
in demand. Saudi Arabia is generally expected to have a production
capacity of 16 to 18 MMBCD by the late 1970's. Exxon anticipates, how-
ever, that beyond 1985 the Arabian Gulf producers as a whole are likely
to be approaching the upper limits of their resources and production
capability may therefore become limited by the resource base. This
leads directly to the question of future trends in crude oil prices
which will be discussed later.
C.6.3.3 Summary
In summary, the future policies of the main producing countries will
have a significant impact on oil availability and price. Because of
its increasing oil dependency, and in particular because of historic
and future residual fuel oil supply patterns, U.S. supplies of residual
fuel oil will be particularly subject to OPEC oil supply and pricing
actions.
C.6.4 FOREIGN REFINING CAPACITY
As was shown in C.6.2.2. 88% of the residual fuel oil imported into the
U.S. in 1974 derived from Caribbean refineries. Apart from Venezuela,
most of the crude oil currently processed in the Caribbean derives from
OPEC countries in North and West Africa and the Middle East. With
forecast declines in Venezuelan crude oil production, the Middle East
and African crudes will form an increasing part of the crude slate for
these refineries. In Table C.6-8, we have summarized the refining
capacity available in the U.S. and its traditional product supply areas.
The figures are based on assessed existing capacity plus an analysis
of announced expansions.
Exxon estimates (Table C.6-4) total U.S. product demand in 1975 at 16.7
133
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Table C.6-8
U.S. Domestic, Canadian Maritimes and Caribbean Exports
Refining Capacity
(MMBCD)
1975 . 1980
U.S. Domestic 14.75 17.49
Canadian Maritimes Export 0.22 0.29
Caribbean Export 3.68 3.85
Total 18.65 21.63
Source: FEA, Canadian National Energy Board
Petroleum Times Hydrocarbon Processing, Oil & Gas
Journal, Platts and ADL estimates.
A - The figures shown for the Canadian Maritimes and the Caribbean are
the result of an assessment of total refining capacity less local
demand to give the capacity "available" for product exports.
134
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MMBCD and 20.3 MMBCD in 1980. The forecast refining capacity in 1980
as shown in Table C.6-8 indicates that U.S. domestic refineries will
be incapable of meeting U.S. product demand in 1980 by about 15% (versus
13% in 1975).
Thus the U.S. will continue to be heavily dependent upon foreign refinery
capacity. Here we should note that the Administration has an announced
intention to reduce U.S. dependency on refined product imports. In fact,
the FEA is believed to be currently undertaking studies to determine the
fee differentials to be applied to product imports which will discourage
such imports, and consequently which will encourage the building of
incremental domestic capacity to supply U.S. requirements. It is diffi-
cult to speculate about the effect of such policy changes since there is
currently such a surplus of refining capacity worldwide. Further, it
can be expected that many of the Caribbean refiners, who are U.S. com-
panies, will vigorously oppose moves by the Administration which place
them in an unfavorable competitive position. We should also note that
current policy in fact favors onshore refining, without the imposition
of any new fee differentials, because of the entitlements program and
the discontinuation of the supplemental crude import fee.
Referring again to Table C.6-8, if we assume that U.S. refineries can
produce a 10% residual fuel oil yield, that Canadian Maritimes exports
are 50% residual fuel oil and the Caribbean 70%, then the potential
capacity for residual fuel oil manufacture is over 4 MMBCD in 1975,
against a currently estimated demand of about 2.5 MMBCD, indicating
surplus refining capacity. In fact, Caribbean refineries have suffered
severe capacity problems in 1975 and many are believed to have been
operating at uneconomic throughput levels. By 1980 it is estimated
that there will be 4.6 MMBCD of residual fuel oil manufacturing capacity
which indicates that this area's residual fuel oil manufacturing capacity
will also be adequate in 1980 to meet U.S. demand, which would have to
increase at something over 12%/year to fully utilize the apparently
available capacity of 4.6 MMBCD. We tend to feel that it will not be
135
-------
until towards the mid-1980fs that new capacity will actually be required
to meet U.S. product demand and the same would appear to be true of
residual fuel oil. Note that the above excludes consideration of residual
fuel oil imports from Europe or from the new export refineries which may
be built in some Middle East and African exporting countries such as
Saudi Arabia, Iran, Libya, Algeria, and Nigeria.
The forecast over-capacity in refining will have an impact on manufacturing
costs in that refiners will presumably be unable to recover fully-allocated
manufacturing costs (including capital costs) during this period. Until
there is a capacity shortage, full cost recovery will not take place and
product price trends are likely to reflect marginal manufacturing economics.
Besides refineries, the oil industry requires ships to move crude oil
and refined products. The above conclusions about over-capacity in
refineries and the consequent inability of refiners to pass on full costs
appears to also be true of tanker freight rates (or costs). By the end
*
of October 1975, the world oil tanker fleet of vessels of over 10,000
deadweight tons (dwt) consisted of 3,457 ships with a total capacity
of 278.4 million dwt. In addition, some 22.4 million dwt of combined
carrier capacity which is actually used in the oil trades must be added
to obtain a total oil carrier fleet capacity of 300.8 million dwt. Of
this total oil-carrying fleet, 42.9 million dwt were currently laid-up
and a large part of the remaining fleet was estimated to be under-utilized.
Freight rates have reached extremely low levels and the current spot rate
for transporting crude oil from the Persian Gulf to the Caribbean in a
VLCC (very large crude carrier, i.e. a ship larger than 160,000 dwt) is
of the order of $0.40/Bbl which can be compared to $2.50/Bbl in mid-1973
for the same movement. Moreover, there were 125 million dwt of tankers
Tanker tonnage statistics are from H. P. Drewry's "Shipping Statistics
and Economics".
A "deadweight ton" is one long ton of ship-carrying capacity and is equal
to 1.016 metric tons. Since deadweight tons are used universally for ship
size designation, such measures will not be converted to metric equivalents.
136
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on order as of the end of October 1975, and almost 9 million dwt of
combined carriers. This tremendous fleet expansion had been predicated
upon expected exponential increases in oil demand, and on the premise
that incremental crude oil would have to be moved from the Persian Gulf.
The 1973/74 price increases and the slowdown in oil demand growth rates
have thrown both these assumptions awry and most observers now feel
that it will be at least the early 1980's (if not later) before tanker
supply and demand are again in balance, indicating that there will be
several years of very low freight rates in the interim. These low
freight rates will, in turn, be reflected in relatively low product
prices, including those for residual fuel oil.
C.6.5 CRUDE PRICE CONSIDERATIONS
The major component of the price of residual fuel oil is the cost of
the crude oil, and since the U.S. is so dependent upon imports of
residual fuel oil and on imported crude oil, a primary factor which
needs to be considered is the foreign crude oil price. However, current
price legislation means that the full cost of foreign crude oil is not
necessarily reflected in residual fuel oil prices, because of the effect
of the Entitlements Program. In this section, we shall look at (a) the
potential effect on price of current U.S. legislation, (b) historic
crude oil prices, and (c) possible future crude oil price trends.
C.6.5.1 The Effect of Current U.S. Crude Oil Price Legislation
The cost of fuel oil which would be calculated from consideration of
foreign crude oil cost plus refining and transportation costs must be
modified to reflect current U.S. policy. For example, the imposition
by the U.S. of import duties, import license base fees and the like
increase fuel oil costs above international levels; so also will the
compulsory storage program which has been mandated to provide protection
from short-term disruptions of supply. The cost of domestic fuel oil
is also substantially affected by the crude oil Entitlements Program
and price controls on domestic crude oils. The Energy Policy and Con-
137
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servation Act of December 1975 will roll back U.S. crude oil prices
from current levels and thereafter will allow crude prices to increase
at up to 10% per year. Proposed detailed regulations for the adminis-
tration of these provisions have just been issued by the FEA which
administers these programs. As applied to residual fuel oils, the
general effect of the new legislation, like the preceding regulations,
appears likely to establish a raw material cost basis comprising a
mixture of lower-priced domestic crude oil and higher-priced foreign
crude oil.
By way of illustration of the impact of these governmental actions,
the following figures have been developed. Imports currently account
for about 35% of U.S. crude consumption and are delivered to the U.S.
at about $13.00/Bbl. Domestic crude oil accounts for 65% of U.S. crude
runs and, under the new legislation, is price-controlled at an average
of $7.66/Bbl. This results in an average U.S. crude oil cost of $9.53/
Bbl (0.65 X $7.66 + 0.35 X $13.00). The Entitlements Program is designed
to cause all U.S. refiners (with some exceptions for small refiners) to
have essentially equal crude costs. Thus, a domestic refiner without
access to any domestic crude oil sells 0.65 entitlements (he is 65%
under the average usage of domestic crude), worth the difference between
the domestic crude oil price and the foreign crude oil price ($13.00 -
$7.66 = $5.34), receiving $3.47/Bbl (0.65 X $5.34) in cash. This
refiner's net crude oil cost then becomes the foreign crude oil price
less the value of his entitlements ($13.00 - $3.47= $9.53). Conversely,
the refiner who processes 100% domestic crude oil buys $1.87/Bbl worth
of entitlements (0.35 X $5.34) and his crude cost becomes $7.66 plus
$1.87 equal to $9.53, or the same as the refiner processing 100%
foreign crude oil. The effect is to set a crude oil cost for refiners
covered by the Entitlements Program below that of a foreign refiner
which is not covered. This advantage translates directly into lower-
cost fuel oil as illustrated in Table C.6-9 which shows residual fuel oil
costs calculations including and excluding entitlements when the fuel oil
is produced in the Caribbean. It is very important to point out that the
138
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Table C.6-9
Illustration of Delivered Cost of Residual Fuel Oil (2.8% Sulfur)
With and Without Entitlements Based on Arabian Light Crude Oil
Refined in the Caribbean ($/Barrel)
With Entitlements Without Entitlements
CO
vo
f.o.b. Crude Oil Price (Saudi Arabian light)
Tanker to Caribbean
Delivered Crude Oil Cost
B
Entitlement Value
Net Crude Oil Cost
Refining Cost
Residual Fuel Oil Cost Ex-Refinery
D
Tanker to East Coast
E
Customs Duty
Residual Fuel Oil Delivered Cost
$11.51
1.00
$12.51
3.47
$ 9.04
(0.50)
$8.54
0.40
0.05
8.99
$11.51
1.00
$12.51
$12.51
(0.30)
12.21
0.40
0.05
12.66
A-Based on average (AFRA) rate for December 1975 for VLCC class Tankers (160,000 DWT Plus).
B-Using domestic crude price average of $7.66/Bbl.
C-Using full cost recovery for 1974 refinery; the negative refinery cost for 2.8% sulfur fuel oil reflects the
allocation of a negative cost to this product by the LP simulation model, since high sulfur fuel is valued
below crude oil cost.
D-Based on average (AFRA) rate for December 1975 for medium-size tankers (30,000 DWT).
E-Assumes fee free imports.
-------
cost to the nation is not the entitlements-adjusted cost of crude oil
but the full import cost. The Entitlements Program simply spreads this
additional cost across all products and across all regions.
Clearly, a number of uncertainties surround how U.S. policy will evolve
in the future, particularly when the federal legislation expires 40
months from now. Beyond this, however, there is the uncertainty as to
how current legislation will apply to the historic suppliers to the
U.S. East Coast fuel oil market. For example, will the benefits of
the Entitlements Program be received by foreign Caribbean refiners
which have been the major source of U.S. residual fuel oil supplies
in the past?
C.6.5.2 Historic Crude Oil Prices
As shown in Table C.6-9, the cost of crude oil accounts for over 90%
of the cost of producing 2.8% sulfur residual fuel oil. Although the
costs of refining and tanker transportation have increased rapidly
in recent years under the impact of inflation, crude oil price increases
have been truly explosive. This is shown in Figure C.6-2, where the
f.o.b. price of Arabian Light crude oil is compared with the average
U.S. refinery acquisition cost of domestic crude oil.
Prior to 1971, the f.o.b. price of Arabian Light crude oil was about
$1.30/Bbl and the price delivered to the U.S. was about $2.00/Bbl.
U.S. crude oil prices were higher, a little over $3.00/Bbl, and were
maintained by a combination of import restrictions and individual state
(notably Texas) production controls. International crude oil prices
increased rapidly starting in late 1970. While there is some controversy
over the role played by the various participants in the international
oil scene which resulted in these price increases, there is little doubt
that the price increases reflected the growing market power of the OPEC
nations who currently control about two-thirds of free world published
oil reserves and about 60% of free world production.
140
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0)
k.
i_
TO
CD
W
aj
o
i
6
01
T5
O
i <:
11
10
9
8
7
6
5
4
2
1
0
Arabian Light Contract
Price -^^^
FOB RasTanura^"""*-
_
~~ . U.S. Average Wellhead Price
\
1 J
\
]
—
1 f 1 1
fj
r-—J"
.
J
r-rj F
J \ .
U.S. Average Refinery
Acquisition Cost of
Domestic Crude Oil
•• •
New Average
Domestic Wellhead Price
1
1969
1970
1971
1972
1973
1974
1975
Source: U.S. Crude Prices: Bureau of Mines
Federal Energy Agency
Arabian Light Prices: Arthur D. Little, Inc., estimates.
Figure C.6-2 - HISTORY OF CRUDE OIL PRICES
(Annual Averages Prior to 1974, Monthly Thereafter)
141
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The succession of crude oil price hikes in the post-1969 period were
triggered off by rising prices for finished petroleum products which
in turn reflected shortages in one or more of the elements in the
integrated petroleum chain; these elements being production, trans-
portation, and refining. In each case, the producing countries took
advantage of the high product prices by raising taxes and later by
partially or completely nationalizing the operations of the oil
producing companies. The key events can be summarized as follows:
• In September 1970, following a rapid rise in spot tanker
rates, which, in turn, reflected a shortage of tanker
capacity, European product prices rose rapidly. Libya,
which was in part responsible for the tanker shortage
through having cut back production of its "short-haul"
crude which then had to be replaced by "long-haul" crude
from the Middle East, was able to negotiate a new fiscal
package with the oil producing companies holding explora-
tion and production concessions within its territory.
The Libyan success led the Middle East countries to seek
comparable tax increases and they successfully concluded
the Teheran Agreement in February 1971, which called for,
among other things, a 5-year built-in increase of taxes
(the levels of which, in retrospect, now seem modest).
Libya, in turn, dissatisfied with its increases in light
of the new Teheran Agreement, went back to the table and
successfully negotiated a new tax package, embodied in
the Tripoli Agreement of March 1971. This was followed
by a succession of agreements related to currency
escalation, culminating in the participation agreements
of 1973, in which the producing countries acquired partial
ownership in their concessionary companies and the right
and obligation to market increasing quantities of crude
oil directly.
• In spite of what were then regarded as large increases in
crude prices, which brought the f.o.b. price of the marker
142
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Saudi Arabian Light crude to $2.30/Bbl by mid-1973, the
rapid worldwide growth of oil consumption during 1973
again placed strains on tanker capacity (and, to a lesser
extent, refining capacity). Tanker rates increased
rapidly and product prices followed. The producing
countries took advantage of this market development by
unilaterally setting crude oil prices and virtually
relegating their concessionary companies to contractor
status. Following the October 1973 Arab-Israeli war and
the Arab embargo which followed, product prices sky-
rocketed and the price of Arabian Light crude oil was
subsequently fixed at $10.46/Bbl, about 8 times what
it had been a little more than 3 years earlier.
The combined effects of the high oil prices and the
worldwide recession brought about a decrease in oil
consumption during 1974 and 1975, at the same time
as new refining capacity and tanker capacity were
becoming operational to deal with anticipated but
unrealized historic rates of growth in oil demand.
Refinery margins (the difference between the weighted
average price of finished petroleum products and the
cost of crude), instead of being at cost-based levels,
were barely able to cover out-of-pocket costs in many
parts of the world. The same was true of tanker trans-
portation. Freight rates dropped precipitously to levels
which covered only fuel costs and port charges (i.e.,
not even enough to cover crew costs, insurance, finance
and investment charges). Product prices, in relation
to crude prices, dropped to historic lows. Residual
fuel oil was particularly hard hit since demand for
this product which is heavily dependent on industrial
activity dropped the most sharply. In spite of the
depressed demand conditions, however, the OPEC countries
143
-------
in October 1975 successfully raised the price of the
marker crude by 10% from $10.46 to $11.51/Bbl using
as one justification the continued inflation in the
price of the goods and services they buy from the
consuming countries.
Following the OPEC price increases, there was turmoil in U.S. crude oil
markets and federal price controls were modified to recognize two
categories of crude oil: "old oil" which was price controlled at $5.25/Bbl
and "new oil" which was free to rise to international levels. The
intention of the regulations was to hold average domestic crude oil
prices down while still providing an incentive to find additional oil
in the new oil category. Based on FEA statistics as of August 1975,
new oil represented about 40% of domestic supply and the average old
oil/new oil price was $8.48/Bbl. Under the new Omnibus legislation
which reflects a compromise between Administration and Congressional
views, the weighted average price of domestic oil has been fixed
initially at $7.66/Bbl (for the combination of old and new oil). This
regulation, in effect, puts a limit on the new oil prices. The legisla-
tion also provides that the weighted average oil price can increase by
up to 10% per year, at the President's discretion.
C.6.5.3 Possible Future Crude Oil Price Trends
The OPEC nations, in announcing their 10% price hike in October 1975,
agreed to hold the marker crude price (for Saudi Arabian Light) constant
at $11.51/Bbl for the next 9 months. The OPEC nations are, however,
becoming increasingly concerned about price relationships between the
marker crude and crudes of differing quality and locations. Currently,
heavy crudes (those containing a high proportion of residual fuel oil)
are under pressure because of the decline in demand for fuel oil. Also,
crudes closer to market have seen their geographical premium eroded by
the decline in freight rates. Crude oil of all qualities is in abundant
supply, given the failure of demand growth following the 1973/74 price
hikes, and consuming countries have tended to become more complacent
144
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about security of supply. The major industrialized nations, within the
context of the newly-formed International Energy Agency, have, however,
agreed to a system of crude oil sharing in the event of supply inter-
ruptions and to protect investments in the development of alternative
energy supplies, have agreed to institute policies creating a minimum
domestic safeguard price of $7/Bbl for imported crude oil.
In general, the collapse of the international monetary system which
some believed might result from a huge build-up of currency reserves
by the OPEC members no longer seems to be a serious threat. The con-
suming countries have shown a surprising ability to absorb the OPEC
price increases although their economies have been slow to recover from
the 1974/75 recession. Many observers had projected that consuming
countries would have much greater difficulty in absorbing the 1973/74
price increases than actually occurred. Thus, future oil price increases
probably could be absorbed as well.
The availability of low sulfur crudes is ample and individual consuming
countries are no longer bidding for supplies. However, a continuation
of this situation is dependent on the production policies and political
stability of one or two countries, particularly Libya and Nigeria, and
could change dramatically if demand for low sulfur fuel oil increases
or if production in these countries is cut back for any reason.
It is our view, in summary, that the OPEC nations, in spite of current
conditions, will be able to hold the current level of prices. To some
extent, this is dependent upon member nations reaching a concensus view
on relative crude oil prices and on crude production balancing. Saudi
Arabia and certain other nations appear to be able to balance production,
and since we believe that world demand will increase, the problem of over-
capacity will tend to be minimized. Thus, for the next several years,
OPEC members will seek to achieve price increases which at least maintain
the real price of oil. Given that international inflation is likely to
be at least at a level of 5% in the next several years, we would anticipate
145
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prices increasing by this amount. We would expect these price increases
to be fully reflected in residual fuel oil prices in the U.S. absent the
effect of any mandated lower domestic price, and an averaging program such
as is currently in existence. In the long-term, by the mid-1980's, we
would anticipate that as oil reaches resource limits, and as one or more
capacity constraints (in refining, production or transportation) becomes
apparent, that OPEC will be able to capitalize this into a quantum increase
in price. Of course, this could happen in the much shorter-term and as
a result of unforeseen political events.
146
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C.7 ENERGY PRODUCTION TRENDS
C.7.1 INTRODUCTION
In this chapter we discuss the future production trends for four energy
sources
• Domestic crude oil
• Foreign crude oil
• Natural Gas
• Coal
We have included coal because it is in many ways the only alternate
for fuel source to residual fuel oil. Our discussion of natural gas
is included because it has been an important boiler fuel whose replace-
ment in the future with other energy sources will impact heavily on
the demand for residual fuel oil.
C.7.2 DOMESTIC CRUDE OIL PRODUCTION
In this section we first establish a framework for discussing crude
oil production, then describe the current situation and end by dis-
cussing projections of future domestic crude oil production
C.7.2.1 Recent Statistics on U. S. Oil Production
United States year-end proved reserves and annual production are de-
clining as is shown in Table C.7-1. With the Prudhoe Bay field dis-
covery excluded from the totals, proved reserves in the U. S. have de-
clined every year since 1966. Decreasing total U. S. reserves are the
result of the general decline since 1965 of annual additions to reserves
147
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Table C.7-1
Statistics on U.S. Domestic Crude Oil
(Excluding Prudhoe Bay in Alaska)
Year
Proved Reserves
at Year End
(Million Barrels)
Annual Additions Annual Indicated Year's
to Production Supply of Yr. End
Proved Reserves (Million Barrels) Proved Reserves
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
31,352
31,452
31,377
30,707
29,632
29,401(1)
28,463(1)
26,734(1)
25,700(1)
24,650(1)
NA
3,048
2,964
2,962
2,455
2,120
3,089(1)
2,318
1,558
2,146
1,994
NA
2,849
3,028
3,216
3,329
3,372
3,518
3,454
3,455
3,361
3,203
3,055
11.0
10.4
9.8
9.2
8.8
».*™
8.2(1>
7.7(1)
7.6<»
7.6(1)
NA
(1) Figures exclude 9,600 million barrels located at Prudhoe Bay, Alaska
which cannot be produced prior to the 1977 completion of the Trans
Alaskan Pipeline.
NA - Not available at time of writing.
Source: American Petroleum Institute
148
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and the continued high production from existing reserves at the maximum
*
efficient rate. U.S. crude production continued to increase until 1970
but has declined since then. The ratio for the U.S. of proved reserves
to production began to decrease over a decade ago as production exceeded
reserve additions.
Five major oil producing areas in the U.S. collectively produced
of total U.S. production in 1974. Table C.7-2 shows annual production
in each of the five major U.S. producing areas. The year production
peaked and began to decline in each area has been underlined for emphasis.
As can be seen, all five regions have already peaked in production anywhere
from three to six years ago.
A disturbing aspect of the production trends shown in Table C.7-2 is
that the only way to slow the production declines is by the addition
of new oil reserves. However, the onshore portions of the five areas
are the most thoroughly explored and drilled petroleum regions in the
world, and there is little prospect for finding large amounts of new
oil reserves.
Because of the extent of exploration and the history of production in
each of the five major U.S. areas, regional production trends generally
can be compared with a typical oil field production profile. Production
profiles of oil fields are predetermined by engineers to maximize the
total recovery of oil. Initially, production increases rapidly until
it reaches a long-term plateau at the HER for the field. The field is
produced for most of its life at the HER before a rapid production decline
begins. Oil field facility equipment capacities are sized for production
at the MER. When field production rates begin to fall below the HER, it
indicates that the ability of the field to produce will decline rapidly
until production becomes insignificant.
The maximum efficient rate (MER) of production is defined to be the
maximum sustainable production from a field which will not decrease the
total volume of oil recoverable from the field.
149
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As a rough approximation, production trends in onshore portions of the
five major producing regions are similar to the production profile of an
individual field. During development of the areas, production increased
and then stabilized before beginning a production decline corresponding
to aging of the producing fields in the regions. Only discoveries of
large, new fields will compensate for the regional production declines,
and probably there are few, if any, large fields remaining undiscovered
onshore in the lower 48 states.
As an indication of the intensity of previous exploration of the lower
48 states, Table C.7-3 compares the number of producing oil wells at the
beginning of 1975 in Texas, Louisiana and the U.S. to the non-communist
world and the Middle East. One third of the free world's currently
producing oil wells are located in Texas and Louisiana, and 88% of the
world's oil wells are in the U.S. This is in spite of the fact that in
the last five years more than 90,000 U.S. oil wells have been abandoned.
Another important fact to note from Table C.7-3 is that U.S. well pro-
ductivities are significantly lower than those of other world areas due
to reservoir characteristics and the length of time fields have been
produced. Of the 494,352 oil wells in the U.S., 355,229, or 71.9%, are
*
classified as stripper wells which as a category averaged production in
1974 of 3 barrels of oil per day. This means that the rest of the wells
averaged about 55 barrels per day, well below the world average. It should
be noted that many U.S. offshore wells are very productive (some more
than a thousand barrels per day) but these are the exception rather than
the rule in the U.S.
C.7.2.2 Projections of Future U.S. Crude Oil Production
Future production depends critically on future additions to reserves since
at current production rates present reserves would be totally exhausted
in a little over seven years. Future reserves depend on how much oil is
A stripper well is defined as a well averaging 10 barrels or less of
daily production.
150
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Table C.I-2
Petroleum Production From the Five Major U.S. Producing
Areas and Year of Peak Production
(MBBLS/Day)
Area 1968 1969 1970 1971 1972 1973 1974
Texas(1) 3,097 3,155 3,424 3,350 3.557 3,547 3,454
Louisiana(1) 2,234 2,314 2,485 2,562 2,437 2,278 2,018
California(1)l,026 1,028 1,020 982 948 921 884
Oklahoma 611 616 613 584 567 524 487
Wyoming 394 424 439 406 382 389 386
Rest of U.S. 1.759 1.702 1,657 1.579 1.575 1.549 1.546
Total U.S. 9,121 9,239 9,638 9,463 9,466 9,208 8,775
(1) Includes both on- and offshore production
Source: American Petroleum Institute, "Annual Statistical Review",
May, 1975.
Table C.7-3
Comparison of U.S. And World Numbers of Producing Oil Wells
And Average Well Productivities
(January, 1975)
Number of % of Wells Average Well
Producing in Each Area Productivity
Area Oil Wells of World Total (Barrels per Day)
Non-Communist World
(excluding U.S.) of Which 67,288 12 501
Middle East 3,919 0.7 5,658
United States of Which
Texas 159,090 28 22
Louisiana 28,000 5 83
Total U.S. 494,352 88 17
Total Non-Communist World 561,640 100 75
151
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still left in the ground to be discovered.
C.7.2.2.1 Future Oil Reserve Forecasts - Predictions of undiscovered
recoverable resources of oil are done using two major estimating
approaches, geological and mathematical. Geological estimates relate
past exploration and production statistics to the measured volumes of
sedimentary rock strata which potentially could contain oil and gas
reservoirs. The presumption is that unexplored, relatively unknown
areas have general characteristics which are similar to areas which
have been previously explored and developed. Mathematical predictions
use historical statistical trends of geological and technical relation-
ships to project future conditions. A number of such mathematical
techniques, such as Gompertz curves and normal distributions, have been
used in forecasting future oil production. Wide variations in resource
estimates arise in part due to the different predictive techniques.
In Table C.7-4 the Hubbert estimate was made using a mathematical
approach while the other estimates in the table were derived using geo-
logical estimating methods. The table shows estimates of how much oil,
presently undiscovered, will ultimately be found and produced in the
United States. These projections essentially ignore the cost of such
production and also assume that recovery techniques will be improved in
the future.
The 1974 USGS estimate appeared to be overly optimistic and was down-
rated in 1975 by significantly more than half. The National Petroleum
Council estimated range is in general agreement with other forecasts
which have been made and is the one which we have assumed to be most
valid. Hubbert's estimate appears conservative but, significantly,
falls in the range of the latest USGS estimate so that the mathematical
and geological techniques are beginning to converge on a reasonable
range of values.
Recent major exploration failures, such as the $650 million invested in
a non-productive exploration effort of the Dustin anticline of Florida,
152
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quickly influence geologist's opinions which are used in forecasts
based on geological correlations and this may partly explain the large
decline in the USGS prediction from 1974 to 1975. All the estimates
in the table indicate that the bulk of undiscovered oil will be either
offshore, or in Alaska.
The forecasts of future recoverable oil resources indicate that at
roughly today's present level of oil production all the oil will have
been produced in the United States within 35-55 years. Under actual
conditions, the production level will not continue at the present
rate but will continue to decline. Small quantities of oil will
continue to be produced for many years, but all of the estimates predict
that U.S. oil resources are finite and are being rapidly used up.
C.7.2.2.2 Future Oil Production Forecasts - Table C.7-5 presents four
*
recent projections of future U.S. petroleum liquids production. Al-
though the projections are based on different assumptions about U.S.
energy demand growth and about the production of alternative fuels,
the forecasts rather uniformly predict that maximum production of
domestic petroleum would occur under favorable government leasing and
exploration policies. Assumptions about petroelum pricing are different
among the forecasts.
Exxon's 1975 projection assumes U.S. oil prices will rise with inflation
rates of 8% through 1977 and 6.2% through 1985. The Library of Congress
projection assumes complete price decontrol while the Standard Oil of
Ohio (SOHIO) projections are shown under both price decontrol and under
the new Energy Policy and Conservation Act of 1975 (EPCA) regulations
which permit the national weighted average composite price to be
escalated at 10% per year. Thus, the Exxon and the SOHIO price regulated
forecasts provide a low side to anticipated future production while the
SOHIO price decontrolled and the Library of Congress forecasts provide a
Including crude oil and natural gas condensates.
153
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Table C.7-4
Various Estimates of Undiscovered Recoverable Resources of Oil
(Billions of Barrels)
Lower 48 States
Source Date Onshore Total
U.S.G.S. 1975 NA 50-127
U.S.G.S. 1974 110-200 200-400
Nat'l. Petroleum
Council 1974 53-70 73-140
M. King Hubbert 1972 9 72
Table C.7-5
Projections of U.S. Petroleum Liquids Production
(MMBBLS/Day)
1970 1973 1974 1975 1980 1985
Exxon (1975) 11.3 11 10.5 10.0 9.6 10.8
Exxon (1974) 11.3 11 10.5 10.6 10.8 10.5
Standard Oil
of Ohio (1975)
(1) Newly enacted
price regulations 11.3 11 10.5 10.0 10.5 11.1
(2) Price Decontrol 11.3 11 10.5 10.0 12.2 14.3
Library of Congress
(1975) 11.3 11 10.5 9.6 11.0 12.0
154
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high side for future production. We assume that future crude oil
production will fall somewhere between the low and high forecasts.
Projections of future domestic oil production must account for three
factors: 1) the rate of the production decline from the lower 48 states
onshore and the contribution of tertiary recover programs; 2) the
scheduling of offshore lease sales and the rapidity of exploration of
virgin acreage; and 3) the scheduled completion of the Trans-Alaskan
pipeline and development of Prudhoe Bay and related fields.
The production decline of the lower 48 onshore will be slowed by increased
drilling activities which will be directed primarily at further develop-
*
ment and extension of existing fields. Wildcat drilling has and will
decrease; and new additions to reserves will most likely be in small
increments.
Tertiary recovery programs in some areas of the country are and will be
implemented but will create relatively insignificant production by the
mid-19801s. Tertiary recovery techniques hold the promise of recovering
almost as much oil from old fields as has previously been withdrawn
during the primary and secondary production stages. Primary production
depends on natural pressure or pumping to bring the oil to the surface.
Secondary recovery techniques are used to repressure old fields and
hence drive more oil to the producing wells. Gas or water injections
into the formation are usually used to provide the pressure. Tertiary
recovery techniques use chemicals or heat to force more oil out of the
oil bearing formation by enabling the oil to move more easily within
the formation. Primary and secondary recovery methods usually cannot
recover more than about 30% of the oil originally in place while tertiary
techniques can recover an additional 30%. Forty percent of the oil in
the ground thus can never be recovered.
*
Wildcat wells are those drilled in areas which have not been previously
explored.
155
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The largest offshore areas of the U.S. have not been explored by drilling,
although most of the areas have been surveyed using seismic profiling
techniques. From the seismic studies large geologic structures are
known to exist in the offshore areas which are expected to contain oil.
The two largest factors affecting potential offshore development are
whether the government will adhere to its accelerated leasing program
and whether the petroleum accumulations are concentrated in large volume
reservoirs.
At present several of the offshore areas most interesting to the industry,
including the Gulf of Alaska and the Baltimore Canyon trough off of the
U.S. East coast, are expected to be leased prior to mid-1977. Other
areas such as the Georges Banks will not be offered for lease bids
for several years. At present, the government leasing program is
proceeding relatively slowly due to a lack of allocated funds to provide
the manpower needed to handle the leases and due to the environmental
impact statements which need to be written for each lease area. Of
the two problems, the environmental constraints seems to be causing the
longest delays.
Even with early leases of the offshore areas, however, it is estimated
that exploration and development of the geologically complex and pre-
viously unknown areas will require from 7 to 10 years before significant
volumes of oil will be produced.
A key consideration about the petroleum deposits to be found offshore
will be their size. Small accumulations of oil simply are uneconomic
offshore as a result of the high costs of developing fields which are
in deep water and harsh operating environments. For example, in the
North Sea, where water depths and weather conditions are similar to the
conditions in the Gulf of Alaska and off the Northern U.S. East coast,
a field must contain 300 million barrels or more before it can be
developed under today's economic conditions. For contrast, only one
field has been found in the Gulf of Mexico which contains more than 300
156
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million barrels while many others of smaller size have been developed
since the Gulf of Mexico has calmer weather and shallower water depths
than the North Sea. Forecasts of the development of U.S. offshore
areas are not constrained by manpower or equipment shortages since it
is anticipated that both these factors will be in adequate supply. At
one time it was thought that there would be a shortage of the type of
rigs needed to do the work due to a high demand for such rigs in other
parts of the world. That demand has slackened recently and no rig
shortage is anticipated in the next decade.
Production of Alaskan oil from its southern fields has declined since
1972, but when the Trans-Alaskan pipeline begins delivering oil to the
lower 48 states its production will increase dramatically. It is now
estimated that in 1977 initial volumes of 600,000 B/D of oil will begin
to flow southward through the pipeline. By 1978 up to 1.2 million
barrels per day will become available from the Prudhoe Bay fields.
C.7.3 FOREIGN CRUDE OIL PRODUCTION
Although synthetic fuels, coal, nuclear power and other sources of
energy are being developed to meet future world energy demands, oil
production will continue through 1985 to be the only source of energy
which will be able to respond significantly to the growth of world
energy demand as well as absorb short-term demand fluctuations by the
world economy. In this section we look at two recent forecasts produced
by the Library of Congress and by a major oil company.
C.7.3.1 Exxon Forecast (December, 1975)
Using projections of growth rates of key world economies to establish
future world energy demand, Exxon has forecast the contributions of oil
and other energy sources to world energy supply. Three factors which
form the basis of Exxon's world oil supply forecasts are: that economic
and technical constraints will limit alternative energy sources to a
relatively gradual development prior to 1985; that an average of an
157
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additional 15 billion barrels of crude oil reserves must be discovered
every year; and that world markets will have continued access to OPEC
production which will act as the supply balancing mechanism. Exxon's
projection through 1985 of non-Communist world oil production is given
in Table C.7-6. Note that the bottom line is Exxon's forecast of oil
demand which means that the OPEC production level has been set to balance
the difference between world demand and the ability of other areas
to produce oil.
Exxon has based its projections on a non-Communist world energy demand
growth of 4% per year through 1977 and a lower 3.3% per year from then
until 1990. Non-oil energy annual growth rates of 3.6% through 1977
and 4.7% through 1985 are assumed, which implies that oil demand will
grow 5.2% a year to 1977 and at 3.3% a year from then to 1990. See
Table C.7-7 which shows the assumptions Exxon made about GNP and inflation
and growth rates as well as showing the energy growth rates.
Exxon's production estimates indicate increased production from existing
OPEC reserves will be needed to match world demand and discovery of
additional world reserves will be needed to achieve the production rates
shown. Since the 1940's, additions to crude reserves have averaged 15-
20 billion barrels per year with the largest portion located in the Middle
East and Exxon has assumed a continuation of that trend. Discoveries
outside the Middle East have steadily increased during the past decade
as higher oil prices have prompted supply diversification and stimulated
exploration. This is offset somewhat by the fact that most of the major
fields in the Middle East appear to already have been found.
Exxon assumes that aggressive exploration efforts stimulated by higher
oil prices will be initiated on acreage provided through reasonable
host government policies and consequently new world reserves can be
found at an average of 15 billion barrels per year.
It should be noted that in the early 1970's world annual oil production
158
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Table C.7-6
Non-Communist World Oil Production As Projected by Exxon
(MMBBLS/Day)
Production Source 1974 1980
OPEC 31 37
Europe 0 4
U.S.A. 10.5 9.6
Other Non-OPEC 6.5 7.4
Net Imports from
Communist Countries 1 1
Total World Demand 49 59
Table C.7-7
Exxon's Assumed Growth Rates
Non-Communist World
1965-73 1973-75 1975-77
GNP 4.7 (1.5) 4.2
ition 3.3 12.5 8.0
y Demand 5.1 (1.8) 4.0
Non-Oil 3.3 1.9 3.6
Oil 7.4 (2.4) 5.2
1985
43
5
10.8
9.2
1
69
1977-90
3.9
6.2
3.3
4.7
3.3
159
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began to exceed annual additions to world reserves and, given Exxon's
projection of reserve additions, by the late 1980's oil production
will become limited by reserve availability just as the U.S. production
became reserve limited in the early 70's.
According to Exxon's projections, oil production in Western Europe
will go from almost zero in 1974 to over 5 MMBCD by 1985 as a result of
North Sea development. Communist countries will also increase their
production. Russia, currently the world's leading producing country,
is expected to expand production, and China is projected to become a
major oil producing nation by 1985. However, as a result of internal
consumption, net exports from Communist countries are projected to stay
at roughly 1 MMBCD through 1985.
North American production is expected to decline until Alaskan, offshore
and Arctic areas are developed, but 1985 production levels are shown to
be essentially the same as in 1974. Production in all other non-OPEC
countries is projected to increase rapidly reflecting projected dis-
coveries in Latin America, Africa and the Far East.
In order to balance total oil and energy requirements, increasing volumes
will be needed from OPEC, rising from 31 MMBCD currently to 43 MMBCD by
1985. OPEC crude oil production reached a peak of 32 MMBCD in 1973 before
declining to about 26 MMBCD in mid-1975 due first to the Arab embargo
and later to the world economic recession. In 1975 OPEC had spare
producing capacity of over 10 MMBCD. OPEC production now is increasing
to meet the needs of the industrialized nations emerging from the recent
recession. By 1985 OPEC as a whole could be supplying up to 45 MMBCD.
However, because of limited long-term production growth by OPEC countries
located outside the Persian Gulf area, the burden of balancing world oil
requirements will fall increasingly on Saudi Arabia and to a lesser
extent on Kuwait and the Arab Emirates.
The Arabian Peninsula producers are likely to approach maximum production
160
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capabilities sometime soon after 1985, indicating that at that point
world oil production will have increasingly limited flexibility to
adjust to world demand increases.
C.7.3.2 Library of Congress Forecast (November 1975)
Projections of world oil production given in a recent Library of Congress
study are shown in Table C.7-8. These projections tend to agree with
the Exxon forecast as the world demand estimates are approximately the
same; however, there are several significant disparities between the
assumptions made in the two forecasts.
The Library of Congress study does not include 1 MMBCD of Communist
country exports, and the study bases its projection of U.S. production
on a decontrolled price situation. Exports from the Communist countries
appear to be a reasonable assumption for the future given China's
proximity to the Japanese market, the use of western technology to
develop China's resources and Russia's new position as the world's
largest producing country. Thus the Library of Congress study may
understate the free world's availability of oil somewhat.
Given the recently enacted EPCA it is likely that U.S. production of
crude oil, condensate and natural gas liquids will not be able to
sustain present production levels, and the addition of 1.2 MMBCD of
Alaskan production will only partially compensate for production
declines in the lower 48 states. Thus it may be difficult for U.S.
production to reach the levels projected in the Library of Congress
study.
C.7.3.3. Dependence on Arabian Peninsula Countries
If the future world oil demand as estimated in both the studies mentioned
above is to be met, the major source of oil supplies through 1985 will
be the three Arabian Peninsula countries shown in Table C.7-9. However,
massive production from these areas probably will not serve the internal
161
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Table C.7-8
Non-Communist World Oil Production
As Projected by Library of Congress
(MMBBLS)
Source
OPEC
Europe
U.S.A.
Other Non-OPEC
Total World Demand 58.4 68.2
1980
36
4.5
11.0
6.9
1985
40
5.9
12.0
10.3
Source: "Towards Project Interdependence: Energy in the Coming
Decade", The Library of Congress, Dr. Herman T. Franssen,
December, 1975.
162
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Table C.7-9
Reserves and Productive Capacities of the Arabian Peninsula Countries
Country
Saudi Arabia
Kuwait
United Arab
Emirates
Totals
Oil Reserves
(Bil. of Barrels)
173.1
81.4
33.9
288.4
Percent of
World's Oil Reserves
35
16
7
58
Estimated Current
Prod. Capacity (MMB/D)
11.0
2.9
3.7
17.6
Ave. Daily
Prod. Mid-1975
(MMB/D)
6.76
1.93
1.7
I(hj39
Spare Current
Prod . Capacity
(MMB/D)
4.24
0.97
2.0
7.21
OJ
Source: "Towards Project Interdependence: Energy in the Coining Decade", The Library of Congress, Dr. Herman T.
Franssen, December, 1975.
-------
interests of these three countries. These countries have small population
bases and limited internal capital absorption capabilities and dispro-
portionately large oil revenue surpluses. The long-range socio-economic
and political interests of the countries probably would be best served
by limiting production and thereby protecting the life of the finite
oil reserves. Although other major OPEC producing countries have current
capital needs in excess of oil revenues and will continue to maximize oil
production, the Arabian Peninsula producing countries will have increasing
oil payment surpluses which could accumulate to about $500 billion current
dollars by 1985. Thus blind dependence on Arabian Peninsula countries
to meet the world oil need may not be wise.
C.7.4 NATURAL GAS
C.7.4.1 Natural Gas Supply in the U.S.
Annual natural gas reserve additions since 1967 have failed to keep pace
with gas production so that proved reserves have begun to decline,
especially since 1970. The reserve-to-production ratio—a measure of
how many more years present reserves will last at current withdrawal
rates—has declined steadily since 1945 and fell to 9.2 years in 1974;
i.e., at current withdrawal rates only 9.2 years of natural gas reserves
still remain. Figure C.7^1 graphically illustrates the decline in
reserves and the R/P ratio and, in addition, shows that domestic
production did not decline with the reserve addition trend line but
continued to increase until 1973.
The Federal Power Commission's (FPC) exhaustive study, the "Natural Gas
Survey", indicated a range of possible future proved reserve positions
in their four alternate cases. Case 1 was to model business as usual
conditions while Case 4 was a most optimistic case about exploration and
development. We feel that Cases 1 or 2 are more realistic in the current
situation and have used these in our forecasts of future production levels.
We feel that, although the gas shortage has become acutely evident since
1973, government inaction and indecisiveness have prevented attainment
164
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u
3
3
o
c
o
350
300
250
200
150
100
40
30
20
Figure C.7-1
U.S. Natural Gas Supplies, 1946-1974
• Total United States
' Excluding Alaska
Proved Reserves
Reserve to Production Ratio
60
50
40
30
20
10
g
TO
a:
10
Production
0
1945 1950 1955 1960
Source: Federal Power Commission, National Gas Survey.
1965
1970
1975
165
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of the accelerated cases which the FPC had postulated would be needed
to increase gas supplies by 1985. Table C.7-10 shows the range of
possible additions to reserves which have been forecast plus the forecast
production levels. Even given the high end of the forecast, by 1985
there will be less gas production than in 1975.
Table C.7-10 also shows our estimate of total gas availability (which
includes natural gas production, supplements and imports) in the United
States through 1985. Our estimate of potential alternate and substitute
supplies of natural gas which will become available over time and that
can be used in addition to natural gas production includes LNG, pipeline
imports and SNG projects (from both coal and petroleum). It can be
seen that these alternate sources are expected to have a significant
impact on the total gas supply by 1985. The high side of our domestic
production figures includes Alaskan gas arriving in the lower 48 states
by the mid-1980's at a level of about 2 TCF by 1985. This is in line
with the FPC Case 2 forecast although we are now less optimistic about
such deliveries by 1985. We feel that the high side of this forecast
range is less probable than the lower values due to uncertainties about
Canadian gas imports and the continued lack of a national energy policy.
C.7.4.2 Potential Demand for Natural Gas
In 1973 the Future Requirements Committee (FRC) of the American Gas
Association forecast a 1985 demand for natural gas of 39 TCF based
primarily on historical demand growth rates. Now we know that such un-
constrained demand will be impossible to meet but the difference between
the FRC demand number and our estimate of future production points out
the magnitude of the gas shortage which will occur. Demand forecasts
thus must be supply-constrained and hinge on assumptions about supply
allocations.
C.7.4.3 Probable Demand for Natural Gas
Since demand for natural gas is supply constrained, we must look to the
166
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Table C.7-10
Future U.S. Natural Gas Year-End Proved
Reserves and Production Levels
(Trillions of Cubic Feet)
Year-End
Reserves
1975
1980
1985
239 -
204 -
162 -
241
222
201
A,
Marketable
Production
18.1
16.4 - 17.5
13.0 - 16.3
Supplements
and Imports
1.4
2.2
4.9
Total Gas
Availability
19.3
18.6 - 19.7
17.9 - 21.2
A
86% of production after field use, repressurization, and losses reduce
gross withdrawals.
Source: F.P.C., Arthur D. Little, Inc.
167
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potential supply as our maximum usage level and determine how the supply
will be allocated among the users. In 1973, the Federal Power Commission
issued a curtailment priorities list which is shown in Table C.7-11. We
have assumed that this general priorities system will continue in effect
in the future. The main point to be noted from Table C.7-11 is that
large boiler use has a very low priority, especially if alternate fuels
might be available. We conclude that, on a national basis, by 1985
large boiler use of natural gas will have been curtailed. This national
assumption, however, is mitigated somewhat by the question of intrastate
gas.
C.7.4.3.1 Intrastate vs. Interstate Gas Supplies - Since the FPC began
regulation of interstate gas supplies in the mid-1950's, new supplies
have increasingly gone to the intrastate market, where the price has
been unregulated. Table C.7-12 shows the prices of interstate and
intrastate gas since 1966 and clearly demonstrates the wide gulf between
the inter- and intrastate gas markets.
From previous work done by ADL, we conclude that without intervention
by the federal government the intrastate market could probably absorb
most new natural gas supplies which would become available, such that
by 1985 there would be very little new gas moving in the interstate
market. This would imply that the interstate market would be dependent
on old gas supply contracts which would in turn be dependent on rapidly
dwindling gas reserves. Currently, about the only new gas reserves
being dedicated to the interstate market are those from offshore federal
lease lands; almost all onshore new gas supplies are being dedicated to
the intrastate market. The implication of this is that those regions
with available intrastate gas would be far less impacted by gas shortages
than those regions without gas production capabilities.
We feel that federal intervention will eventually force more gas into
the interstate market to lessen regional inequities and this will mean
that low priority uses, even in intrastate markets, will be curtailed
168
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Table C.7-11
Federal Power Commission Natural Gas Curtailment Priorities
"The national interests in the development and utilization of natural gas
resources throughout the United States will be served by recognition and
implementation of the following priority-of-service categories for use
during periods of curtailed deliveries by jurisdictional pipeline companies:
(1) Residential, small commercial (less than 50 MCF on a peak day).
(2) Large commercial requirements (50 MCF or more on a peak day),
firm industrial requirements for plant protection, feedstock and
process needs, and pipeline customer storage injection requirements.
(3) All industrial requirements not specified in (2),(4),(5),(6),(7),
(8),or(9).
(4) Firm industrial requirements for boiler fuel use at less than
3,000 MCF per day, but more than 1,500 MCF per day, where alternate
fuel capabilities can meet such requirements.
(5) Firm industrial requirements for large volume (3,000 MCF or more
per day) boiler fuel use where alternate fuel capabilities can
meet such requirements.
(6) Interruptible requirements of more than 300 MCF per day, but less
than 1,500 MCF per day, where alternate fuel capabilities can meet
such requirements.
(7) Interruptible requirements of intermediate volumes (from 1,500 MCF
per day through 3,000 MCF per day), where alternate fuel capabilities
can meet such requirements.
(8) Interruptible requirements of more than 3,000 MCF per day, but less
than 10,000 MCF per day, where alternate fuel capabilities can meet
such requirements.
(9) Interruptible requirements of more than 10,000 MCF per day, where
alternate fuel capabilities can meet such requirements.
The priorities-of-deliveries set forth above will be applied to the deliveries
of all jurisdictional pipeline companies during periods of curtailment on
each company's system; except, however, that, upon a finding of extraordinary
circumstances after hearing initiated by a petition filed under Section 1.7(b)
of the Commission's Rules of Practice and Procedure, exceptions to those
priorities may be permitted.
The above list of priorities requires the full curtailment of the lower
priority category volumes to be accomplished before curtailment of any
higher priority volumes is commenced. Additionally, the above list requires
both the direct and indirect customers of the pipeline that use gas for
similar purposes to be placed in the same category of priority."
Source: Federal Power Commission Statement of Policy on Utilization and
Conservation of Natural Resources - Natural Gas Act, Docket
//R-469, Order #467, Issued January 8, 1973 (modified March 2,
1973).
169
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Table C.7-12
Prices Received by Producers for Natural Gas Sales, 1966-1975
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
(cents
.Average
Wellhead Prices
15.7
16.0
16.4
16.7
17.1
18.2
18.6
21.6
26.7
35.0
per thousand cubic feet)
New Long-Term
Interstate Contracts
17.7
18.8
19.6
19.9
22.3
24.8
35.1
40.3
43-51
New Gulf Coast
Intrastate Contracts
15.1 -
15.6 -
16.1 -
14.4 -
18.5 -
20.6 -
23.5 -
25 -
125 -
175 -
19.5
19.6
20.2
21.5
23.0
26.2
30.0
125
195
211
Sources: Foster Associates; U.S. Bureau of Mines, Natural Gas Annual,
1973; Federal Power Commission; Jensen Associates; and
Arthur D. Little, Inc., estimates.
170
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by 1985. The impact of this will be felt primarily in the major gas
producing areas of Louisiana, Oklahoma and Texas, where utilities use
large quantities of intrastate gas and do not have ready access to
alternate fuel sources.
C.7.4.3.2 Impact on Utilities - We anticipate that, because of the
lack of supplies, all interstate utility boiler use of natural gas will
be eliminated by 1980. There may be a few circumstances of summer use
of natural gas and some use in peakshaving units, but this will be of
insignificant volume. In the intrastate market we feel that, by 1985,
the same situation will apply, but that in 1980 the situation could
still be very much undecided. The Texas Railroad Commission recently
ruled that boiler use of natural gas in Texas would be reduced by 10%
by 1981 and there would be a 25% mandated reduction in boiler use by
1985. Large utilities in that region, however, are planning to phase
out all use of gas earlier than this in anticipation of federal controls
on intrastate utility use of natural gas. We anticipate that, by 1980,
intrastate natural gas usage will be limited to old contracts and that
new gas supplies will not be available to utilities. By 1985, we assume
that intrastate gas will not be used in utility boilers to a substantial
degree.
C.7.4.4 Future Natural Gas Price
The current debate on deregulation of natural gas prices must be resolved
before forecasts of future gas prices can be made with any accuracy, but
we feel that future prices of new interstate natural gas supplies will
primarily be a function of competing fuel prices and intrastate market
conditions. The FPC has begun to allow private companies to make purchases
in the intrastate market for movement through the interstate pipeline
transmission system to the point where the company wants to use the gas.
Such gas as is thus obtained will be bought in competition with intra-
state industrial concerns who are buying gas for process use. This
will increase the competition in the intrastate market. We anticipate
171
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that 1985 prices for natural gas will be equivalent on a BTU basis
to the prices for fuel oil which means that gas prices might be in
the range of $3.50 - $4.50/MMBtu. By 1980 parity with fuel oil prices
will probably not be achieved for all supplies of intrastate gas but,
for planning purposes, we can assume that the price will be $2-3/MMBtu
for such new supplies as are available.
C.7.5 COAL
The world's largest source of fossil fuel energy is contained in coal
reserves. In 1973 world coal production was less than 1% of reserves
but accounted for approximately 28% of the world's total energy consumption.
In contrast, about 3% of the world's petroleum reserves were produced
in 1975 and accounted for 45% of total world energy consumption.
About one-third of the world's recoverable coal reserves are located
in the U.S.; and in 1973 the U.S. coal mining industry accounted for
slightly less than a quarter of the total world coal production as
shown in Table C.7-13.
C.7.5.1 U.S. Historical Coal Production
Because of large available reserves, U.S. coal production has been able
to fluctuate in response to irregular growths in demand. As shown in
Table C.7-14 the U.S. has a demonstrated coal reserve base of about
435 billion tons of which about 50% is economically recoverable under
current conditions. The reserves are split roughly equally between East
and West. Over two-thirds of the coal reserves are considered to be
available only by underground mining methods.
U.S. coal production became significant and rose throughout the 1800fs
to a peak of 678 million tons in 1918 during World War I before falling
to a low of 359 million tons in 1932 during the world business recession.
Domestic production then increased again during World War II through
1947 reaching an all time peak of 688 million tons before falling as a
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Table C.7-13
World Coal Statistics - 1973
Region
Sino-Soviet Bloc
United States
Western Europe
Far East + Oceania
Africa
Other Western Hemisphere
Total
Reserves
(Billion Short Tons)
307
217
72
46
17
ere 9
668
Production
(Million Short Tons)
1,266
599
303
207
74
32
2j481
% Of World
Production
51.0
24.2
12.2
8.3
3.0
1.3
100.0
Source: Energy Perspectives, U.S. Department of the Interior,
February, 1975.
Table C.7-14
1974 U.S. Demonstrated Coal Reserve Base*
By Potential Mining Method
(Billions of Short Tons)
Total U.S.
Billion Tons %
Surface
Underground
Total
137
298
435
32
68
100%
Western %
103
129
232
of Total U.S
24
30
54%
Eastern
34
169
203
Total U.S.
8
38
46%
Note: Approximately 50% of Demonstrated Coal Reserve Base is economically
recoverable.
Source: U.S. Geological Survey Bulletin 1412, "Coal Resources of the
United States, January 1, 1974."
173
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result of oil and gas penetration of transportation, home heating and
industrial fuel markets. After decreasing to 420 million tons in 1961,
coal production has increased substantially in response to the lower
cost of coal resulting from the increasing size and efficiency of strip
mining machinery and in response to increased demands of the electric
utility industry. Since 1961 coal demand by utilities has risen at a
rate which has more than offset declines in demand from all other
consuming sectors. Highly productive strip mining has risen from 1%
of production in 1917, a previous period of high coal demand, to over 50%
of production in 1974. In addition to the trend towards increased
production from strip mines, the coal industry has been moving westward
so that in 1974 15.4% of all U.S. coal production came from the Western
areas, as compared to 7.4% in 1970.
C.7.5.2 Projected Demand for Coal
Electric utilities are the major consumers of coal and will continue as
such at least through 1985. Table C.7-15 shows projected demand for
coal by user category. In 1974 utilities consumed 390 million tons,
accounting for 63% of coal and lignite demand. Projections of electri-
city demand and utility consumption of primary energy sources indicate
utility requirements will be 616 million tons and 741 million tons in
1980 and 1985, based on electric load growths of 6.2% per annum. The
utility percentage of total coal demand is expected to decrease after
1980 as increased nuclear power generation reduces utility demand for
coal at the same time as other coal markets begin to increase slightly.
Markets for coal other than that of electric utilities will begin to
develop and increase slowly prior to 1985 but will not develop rapidly
until later years. Demand for metallurgical grade coking coal by domestic
and foreign steel industries will increase through 1985 but will be
limited by improved efficiencies of blast furnaces. Use of coal as a
feedstock and raw material by the chemical industry and as a fuel for
industry will increase slowly prior to 1985 as natural gas becomes un-
available and petroleum prices rise. A significant new use for coal will
be for gasification and liquefaction, and it is estimated that by 1985
63 million tons of coal will be thus used.
174
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Ol
Table C.7-15
Projection of U.S. Bituminous Coal and Lignite Demand
(Million Short Tons)
Electric
Year Utilities
1974 390.1
1975 405
1980 616
1985 741
1. Includes ship
Industrial
and -^
Commercial
64.1
65
95
127
bunkers
2. Includes small quantities
Gas if icat ion ,
Liquifaction
Feedstocks^
5.0
5
10
63
Retail &
Railroads
8.8
8
8
5
of non-coking coals used in
Total
Domestic Steam Coke and „
Coal Demand Metallurgy
468.0
483
729
936
steel and
89.7
87
95
105
rolling mills.
Total
Domestic ,
Consumption Exports
557.7 57.9
570 67
824 100
1,041 110 1
Total
Demand
615.6
637
924
,151
3. Feedstocks for ammonia, methanol and non-energy uses.
4. Net exports: d
Imports of coal, mostly from
Canada, Poland and South Africa in 1974,
have been small, totali
ng
about 2,080,000 tons in 1974, and are expected to remain small.
Sources: U.S. Bureau of Mines and Arthur D. Little, Inc., estimates.
-------
C.7.5.3 Projected Supply
Table C.7-16 shows several published projections of U.S. coal production,
each of which is based on the assumption that environmental and federal
leasing constraints will allow some further development of Western coal
lands and continued operation of strip mines. Looking at all the pro-
jections the most probable U.S. production level in 1980 is expected to
be 870 million tons and 1,150 million tons by 1985.
Until recently, U.S. demand has been met primarily by mining of eastern
coal which has been responsive to demand fluctuations without the con-
straints of a federal leasing program and extensive environmental con-
siderations. Most of the coal lands in the East, the Mississippi Valley
region and the Appalachian basin are privately owned. However, as is
shown in Table C.7-17, federal government ownership of coal rights and
lands which will be developed in the Rocky Mountains and Northern Great
Plains regions ranges from 82% in Utah to 25% in North Dakota and is in
excess of 60% overall. These two regions contain over 50% of U.S.
reserves so that future governmental actions will be critical to future
coal production potential.
Severe environmental constraints imposed on surface operations issued
in conjunction with a federal leasing program would have a major limiting
effect on production prior to 1985. The U.S. has economically strip
mineable reserves of 55 billion tons, but according to National Petroleum
Council statistics, if contour mining bans are imposed amounts projected
for production in 1980 and 1985 would be decreased by over 12%. If bans
on all surface mining were imposed, projections of production for 1980
and 1985 would be reduced by over 40%.
Based on recent surveys by the Federal Energy Administration and the
National Coal Association, ADL has prepared annual estimates of coal
mine capacity through 1985 as shown in Table C.7-18. This table indicates
the maximum expected production capability of the coal industry. Because
176
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Table C.7-16
Actual and Projected U.S. Coal Production
(Million Tons)
Actual
Projection and Date Published
ADL (1975)
EXXON (1974) Eastern Production
Western Production
FEA (1975)
Total:
Eastern Production
Western Production
Total:
Nat'l Petroleum Council (1973)
Case IV
Case II/III
Case I
Project Independence (1974)
Business as usual
Accelerated
CONOCO (1975)
1970 1974
602.9 603.4
Projected
1975 1980 1985
636 870 1,130
558.0
44.9
602.9
558.0
44.9
510.6
92.8
603.4
510.6
92.8
578
92
670
587
98
650
220
870
710
185
700
514
1,214
NA
NA
602.9 603.4 685
895
NA
602.9 603.4 695 830 1,004
602.9 603.4 713 876 1,134
602.9 603.4 754 1,023 1,570
602.9 603.4 685 895 1,100
602.9 603.4 750 1,376 2,063
602.9 603.4
NA
NA 1,175
Source: Bureau of Mines, "Minerals and Materials", 11/75.
177
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Table C.7-17
Federal Ownership of Coal Lands and Rights
State
Montana
Wyoming
North Dakota
South Dakota
Utah
Colorado
Arizona
New Mexico
Total
Total
Reserves
107,727
51,228
16,003
428
4,042
14,870
350
4,394
199,042
By Potential Mining
Method
Underground Surface
65,165 42,562
27,554 23,674
NA 16,003
NA 428
3,780 262
14,000 870
NA 350
2,136 2,258
112,635 86,402
Percent Federal Ownership
75
65
25
NA
82
53
small
59
60%
Source: U.S.G.S. Bulletin 1412
"Project Independence, 'Coal'"
178
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Table C.7-18
U.S. Domestic Coal Mine Capacity
(millions of short tons)
Base
Retirements"
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
638. O2
666
701
718
750
788
828
870
916
965
1,017
1,072
-18
-18
-18
-18
-19
-2.0
-20
-20
-21
-21
-22
-22
New Mines
and
Expansions
46
53
35
50
57
60
62
66
70
73
77
80
Estimated ,
Probable Capacity
666
701
718
750
788.
828
870
916
965
1,017
1,072
1,130
1. January 1
2. Minerals Yearbook, 1974
3. Assumes 30-year mine lifetime (3.3% annual loss in capacity). Applicable
only to eastern and midwestern capacity — 536 million tons/year in 1974.
4. December 31
Sources: Arthur D. Little, Inc., estimates based on Federal Energy
Administration and National Coal Association surveys of new
coal mine plans.
179
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it takes two to six years to develop mining operations, major commitments
have already been made for 1980 output; but major new mines which will be
operating by 1985 need not have been announced yet. Thus, the projection
as shown is relatively accurate through 1980 but becomes increasingly
uncertain after that.
C.7.5.4. Supply/Demand Balance
In Table C.7-19, which is based on the demand projection in Table C.7-15
and the ADL supply forecast in Table C.7-16, shortfalls in supply are
indicated to occur throughout the time period. The 1974 shortage was
caused by the mine workers strike while 1975 production and demand are
essentially in balance. Shortages are expected to increase and to
amount to 5% in 1980. The shortfall is expected to lessen somewhat by
1985. While actual conditions through 1985 may not produce a real
shortfall, this analysis suggests that coal will not be able to be
substituted freely for oil or gas usage due to a tight supply/demand
situation using a rather conservative demand forecast. Ignoring import
problems, this shows that in 1985 only oil will be essentially unconstrained
by supply considerations while natural gas and coal will both be supply
constrained.
180
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Table C.7-19
Projected Short Falls of U.S. Coal Supply
(Millions of Short Tons)
Year
1974
1975
1980
1988
Total
Demand
615.6
637
924
1,151
Total
Supply
603.4
636
870
1,130
Short Fall
(12.2)
( 1 )
(54 )
(21 )
Short Fall
Percent of
2%
Nil
5%
2%
as
Demand
Source: Tables C.7-15 and C.7-16
181
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C.8 DEMAND TRENDS FOR RESIDUAL FUEL PRODUCTS
C.8.1 OVERVIEW
Over the period 1970-1973, demand for residual products grew at an average
annual rate of 8.0%, while demand for all petroleum products increased
at an average of 5.5% per annum. In the future the demand for all petro-
leum products is expected to increase at rates below recent historic
averages as a result of several interrelated and reinforcing trends:
slower rates of national economic growth, higher energy prices and con-
servation incentives. A concensus of recent forecasts of U.S. oil demand
suggests that total product demand will grow at an average of 2% per
annum. Residuum products other than residual fuel oil could be ex-
pected to follow the national growth pattern for petroleum products,
since the demand level for these products is closely related to the
national industrial outlook. However, the growth in demand for residual
fuel oil may well exceed the national average for petroleum products
generally.
Consumption of residual fuel oil will grow at rates in excess of other
petroleum products for three primary reasons: the level of natural gas
curtailments to utilities and large industrial customers; the inability
of coal to substitute for curtailed gas supplies; and, finally, the in-
crease in fossil fuel requirements by utilities resulting from delays in
the scheduled operation of nuclear capacity. Since 1971, U.S. production
of natural gas has been declining. Furthermore, the rate of discovery
of new natural gas reserves has been below production levels since 1967,
so that the outlook for increased domestic production of natural gas in
the Lower 48 states is bleak. The only relief from this domestic decline
trend is expected to come from production of Alaskan North Slope gas in
183
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the early to mid-1980's. The decreased availability of natural gas
(see the previous chapter for more details) will have a significant im-
pact on the demand for oil in general and residual fuel oil in particular.
In early 1973, the Federal Power Commission (FPC) issued a priority list
of types of gas consumers which interstate pipelines were obliged to ob-
serve in curtailing their customers. This list basically gave preferential
status to residential and small commercial customers and certain special
industrial process users of gas, while according use of gas under boilers
the lowest priority. Thus, as gas supplies have dwindled, it has been
the utility and large industrial customers of interstate pipelines who
have been most heavily curtailed. Also affected were the refineries,
which have traditionally obtained a large fraction of their fuel from
natural gas. Once curtailed, these large volume users had little choice
in their fuel substitution, since the conversion from natural gas to
residual fuel oil is more feasible from technical and cost viewpoints
than conversion to coal. In addition, many of these curtailed interstate
pipeline customers were located in areas remote from the country's coal
producing regions, so that coal transportation logistics and costs would
have ruled out conversion to coal. To date, most of the conversions to
residual fuel oil have occurred along the East and West Coasts, and in
the upper Midwest. In the near-term future, the trend will be for
continued conversions to oil as a result of gas supply shortages; over
the longer term (early to mid-1980's onward), the increased availability
of nuclear power for utilities and the increased burning of coal by large
industries is expected to gradually halt the present conversion trend.
Coal has been unable to offset the declining natural gas supplies in
the short-term for three principal reasons: (1) the difficulty of
quickly gearing up coal production capacity to meet higher demand levels;
(2) transportation problems in getting coal from the mines to the end
user; and (3) environmental objections to the burning of coal. During
the 1960's and early 1970's, when oil products were relatively cheap com-
184
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pared to coal and when there was an awakening of environmental concern
over air pollution, many large volume energy users, located away from
coal deposits (and often near ports), switched from coal to oil or gas.
With demand declining, coal producers dropped their production capacity.
Then when the OPEC price hikes and Arab oil embargo launched a movement
for U.S. energy independence, which implied a resurgence for coal as the
country's most abundant energy resource, the coal industry found itself
without the manpower and physical goods, not to mention a transportation
network, to bring about the rapid increase in production implied in energy
self-sufficiency.
In addition to the physical production and (transportation constraints,
coal faced environmental obstacles. With large metropolitan utilities
on the East Coast restricted to burning residual fuel oil of less than
0.5% sulfur, the only comparable domestic coal supplies were, in general,
expensive metallurgical grade coal or Western low-sulfur deposits. Some
utilities did convert to coal during 1973-1974, but for the most part they
had to be granted variances to existing local air pollution regulations
in order to do so. In the short term, it is likely that some coal
burning will continue at variance with local ordinances, but the diffi-
culties in obtaining coal supplies and the uncertain outlook for air
pollution restrictions, will keep down the number of conversions. For
the longer term, when coal production capacity has expanded, permanent
resolutions to the environmental conflicts are expected.
The third major factor impacting differentially on the demand for resid-
ual fuel oil is the delays in nuclear power plant construction. These
delays have been blamed on financing difficulties, licensing and siting
problems, equipment delivery schedules, public intervention in opposition
to nuclear power and, most recently, changes in forecast load levels.
Whatever the individual explanation for the delays, which have lengthened
the average nuclear generating plant construction time to 8 to 10 years,
the effect of the delays is to increase the short-term demand for oil.
For some utilities the short-term solution has been the installation of
185
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gas turbine units, which require short lead times. These turbine units
typically burn diesel fuel and are designed for peakload usage rather
than base load applications. However, for other utilities, the delays
in nuclear power plant construction have led to the need for additional
residual oil-fired units or for the continued use of old oil-fired units
which were scheduled for retirement. In addition, the extremely high
capital costs of nuclear generating plants—particularly viewed from the
present period at the end of a two year hiatus in electricity demand
growth—have caused several utilities to postpone the start-up dates for
their nuclear units.
In the following section the expected impact of these national trends
on individual end-use consumption of residual fuel oil will be discussed.
C.8.2 TRENDS IN END-USE CONSUMPTION OF RESIDUAL FUEL OIL
As described in Chapter C.4 the two major end uses, electric utilities
and industrial (including oil company usage), accounted for 60-70% of
total residual fuel oil usage over the 1970-1974 period. Because of
their prominence among residual fuel oil uses, demand trends in these
two sectors will be critical in determining the rate of growth (or decline)
in residual fuel oil consumption. Trends in utility and industrial fuel
demand will, therefore, be covered in greater detail below. Among the
three remaining end-use categories reported by the Bureau of Mines, only
the Residential/Commercial Heating sector is significant in terms of volume.
This classification refers to large apartment and commercial building and,
therefore, it might be expected that growth in fuel demand by this sector
would be related to changes in such independent variables as population
growth, GNP and rate of urbanization. At the same time, electricity
has been assuming an increasing proportion of this market, given the
emphasis on year-round comfort, including air conditioning as well as
heat. Thus, for the future, the growth in residual fuel oil consumption
in the Residential/Commercial sector is expected to be minimal, certainly
below the 2% per annum concensus forecast for all products.
186
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Residual fuel oil usage for transportation (almost exclusively ships
and bunkers) is extremely difficult to forecast due to the inherent nature
of ship bunkering habits. Where ships bunker is a function not only pf
bunker prices, but of trade routes, which are likely to vary from one
year to the next. Thus, for present purposes, it is sufficient to state
that transportation uses are unlikely to expand very rapidly and, in
fact, considering the small railroad component, may actually decline.
C.8.2.1 Utility Demand
Prior to the OPEC price hikes in 1973-1974 and the Arab oil embargo, it
was a utility axiom that peak demand for electricity would grow an average
of 7% per annum or double every 15 years. Subsequent to the rises in
OPEC oil prices, which utilities were forced to pass along to their
customers in the form of massive rate hikes, consumer demand for elec-
tricity dropped to below 1973 levels in 1974 and generally did not accel-
erate appreciably during 1975. This dramatic leveling off of the demand
curve has lead to utility industry revisions of their hallowed 7% per
annum figure. Most industry spokesmen now forecast that growth in demand
will be more moderate—4.5% per annum—over the next five to ten years,
although they typically express greater optimism about the longer term,
when significant quantities of nuclear base load capacity are slated to
be onstream. The slower than historical growth projections imply a
reduction in the rapid rate of growth of utility consumption of residual
fuel oil.
However, as discussed above, acting to offset the slowdown in consumer-
induced utility expansion will be the conversions of curtailed gas-
burning utilities to residual fuel oil and the delays ifi nuclear plant
construction. Both of these trends will combine to cause at least a short-
term spurt in residual fuel oil demand. To the extent that the gas cur-
tailments and nuclear setbacks of the future occur in the Gulf Coast and
Midwest areas, these trends will tend to lessen the concentration of
residual fuel oil consumption on the East and West Coasts. Over the longer-
187
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term, utility demand for residual fuel oil should peak out and then de-
cline gradually as other fuels (primarily coal and nuclear) take over
this market.
C.8.2.2. Industrial Demand
Over'the long-term, growth in the fuel consumption of the industrial
sector can be expected to parallel the growth in the national economy.
In the recent past, residual fuel oil consumption by the industrial
sector has increased at a rate slightly in excess of GNP, reflecting
the impact of gas curtailments. In the near future, residual fuel oil
demand in the industrial sector is expected to continue to expand more
rapidly than indicated by the rate of general domestic industrial activity
as natural gas curtailments proceed to strand more industrial gas
customers.
However, partially offsetting these gains in residual fuel oil customers
will be the effects of price-induced conservation efforts of all residual
fuel oil users. In the short-term, industry's conservation programs will
be limited to non-capital intensive measures—curtailing wasteful
practices and improving maintenance. Over the longer term, the results
of industrial conservation efforts will be enhanced by the introduction
of more energy efficient equipment and processes, so that the effects
of energy conservation in the industrial sector can be expected to impact
gradually over the next decade.
C.8.3 DEMAND TRENDS FOR OTHER RESIDUUM PRODUCTS
Besides the trends on residual fuel oil demand, brief mention should be
made about future cat cracker feed demand, coke consumption and lubes,
waxes and asphalt demand. These residuum uses constitute the balance
of residuum demand with the exception of refinery fuel usage.
As discussed in Chapter C.3, future refinery usage of residuum as fuel will
certainly increase in the future and would be expected to represent up to
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3-4% of total crude charged by 1985 when it Is anticipated that all
natural gas will have been withdrawn from refinery boiler use.
Future gasoline demand will affect how much residuum is used as feed for
the cokers, catalytic crackers and hydrocracking units. We anticipate
that gasoline demand may increase slightly for a few more years (though
at rates much below historic trends) then become static or actually
decline in the early 1980's as federally mandated fuel efficiency standards
for automobiles begin to have an impact. We anticipate that gasoline
demand will commence a declining growth pattern in the 1980's as the
proportion of more efficient, small engine cars in the total car population
increases and as alternative transportation forms (largely mass transit)
reduce reliance on the private automobile.
Since converting residuum into gasoline is one of the most costly operations
in a refinery, it is reasonable to assume that static or declining gasoline
demand will selectively impact first on gasoline produced by cracking
residuum, thus freeing up supplies of residuum for use as residual fuel
oil. Through 1985, however, this effect will be minimal.
In addition to producing gasoline blending stock the coking operation
produces a salable by-product—petroleum coke. Petroleum coke produced in
PAD Districts I-III is generally used in the steel and electric utility
industries. Some coke that is of superior quality (i.e. of very low
sulfur content and from particular types of coking operations) is used
by the carbon products industry for such things as electrodes. Much of
the coke produced on the West Coast is exported to Japan. In Japan some
of the coke is used in the steel industry, but mostly it is blended with
coal for utility boiler fuel. These uses of coke generally require a
fairly low sulfur content so that coke cannot be treated as a sulfur sink.
In addition, the EPA is beginning to regulate the sulfur content of coke
sales to utilities, since high sulfur coke can result in higher than
desired sulfur emissions.
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In the late 60's petroleum coke was in oversupply and was sold at distress
prices. Now sales keep, up with production. Coke production, however, is
not an independent variable—it is the result of conversion processing
of residuum to gasoline. Thus, coke availability will probably follow
gasoline production trends. Since we do not anticipate long-term
continued growth in gasoline demand fes described above) no marked growth
in petroleum .coke production is likely in the future.
Lubes and waxes are very specialized products from residuum and they
represent a very small part of the residuum usage. We assume that these
products, which are premium uses of oil, will continue to be supplied in
sufficient quantity to meet demand, which will probably grow at or above
the deemed average growth rate of 2% per year.
Asphalt, which goes primarily into road construction and building con-
struction, would appear to have relatively good growth potential in the
future. However, the significant price increases, prompted by crude price
increases, may impede further product demand growth. Road construction
and repair depend on low cost bulk materials, and the recent crude oil
price increases have forced asphalt prices upwards, causing users to begin
seeking substitutes. Unless suitable substitutes are found, and there do
not appear to be very many of them, asphalt will continue to be used in
spite of higher prices. Thus we expect asphalt demand to grow at about
2% per year.
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C.9 TECHNOLOGICAL TRENDS IN SULFUR REMOVAL PROCESSES
C.9.1 INTRODUCTION
Air pollution regulations limit the emission of SO gases in the flue gas
A
from power boilers (steam boilers). These regulations are predicted on
a maximum allowable emission of SO per heat input to the boiler. The
Federal EPA regulations limit S0« emissions from new boilers having a
*
capacity greater than 250 MMBTU/HR (263.7 GJ/HR) as follows:
• For liquid fuel - 0.8 Ib SO /10 Btu heat input [(0.34 kilogram
(kg) S02/GJ)]
• For solid fuel - 1.2 Ib S02/106 Btu heat input (0.52 kg S02/GJ)
Emission limitations for existing boilers were set by state and local
codes, as developed in the implementation plans aimed at achieving the
primary and secondary air quality standards on schedule. There are no
federal emission requirements for existing boilers, only for new units.
State regulations for new units can be more stringent than the minimum
federal performance requirements as discussed in Chapter C.5.
Meeting these sulfur emissions regulations can be accomplished by a
variety of methods including:
• Switching to low sulfur fuels
• Precombustion sulfur removal
• Post-combustion sulfur removal (flue gas desulfurization)
*
One BTU is the same as 1054.8 Joules so that to convert from millions of
BTU's (MMBTU) to Gigajoules (GJ) one multiplies by 1.0548. One pound is
equal to 0.4536 kilograms.
191
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Pre-combustion sulfur removal can be accomplished either during the
refining of the fuel products or just prior to use, as is the case with
the CAFB process. Switching to low sulfur fuels is the easiest option
to implement and requires minimal capital investment. However, it.;is not
a universal solution because there is not enough low sulfur fuel available
to satisfy the potential demand. Hence, pre-combustion or post-combustion
sulfur removal must be employed to satisfy the sulfur emission requirements.
Various sulfur removal processes have been, or are being, developed in
each of the categories mentioned above. We shall discuss the advantages
and disadvantages of each category, concentrating on processes designed
for oil.
C.9.2 POST-COMBUSTION SULFUR REMOVAL
Flue gas desulfurization (FGD) refers to removal of sulfur compounds after
combustion of the fuel. Sulfur is present mainly in the form of S0»
although some SO is generally present. The advantages of FGD systems
are the flexibility of fuel supply, lower operating cost and lower energy
consumption than other available sulfur removal systems.
The disadvantages of FGD systems are that it adds the responsibility of
controlling and managing an additional process on the user and that the
user must sell or dispose of the final sulfur compound. Also, the economics
may not be favorable for very small installations (generally below 100
megawatt capacity).
C.9.2.1 Current Status of FGD Systems
It now appears that reliable S0_ control technology is finally emerging.
Its use is being encouraged by the EPA which is adopting an enforcement
strategy that requires boiler operators in areas where primary air quality
standards are not being met to file compliance plans to meet emission
codes as rapidly as possible by installing control systems or by con-
verting to low-sulfur fuel.
192
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Table C.9-1 summarizes the current status of commercial-scale S0» emission
control systems as applied to electric utilities. The table indicates
that roughly 50,000 megawatts of generating capacity are in various
project stages, ranging from preparation of system bid specifications,
through construction, to the 3,300 megawatts currently in operation
with SO- control. Almost all of the capacity represents coal-fired
boilers with well over 90% of the control systems involving production
of a waste form of the sulfur rather than recovering by-products. The
total U.S. generating capacity from all utility boilers in 1975 was about
500,000 megawatts.
All systems in the bid evaluation stage or in more advanced stages of
contracting or construction should be in operation by the end of 1978.
Systems in the pre-bid stage should be in operation by the end of 1980,
as will additional systems not yet listed but committed by the end of
1977. Thus, the total capacity under SO. control should be on the order
of 50,000 megawatts by 1980, or about 10% of total U.S. generating
capacity in 1975.
It should be mentioned that no changes are required in the FGD system
or the cost of the system between coal and oil-fired boilers. Oil has a
higher Btu/lb (GJ/KG) content but lower acceptable emission rates in terms
of Ib SO /MMBtu (KG SO /GJ). Thus, 0.7% coal or 0.7% oil meets the
federal regulations and 0.3% coal or 0.3% oil meets the regulations in
the metropolitan areas (these percentages are weight percent of sulfur).
C.9.2.2 Types of Flue Gas Desulfurization Processes
FGD sulfur dioxide control processes may be classified according to the
final form of the sulfur removed from the flue gas:
• Waste salts
• Concentrated S0_
• Direct sulfuric acid
• Elemental sulfur
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Table C.9-1
U.S. Utility SO,, Control System Commitments
Number of
Status Units
Operational 21
Under Construction 23
Contract Awarded 9
Letter of Intent 11
Requesting/Evaluating Bids 8
Pre-Bid Period 46
TOTAL 118
Generating Capacity (MW)
3,300
7,500
3,800
4,700
3,900
24.000
47,200
194
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A few processes have had important commercial-scale experience in coal-
fired applications; most significant experience has been with processes
that produce a waste form of the sulfur for disposal, rather than a by-
product for recovery. Most of the leading by-product recovery processes
have yet to be tested on long-term basis in coal-fired applications.
However, a few processes, such as the Wellman-Lord concentrated SO.
process, have been well demonstrated in industrial applications in the
United States and in utility boiler applications in Japan. Four of
these units are in operation in Japan on oil-fired boilers and on the
tailgas stream coming from Glaus plants. (A Glaus plant converts SO-
into elemental sulfur.)
The status of each of the processes is discussed briefly below:
C.9.2.2.1 Waste Salt Processes - These processes produce varying types
of sulfite and sulfate salts which must be disposed of in an environmentally
acceptable manner. These processes account for over 90% of the systems
currently committed for SO- control and can be expected to maintain this
dominant position in applications which will become operational over
the next ten years. Of these waste salt or "throw-away" processes, a
very large fraction involve some version of lime or limestone slurry
scrubbing to produce a solid waste calcium sulfite/sulfate for disposal.
The most prominent waste salt processes are based on lime, limestone and
double alkali reactants.
C.9.2.2.2 Concentrated SO,., Processes - These processes produce con-
centrated SO- gas streams from dilute flue gas S0«. Conventional, comi-
mercially proven technology is available for the further conversion of
the concentrated S0« produced by these processes into either liquid S02»
sulfuric acid, or elemental sulfur.
Liquid SO- is produced by compression of the SO- stream after the gas
from the process has been concentrated and dried. Sulfuric acid is
produced by oxidizing the S02 to SO, and absorbing the gas in water.
195
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Elemental sulfur is produced from concentrated SO- by direct reduction
or by reactions involving other chemicals.
The main direct reduction process employs natural gas (methane) using
technology offered by Allied Chemical and commercially demonstrated in
a smelter application at Falconbridge Nickel on a 500-ton/day sulfur
plant. The demonstrated capacity of this process is about the equivalent
of the potential sulfur production from a 1500-megawatt utility plant
running on high-sulfur coal.
Other conventional conversion technology, involving reaction of H-S and
S09 to produce sulfur (Glaus process), can also be used. Such an approach
requires generation of hydrogen for the production of H-S and the reduction
of the SO- instead of direct reduction with natural gas. Hydrogen can
be generated by several approaches that differ in capital cost and from
several feedstocks that differ in availability and cost.
The leading processes in this category are the Wellman-Lord process
and the Magnesia Scrubbing process.
C.9.2.2.3 Direct Sulfuric Acid Processes - In these processes, sulfuric
acid is produced directly with no intermediate concentrated SO- gas
stream. A more dilute acid is produced than the normal commercial 98%
acid grade. Operations involving this approach are still in the
experimental stage. The outlook is not promising for this process category
because no successful applications have been developed after several years
research.
C.9.2.2.4 Elemental Sulfur Processes - These processes produce elemental
sulfur or hydrogen sulfide directly, with no intermediate production of
concentrated SO-. Hydrogen sulfide can be converted directly to elemental
sulfur using commercially available technology (Glaus process). The
EPA is currently reviewing proposals based upon some of these processes
for funding of a 100-megawatt coal-fired demonstration plant for a sulfur
196
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recovery process. Processes in this category include:
• Charcoal absorption - Westvaco, Foster-Wheeler
• Citrate process - Arthur G. McKee
• Potassium thiosulfate system - Conoco Coal Development
• Sodium phosphate process - Stauffer Chemical/Chemico
• Dry carbonate process - Atomics International
• Ammonia process - Catalytic
All of these processes require some type of reducing gas (hydrogen,
carbon monoxide or natural gas) to produce the elemental sulfur, with
the exception of the Foster-Wheeler process, which uses a special char
for the reduction of SCL to elemental sulfur.
All of these processes are in the earlier stages of development, and
cannot be expected to have any important commercial impact until about
the mid-1980's.
C.9.2.3 Present Work in FGD Systems
The FGD technology is considered a proven technology by the EPA. Thus
present work includes removing operational problems and improving the
reliability of the systems. The current work includes the following:
• Problems associated with reheat
• Operation of mist eliminator
• Scaling and plugging of the system
• Disposal of waste sludge in environmentally acceptable manners
It is now necessary that utility people gain experience in the operation
of these systems. It is expected that the reliability of these systems
will improve with increased familiarity of the systems by utility personnel.
C.9.2.4 FGD Process Economics
\
Over the past few years the costs for construction and operation of SO.
control systems for utility boiler applications have increased markedly,
because of:
197
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• Improvements in systems to achieve greater reliability.
• Revisions of costs for systems as processes emerged from the
development stage to full-scale installations and actual capital
cost information based on operating experience became available.
• General escalation in the cost of materials, equipment and labor.
Capital costs have increased from $20-30/KW of boiler capacity to $50-80/KW,
depending upon the application. Costs have more or less stabilized in
1975.
Table C.9-2 contains a summary of generalized, relative economics of the
process types which have achieved the most advanced stage of development
and demonstration and which are likely to have the greatest level of
acceptance and application by the utility industry over the next ten
years. Table C.9-3 gives the detailed cost breakdown for a double alkali
(same cost for lime scrubbing) method.
Capital costs, given as dollars/KW of installed boiler capacity, are
consistent on a relative basis for the process types and on an absolute
basis are 1975 bid prices (with no inclusion of escalation over the
course of the project) for a new 800-megawatt, high-sulfur, coal-fired
application. The capital costs would not change appreciably on a $/KW
basis on larger applications or on applications down to about 150 megawatts
because of the modular nature of the systems at and above the 150 megawatt
level. The costs are also consistent with relatively simple retrofit
situations; more difficult retrofit situations could increase the costs
very significantly. The capital costs include on-site disposal ponds
(for solid waste disposal), but do not include any treatment facility
for fixation of the wastes or plants for conversion of the concentrated
SO to elemental sulfur or sulfuric acid; these are all handled as
separate items under disposal and conversion costs.
The operating costs are on an annualized basis at an 80% load factor,
include capital charges and are given in cents/MMBtu of fuel input to
the boiler.
198
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Table C.9-2
Utility S0? Control Process Economics
Capital Cost Annual Operating
Process ($/KW) Cost6 (c/MMBtu)
Lime Scrubbing 60 35.4
Disposal Cost - 6.5
Total Cost (with Disposal) 60 41.9
Concentrated SO. Operations 70 42.6
Acid Conversion Cost 7 2.5
Acid By-product Credit _^ (2.1)
Total Cost (to Acid)E 77 43.0
Sulfur Conversion Cost 9 8.6
Sulfur By-product Credit _^_ (3.0)
T7
Total Cost (to Sulfur) 79 48.2
A - 800-megawatt base load plant burning 2.6%S coal to produce 70,000
ton sulfur/year (80% load factor, 80% removal S02). New Unit or
simple retrofit.
B - Includes capital charges (at 18% capital investment/year), labor,
maintenance plus variable costs (including lime at $30/ton CaO).
C - Disposal @ $10/ton dry solids
D - Natural Gas @ $2.00/Mcf
E - Total annual cost (including all capital charges) to final form of
sulfur removal from flue gas.
Note: The capital cost and the operating cost will be approximately
15% higher for 91% removal efficiency (giving sulfur emissions
in flue gas equal to emissions from burning 0.3%S fuel).
199
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Table C.9-3
Double Alkali FGD Systems
Capital Cost, $/kw 60.0
Operating Costs (c/MMBtu)
Capital Charges, @ 22% 15.8
Lime 5.3
Na2C03 1.8
Operating Labor Cost 2.7
Maintenance Cost 2.7
Electricity, @ $0.02/kwh 1.0
Reheat, @ $2.00/MMBtu 3.2
Materials 2.7
Total Operating Cost (
-------
Where waste treatment and disposal of waste solids by fixation processes
are required, the cost is shown as a separate cost, which is added to
the annual operating cost, to give a total annual operating cost.
The conversion of concentrated S0« to sulfuric acid and elemental sulfur
(using either natural gas, if available, or else hydrogen or carbon
monoxide) is shown separately. The conversion costs include capital
charges on the investment (at 22%/year) for the conversion facility
as well as other operating costs for the conversion to the final product.
By-product credits, as indicated, are used to reduce the conversion
costs and the net conversion cost (or credit) is added to the annual
operating cost to produce concentrated SO-, giving the total annual
costs to produce the final by-product form.
Flue gas desulfurization cost varies from 40 to 45c/MMBtu (37.9 to
42.7C/GJ). This represents $2.35 to $2.65/bbl additional cost when
using high sulfur fuel oil. The current cost of 2.8%S residual oil
is roughly $10.00/bbl. Thus, the cost of desulfurization adds about
25% to the oil cost.
The cost of energy used in flue gas desulfurization is about 10% of the
total cost. Thus, a 10% increase in energy cost will cause a 1% rise
in flue gas desulfurization cost, and thus an 11% overall cost of
obtaining flue gases meeting the applicable standards.
C.9.2.5 Application of FGD Systems to Industrial Boilers
Industrial boilers differ from the utility boilers primarily in their
average capacity with the industrial boilers being generally fairly
small. While the FGD technology for industrial boilers and utility
boilers is the same, the application of FGD systems to industrial
boilers has so far been limited to only a few installations. This is
due to the fact that the industrial boilers represent a secondary small
sized market for FGD systems which has been relatively neglected to date
in favor of concentrating on utility boilers.
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The cost of SOp control on small boilers is expected to be high. A
six-tenth rule generally may be applied to determine the capital invest-
ment for a FGD system for a boiler having a capacity less than 150
megawatts. That is, the ratio of the capital investments for two
different sized boilers varies as the six-tenth power of the ratio of
their capacities. Thus, a 100 megawatt double Alkali FGD system would
cost about $47 million to install.
C.9.3 PRE-COMBUSTION SULFUR REMOVAL
An alternate approach for meeting SO limitations in the flue gas is to
X
desulfurize the residual fuel oil before it is used in the boiler. The
sulfur removal may occur during the manufacture of the fuel oil, in
which case the refiner provides the capital investment for the equipment,
maintains the operations and pays for the processing; or it may be done
by the fuel user, in which case it is the user who provides the capital
investment, etc. Below we discuss catalytic desulfurization of residual
fuel oil as part of the refining process and the CAFB process.
C.9.3.1 Catalytic Desulfurization of Residual Fuel Oil
The applicability of catalytic desulfurization in a petroleum refinery is
determined principally by the characteristics of the crude oils to be
processed and the end-product sulfur specification, as 90+% sulfur removal
is technically feasible for most residual stocks. Most of the fuel oil
desulfurization facilities installed to date have been based on the
"indirect" route, but six direct desulfurization units have been installed
since 1967 (five in Japan), and this route will be applied to a much
greater extent as sulfur specifications become more stringent.
Before describing the differences between direct and indirect catalytic
desulfurization, the properties of crude oils which make these two
processes necessary are described.
C.9.3.1.1 Feedstock Properties Affecting Desulfurization - The most
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important feedstock property with respect to influence on the desulfur-
ization of crude oil is the metals content. Organometallic compounds,
principally porphyrins containing nickel and vanadium, will usually de-
compose on the catalyst surface resulting in metal deposition. Although
catalysts can tolerate substantial metal deposits, ultimate deactivation
is irreversible. The effect on economics of catalyst replacement cost,
catalyst inventory and/or reduced operating efficiency due to catalyst
changeouts is substantial for high-metals stocks. The concentration of
metals in reduced crudes varies widely, from around 35 ppm Ni + V (nickel
and vanadium) in Light Arabian and 60 ppm in Kuwait to about 250 ppm
in Iranian Heavy and nearly 700 ppm in Venezuelan Bachaquero. In addition
to the inherent metals content of the feed, the severity of processing
(the degree of desulfurization and difficulty of processing), affects the
amount of metals deposited on the catalyst.
The asphaltenes content of the residue reflects the type of structure in
which the sulfur is bound, i.e., a high asphaltenes content indicates
multi-ring, sulfur-containing hydrocarbon structures which require high
processing severities for sulfur removal. Further, asphaltenes are
thermally unstable and thus easily convert to coke on the catalyst surface
which reduces the activity of the catalyst. Asphaltenes generally
correlate positively with asphalt yield and sulfur content and direct
desulfurization may be required to produce low-sulfur fuel oil from high-
asphaltene residue. The sulfur content of the end-product would be sig-
nificantly greater if the large proportion of asphalt were bypassed around
the catalytic section as in indirect desulfurization.
Table C.9-4 (see also Table C.3-5) shows a classification of some widely
available crude oils according to direct catalytic desulfurization pro-
cessing characteristics:
• Type I (low metals, low asphaltenes). Can be desulfurized
relatively readily by direct hydroprocessing.
• Type II (moderate metals, low asphaltenes). Can be desulfurized
directly, but catalysts costs will be a more important factor In
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Table C.9-4
Properties of Atmospheric Residues
From Widely Available Crudes
Type I
Murban (Abu Dhabi)
Zakum (Abu Dhabi)
Qatar
Arabian Light
Kuwait
Type II
Iranian Light
Kirkuk
Type III
Arabian Heavy
Khafji (Arabian)
Type IV
Iranian Heavy
Tia Juana (Venezuela)
Bachaquero (Venezuela)
Crude
Production
xlO3
Residue Properties
2,800+
500
960
330
2,400+
330
600
Sulfur,
Wt.%
Ni + V,
2.4
3.8
4.3
4.1
2.5
2.2
3.1
102
80
102
90
230
300
680
Asphaltenes,
Wt. %
800+
300
555
5,300
2,800
1.6
2.0
3.0
3.0
3.9
1
5
30
34
60
0.1
0.2
~1.4
~2.5
2.6
-1.5
3.3
7.6
6.4
3.3
-11
8-9
A - 1973 approximate production, derived from Oil & Gas Journal.
Source: See Table C.3-5 for source reference.
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scheme selection than for Type I.
• Type III (moderate metals, high asphaltenes). May be processed
by direct desulfurization, but processing severity (hydrogen
partial pressure, catalyst inventory) and/or product sulfur
level will be higher than when processing Type I stocks.
• Type IV (high metals contents). Catalyst life will be low with
direct processing; the impetus to follow an alternative scheme
is very strong.
C.9.3.1.2 Direct Versus Indirect Desulfurization Processes - The expected
properties of the crude oils to be used in a refinery determine what
processing units will be used once a particular set of desired end-
products has been chosen. To produce low-sulfur residual fuel oil from
high-sulfur crudes, desulfurization units must be used: direct or indirect
desulfurization is chosen depending on the expected crude types. Figure
C.9-1 is a simplified illustration of these two processes.
In direct desulfurization reduced crude from the atmospheric distillation
unit is charged, along with makeup hydrogen, to the desulfurization unit,
which yields low-sulfur fuel oil and small quantities of naphtha and
light gases. Hydrogen sulfide is removed from the gases and converted
to elemental sulfur. The hydrogen generally would be produced from light
gases or naphtha since sufficient hydrogen usually would not be available
from catalytic reforming of naphtha in the refinery and the quantity of
hydrogen required for desulfurization will not justify the installation
of a partial oxidation unit. The output from the desulfurization unit
is a very low sulfur fuel oil with a sulfur content of 0.3% by weight.
This very low sulfur content can be reached even when using a residuum
containing 3.8% sulfur (such as from Saudi Arabian crude)—i.e. 3.5%
by weight of the residuum charged to the unit is removed as sulfur.
Such a removal of sulfur is not possible with indirect desulfurization
which in general can only produce a low sulfur (0.7% by weight) residual
fuel oil. The word "indirect" is slightly misleading and the process
205
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Figure C.9-1
Simplified Illustration of Direct and Indirect
Desulfurization Units
Direct Desulfurization
Crude Oil
Atmospheric
Distillation
Unit
1
Residuum
Desulfurization
Unit
T
very low sulfur
residual fuel oil
Indirect Desulfurization
Crude Oil
Atmospheric
Distillation
nit
Residuum
Vacuum
lower sulfur
Vacuum
Distillation
Unit
uverneaas
^
Desulfurization
Unit
v
resi
Asphaltic Bottoms
dual fue]
206
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be better described as a "partial by-pass" process, as is shown in the
bottom part of Figure C.9-1. In indirect desulfurization the residuum
stream from the atmospheric distillation unit is sent to the vacuum
distillation unit where the asphaltic compounds (along with most of
the metals and a fair proportion of the sulfur) are separated from the
rest of the stream. The vacuum overheads stream is sent to the desulfur-
ization unit where the same process as for direct desulfurization takes
place. After the desulfurizer the asphaltic bottoms are added back in to
produce low sulfur residual fuel oil. It should be noted that any asphalt
product production would be from the asphaltic bottoms and would lower
the sulfur content of the residual fuel oil, but for a comparison of the
two processes we have recombined the two streams.
The output from the indirect desulfurization process is usually about 0.7%
sulfur fuel oil. This can only be accomplished if medium sulfur content
residuum is used such as from Iranian Heavy oil which contains 2.5% sulfur.
Indirect desulfurization cannot remove as much sulfur as direct desulfur-
ization so is limited in application if very low sulfur fuel oils are
needed.
C.9.3.1.3 Comparative Costs of Residuum Desulfurization - Some indication
of relative costs can be obtained by considering economics based on two
types of Middle East crudes. For this purpose, we have studied the
processing of residues derived from a 50/50 blend of Arabian Light and
Arabian Heavy crudes and from Iranian Heavy crude, representing, respec-
tively, a high-sulfur, moderate-metals (Type I or II) stock and a moderate-sulfur,
high-metals (Type IV) stock. The direct desulfurization processes have
been set to produce 0.3% sulfur fuel oil so as to facilitate economic
comparison with the CAFB process. The indirect desulfurization process
is shown producing 0.7% sulfur fuel oil since it cannot produce a 0.3%
product.
We have shown costs for Saudi Arabian crude since it is the benchmark
crude oil for OPEC. However, for comparison with the CAFB process we
207
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have used Iranian Heavy since it has high sulfur and high metals, both
of which properties are similar to what the CAFB process will accept.
We have chosen the Unibon process (licensed by UOP Process Division)
as the basis for developing our cost estimates. The Unibon process
is more limited than the H-Oil process in its ability to treat high
metal vacuum residues without a prior deasphalting step; however, the
costs for the processes are comparable.
"Typical" costs of process utilities for project assessment are un-
predictable, considering the uncertainty of future energy values, but
the values used in our comparisons are:
Power $0.02/kwh
Cooling Water $0.03/103 gal
3
Condensate $0.30/10 gal
3
Boiler Feedwater $1.00/10 gal
3
Steam (high pressure) $3.00/10 Ib
Fuel $2.00/106 Btu
All costs reflect integration of the desulfurization unit into a grass-
roots refinery or power plant. A nominal refinery on-stream efficiency
of 330 stream days per year was applied. The cost figures were obtained
from Conser* (1974) and updated to December 1975 dollars.
C.9.3.1.3.1 Arabian residuum - Table C.9-5 summarizes investment and
operating costs for the desulfurization of Arabian Light/Arabian Heavy
reduced crude. The Arabian reduced crude blend, having relatively high
sulfur and relatively moderate metals contents, is a favorable stock
for direct desulfurization. Table C.9-5 costs are shown for the production
of 0.3% sulfur fuel oil when processing 20,000 and 40,000 B/SD of charge.
The costs range from 52 to 57c/MMBtu (49 to 54(?/GJ) depending on the size
of the desulfurization unit.
Conser, R. E., "Management of Sulfur Emissions," presented at the NPRA,
72nd annual meeting, Miami, 1974.
208
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Table C.9-5
Desulfurization Costs for Arabian
Reduced Crude Mixture (3.8% S)
(Direct Desulfurization to 0.3% S)
Plant Capacity, B/SD 20,000 40,000
Capital InvestmentA, $ 48.7 x 106 81.7 x 106
Operating Costs, $/bbl
H2 Plant Feed + Fuel (net) 0.92 0.92
Other Utilities 0.51 0.51
Catalyst/Acceptor/Chemicals 0.27 0.27
Labor/Overhead 0.15 0.12
Maintenance @ 3% of Investment 0.25 0.21
Fixed Charges, @ 18% of Investment 1.50 1.26
TOTAL, $/bbl 3.60 3.29
TOTAL, $/106 Btu 0.57 0.52
BASIS:
• 3.8% S fuel
• 92% S removal efficiency (0.3% S in final product)
• December 1975 dollars
• Operating factor - 7,000 hr/yr
A - Includes HDS unit, hydrogen and sulfur plants.
B - 6.3 x 106 Btu/Bbl of desulfurized oil (HHV).
209
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C.9.3.1.2.2 Iranian Heavy residuum - With Iranian Heavy residuum it is
less expensive to produce 0.3% sulfur fuel oil than with Saudi Arabian
crude because less sulfur must be removed from the Iranian crude. As
Table C.9-6 shows, using direct desulfurization with Iranian Heavy
residuum costs 44.5 to 50<:/MMBtu (42 to 47
-------
Table C.9-6
Desulfurization Costs for Iranian
Heavy Reduced Crude (2.5% S)
(Direct Desulfurization to 0.3% S)
Plant Capacity, B/SD 10,000 20,000 40,000
Capital Investment, $10 25.4 41.9 69.2
Operating Costs, $/bbl
H2 Plant Feed + Fuel (net) 0.59 0.59 0.59
Other Utilities 0.43 0.42 0.41
Catalyst/Acceptor/Chemicals 0.35 0.35 0.35
Labor/Overhead 0.23 0.12 0.07
Maintenance @ 3% of Investment 0.26 0.22 0.18
Fixed Charges @ 18% of
Investment 1.57 1.29 1.07
TOTAL, $/bbl 3.43 2.99 2.67
TOTAL, $/106 Btu 0.57 0.50 0.445
Basis: • 2.5% S fuel
• 88% S removal efficiency (0.3% S in final product)
• December 1975 dollars
• Operating factor - 7,000 hr/yr
211
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Table C.9-7
Desulfurization Costs for Iranian
Heavy Reduced Crude (2.5% S)
(Indirect Desulfurization to 0.7% S)
Plant Capacity, B/SD 20,000 40,000
Capital Investment, $10 32.3 53.3
Operating Costs, $/bbl
H2 Plant Feed + Fuel (net) 0.35 0.35
Other Utilities 0.57 0.56
Catalyst/Acceptor/Chemicals 0.07 0.07
Labor/Overhead 0.12 0.07
Maintenance @ 3% of Investment 0.17 0.14
Fixed Charges @ 18% of Investment 1.00 0.82
TOTAL, $/bbl 2.28 2.01
TOTAL, $/106 Btu 0.38 0.335
Basis: • 2.5% S fuel
• 72% S removal efficiency (0.7% S in final product)
• December 1975 dollars
• Operating factor - 7,000 hr/yr
212
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residual oil offers an alternate to the processes discussed earlier.
Westinghouse Research Laboratories have prepared a process evaluation
and demonstration plant design. The following evaluation of the CAFB
*
processes is summarized from work done by Westinghouse in 1975. Specific
evaluation of the CAFB process was outside the scope of the ADL study.
C.9.3.2.1 Conclusions From Westinghouse Report - The conclusions and
recommendations based on the results of the Westinghouse evaluation are
quoted below:
"Market
0 Atmospheric-pressure operation of the CAFB process is most
applicable to the electrical utility industry as a boiler
retrofit for oil- or gas-fired boilers. The atmospheric-
pressure process is not generally attractive for new
boilers or retrofit of coal-fired boilers because of the
current trend toward coal. The largest market is for
boiler sizes ranging from 50 to 400 MW.
0 Vacuum bottoms or other low-grade high metals content
fuels are the fuels most likely to be available for the
CAFB process.
0 Limestone availability for CAFB may be more restricted
than for slurry scrubbing processes due to more stringent
requirements on sorbent physical properties with CAFB.
0 Potential markets for CAFB by-product/waste stone are un-
certain.
Technology
0 Environmentally3 CAFB appears superior to Ifime and lime-
stone slurry flue-gas scrubbing because of the reduced
impact of nitrogen oxide, solid waste, and process water
requirements.
"Fluidized Bed Combustion Process Evaluation," EPA-650/2-75-027-a, study
conducted by Westinghouse, March 1975.
213
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Higher fuel efficiencies are realized with CAFB than with
HDS.
The ability of CAFB to utilize low-grade petroleum or
synthetic fuel fractions with high metals content provides
the potential for a fuel source which may not be feasible
with EDS or stack-gas cleaning processes.
CAFB is in a much earlier state of development than is
lime/limestone slurry scrubbing or HDS, although major
development work is still required in slurry scrubbing
processes to demonstrate reliability. [See also section C.9.2.
in this report on FGD.]
CAFB has the potential to offer high reliability and lower
space requirements than lime/limestone slurry scrubbing.
It has not been established whether there is, in general,
sufficient physical space at a majority of boiler plant
sites for either CAFB or slurry scrubbing retrofit.
The utilization of a clean fuel, such as from EDS, is
the most convenient technological option available to
the utility.
Economics
The capital cost of CAFB is 25 to 50 percent greater
than that of limestone scrubbing and is comparable to
regenerative stack-gas cleaning costs. [ADL note—Table 8
in Westinghouse EPA 650/2-75-027-a—Summary Report—suggests
the range is more like 100-120 percent greater.]
The fuel adder for CAFB is competitive with limestone
scrubbing if low-grade fuels available to CAFB are 10 to
o
20
-------
unless a unit larger than 25,000 bbl/d is built to
supply move than three 200 MW boilers, or a unit larger
than 353000 bbl/d is built to supply two 500 MW boilers.
Thusj HDS requires more immediate commitment of capital
than would a single CAFB unit-."
C.9.3.2.2 Cost of CAFB Process - Using the Stone & Webster/Westinghouse
design and cost analysis as a basis, the economics of the CAFB process
were adjusted to conform to the basis used in the FGD and HDS cost
evaluations presented earlier. In addition, the CAFB costs are based
upon a twenty percent air/fuel ratio, which corresponds to the ratio
existing in most of the pilot plant runs. Desulfurization costs for
CAFB are shown in Table C.9-8. Electric power consumption is the largest
variable cost factor. The capital charge per million Btu's is relatively
high compared to other processes discussed.
C.9.4 SELECTION OF THE DESULFURIZATION PROCESS
Up to now our discussion has focused on the various methods available
to produce low sulfur emissions in the flue gases of an oil-fired boiler.
In each case we have developed a cost for comparable sulfur removal by
each process. Before making a cross-comparison among the processes we
need to point out some of the other factors beyond the pure "cost per
million Btu's" which need to be, or will be, considered by decision
makers.
C.9.4.1 Selection Criteria
These selection criteria affect both the pre- ancj post-combustion
desulfurization alternatives. Some of the major considerations are:
1. The user may wish to maintain flexibility of fuel supply
by using a post-combustion process rather than be dependent
on petroleum refiners marketing low-sulfur fuel oil.
2. A petroleum refiner installing direct desulfurization
facilities for use with Arabian crude stock, for example,
215
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Table C.9-8
Desulfurization Cost for CAFB (2.6% S Fuel)
Capacity
Capital Investment (C.I.) (1975), $10
50
9.5
200
28.2
Operating Costs
Electric Power
Limestone
Labor and Overhead
Maintenance (L&M)
Solid Waste Disposal
Unit Costs
$0.02/kwh
$30/ton
$8/man-hr
4% C.I.
$10/ton
C/10 Btu
11.8 11.8
1.8 1.8
8.5 2.1
5.9 4.7
0.7 0.7
Capital Charges, 18% of C.I.
Total Operating Cost, C/10 Btu
48.9 36.3
77.6 57.4
Basis: • 20% Air/Fuel ratio
• Operating Factor - 7,000 hr/yr
216
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would incur significant additional costs and lower operating
efficiency when processing other stocks which had higher
metals contents. The same alternate stocks would not create
similar problems for the fuel oil user with flue gas de-
sulfurization or CAFB facilities where the costs relate more
closely to sulfur content than to metal content.
3. A petroleum refiner installing indirect desulfurization
facilities for use with Iranian crude oil, for example,
could be limited in the amount of high-sulfur crudes
that he could process while meeting product sulfur
specifications since indirect desulfurization is in-
herently limited in the amount of sulfur which it can
remove. A fuel user with flue gas desulfurization or CAFB
facilities enjoys more flexibility in this respect.
4. The comparisons have been based on an equivalent rate
of return on desulfurization facilities installed by
the petroleum refiner and the user. The user might
be able to include a relatively lower rate of return
(utility basis) in his assessment of a flue gas desulfur-
ization or CAFB installation as the alternative to paying fpr the
petroleum refiner's full charges for risk and profit
in the price of the low-sulfur fuel oil.
5. Pre-combustion desulfurization is less efficient with
respect to overall energy considerations than flue-gas
desulfurization—i.e., lesfs energy is consumed for an
equivalent degree of flue gas desulfurization than for
residuum desulfurization. Increased energy costs or
government policy with respect to energy conservation
could enhance the influence of this factor.
6. The user may prefer not tp take on the responsibility of
a processing step involving the sale or disposal of sulfur
and thus may prefer to shift the responsibility for desulfur-
ization to his supplier if other economic and technical factprs
217
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are a standoff.
The economics of heavy oil catalytic desulfurization are more favorable
in comparison with stack gas desulfurization for Type I crudes (Arabian)
than for Type IV crudes (Iranian Heavy). Processing costs for either
kind of residual fuel oil catalytic desulfurization and flue gas desulfur-
ization are sufficiently close that individual decisions will be made in
the context of the processing characteristics of the range of residuums
expected to be available, the flexibility required in the proportions
and types of these stocks, government policy, and individual approaches
to the assessment of capital projects.
C.9.4.2 Comparison of Operating Costs of Desulfurization Alternatives
The above selection criteria will be very important in deciding which
particular process will be selected by an individual user. But the
decision must also look to economics and to that end we have prepared
Table C.9-9 which summarizes the operating costs for the CAFB, FGD
and catalytic desulfurization processes. The economics for FGD are
based upon the Double Alkali process while the particular catalytic de-
sulfurization costs shown are for the RCD Unibon process.
The CAFB information on Table C.9-9 is generally in agreement with the
Westinghouse assessment but with some shifting in the ranges. For example,
this comparison indicates that catalytic desulfurization would be com-
petitive down to a capacity of 250 MW (10,000 Bbl/day).
The results of our technical assessment are summarized as follows:
• Flue gas desulfurization is the lowest cost option for
sulfur control. The technology is further advanced than
CAFB, but is not particularly effective for NO control,
X
and offers no protection against ash deposition on boiler
tubes and supports.
218
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to
I-1
VO
Table C.9-9
Comparative Desulfurization Costs
Plant Capacity, MW
Capital Investment, $/kw
Operating Costs, C/10 Btu
Electric Power
Other Utilities
Catalyst/Chemical
H2 Plant Feed + Fuel
Labor & Overhead
Maintenance (L&M)
Solid Waste Disposal
Capital Charge @ 18% CI
TOTAL OPERATING COST, C/10 Btu 77.6 57.4
Basis: 2.6% Sulfur Residual Oil; "90% sulfur removal
Operating Factor - 7000 hrs/yr
CAFB
50
190
11.8
— —
1.8
—
8.5
5.9
0.7
48.9
200
141
11.8
— —
1.8
— —
2.1
4.7
0.7
36.3
FGD
(Double Alkali)
150
60
1.0
3.2
7.1
• —
2.7
5.4
6.5
15.8
Catalytic Desulfurization
(RCD Unibon)A
B
250(10)
102
7.1
5.8
9.8
3.8
4.3
—
26.2
500(20)
84
7.0
5.8
9.8
2.0
3.6
«
21.5
1000(40)
69
6.8
5.8
9.8
1.2
3.0
—
17.8
41.9
57.0
49.7
44.4
A - Licensed by UOP Process Division
B - Value in parenthesis is volume in MBCD.
Sources Westinghouse Research, Universal Oil Products and ADL Estimates.
-------
• Catalytic desulfurization is less costly than CAFB in the
capacity range above 250 MW (10,000 Bbl/day) which is
generally the capacity suitable for a large modern refinery.
• When compared to catalytic desulfurization, CAFB appears to
have a cost advantage in the capacity range from 50 to 250
MW, and is less sensitive to resid quality than catalytic
desulfurization.
Although the CAFB process is currently shown to have a cost advantage
for a certain capacity range, its status of development is less advanced
than the competing alternatives. Historically, the cost of flue gas
desulfurization increased as the various processes approached commerciali-
zation. Consequently, it would be unusual if the costs associated with
CAFB do not escalate before the first commercial system is installed.
220
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C.10 RESIDUAL FUEL OIL HANDLING PROBLEMS
C.10.1 INTRODUCTION
Much residual fuel oil is consumed at locations which are accessible to
water-borne transports because residual fuel oil requires special
handling in transportation and water-borne transports are the mosjt con-
venient way of moving resid. For residual fuel oil to be used at locations
remote from waterways special problems must be considered and overcome.
This chapter discusses the specific handling problems associated with
residual fuel oil and mentions several of the ways these problems have
been overcome. The chapter begins with a brief description qf the
relevant physical properties of residual fuel oil, then discusses the
various modes of transportation and finally discusses problems of resid
storage.
C.10.2 PHYSICAL PROPERTIES
The main physical properties of concern for the transportation of
residual fuel oil are its viscosity and pour point. Also briefly
discussed are several other properties.
C.10.2.1 Viscosity
Viscosity is a measure of the resistance of a fluid to shear or flow
and can be reported or measured in a number of ways.
In the case of fuel oils it is commercial practice in the U.S. to quote
the viscosity as measured on the Saybolt viscometer, where the time,
measured in seconds, for a given volume of oil at a constant temperature
to flow through an orifice of standard size is given as a measure pf the
221
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viscosity of the oil. Thus, the higher the viscosity value reported,
the longer it took for the oil sample to flow through the orifice.
Clearly, a viscosity of "infinity" indicates the oil will not flow at
the test temperature.
The viscosity of more mobile oils is recorded as Seconds Saybolt
Universal (SSU) at 122°F (50°C) but for more viscous oils similar
instruments with larger orifices are used so that the time of flow is
reduced to about one tenth of that taken with a smaller orifice. The
viscosity is then given as Seconds Saybolt Furol (SSF) at 122°F. Other
scales of viscosity which are regularly used are Seconds Redwood 1 at
100°F (38°C) and Engler Degrees.
The viscosity of an oil depends on its temperature. Hence, the viscosity
is always recorded together with the temperature of the oil. Residual
fuel oil which has a viscosity of 3,000 SSU at 122°F (50°C) will have a
viscosity of 1,700 SSU at 140°F (60°C) and a viscosity of only 650 SSU
at 180°F (82°C).
Viscosity is most important to the users of residual fuel oil. Too
low a viscosity and the pumps used to move the oil about will not work
properly (mainly a loss of lubrication for the pumps and a loss of
pumping efficiency). Too high a viscosity may lead to premature pump
failure as the pumps are overworked by trying to force the oil through
the pipes.
C.10.2.2 Pour Point
Wax crystals (n-paraffins) contained in residual fuel oils can cause the
fuel oil to gel and plug the pipelines if the temperature of the oil is
permitted to fall below a certain level. As the temperature of the oil
in the pipeline falls below a certain point called the cloud point, the
wax crystals begin to form. As the oil continues to cool, the oil becomes
a slurry of wax crystals in oil which tend to build up on pipe walls,
valves, etc. When the oil cools to a temperature called its pour point,
222
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the crystals become so numerous that they interlock and the oil gels,
stopping the flow.
The pour point of an oil thus represents the lowest temperature at which
an oil can be stored or handled without it congealing in the tanks or
pipe lines, and is thus a value of critical importance for handling
residual fuel oil.
The pour point of residual fuel oils is an inexact measurement and is
only measured to the nearest 5°F (2°C). For a given oil, the pour point
is dependent upon the temperature to which the pil has been previously
heated. Also, the pour point test does not indicate the behavior of
the product under pressure, as in the case of the oil under pipeline
pressure. The static conditions of storage of a large amount of oil
are different from the laboratory test conditions. Hence it is general
practice to keep a safety margin of several degrees between the measured
pour point and the operating temperature of the fuel oil. Typically,
residual fuel oils are handled at about 125-130°F (52-54°C), while most
residual fuel oils have a measured pour point of 60-100"F (16-38°C).
In general, pour point is a less critical specification for residual
fuel oil because users of resid are set up to handle it. For a user £n
the U.S. without heating equipment in the storage tanks pour point is
all critical since he will not be able to use resid because the like-
lihood of the oil temperature occasionally falling below the pour point
is overwhelming. But once the heating equipment is installed, pour point
generally ceases to be a problem affecting storage or usage.
Residual fuel oil which requires special heating equipment before it
can be handled is called "high pour resid" and usually sells at a
slight discount from "low pour resid" which can be used without special
heating equipment. The pour points associated with these two classes of
resid vary with the seasons and by different oil companies, but generally
any oil with a pour point over 60°F (16°C) would be considered high pour.
223
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Clearly, pour points can go quite low—residual fuel oils with pour points
of as low as -20°F (-29°C) can be obtained. It should also be pointed
out that the pour point of an oil affects its viscosity. As the oil
cools down towards its pour point the viscosity increases normally until
the oil is within 5° to 10°F (2 to 5°C) of the pour point. As the wax
crystals begin to form the viscosity begins to increase very rapidly
and reaches infinity at, or near, the pour point.
C.10.2.3 Specific Gravity
Most residual fuel oils have a specific gravity between 0.94 and 1.00,
i.e. almost as heavy as water. When an installation is designed to
handle residual fuel oil, the equipment is dimensioned accordingly and
hence the relatively high specific gravity of this product does not
create any problems.
C.10.2.4 Sulfur Content
Although high sulfur content in residual fuel oils can cause severe
problems as far as its use as a fuel is concerned, it has no effect on
the storage or handling problems. All metal surfaces that come in
contact with the residual fuel oil and are likely to corrode are usually
coated and thus protected.
C.10.2.5 Minimum Operating Temperature
Utility grade residual fuel oils typically have pour points of 60-100°F
(16 to 38°C). It is necessary to maintain the oil above this temperature,
usually around 125-130°F (52-54°C) so that it can be handled at reasonable
pressures at the lowest cost and so that problems with its' pour point will
not be encountered.
When transporting these oils special care has to be taken to ensure that
their temperature at arrival is well above the pour point. This is
achieved by:
• heating the oil to about 160°F (71°C) before it is transported
224
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• reducing the heat loss by insulating the tanks, pipelines, e^c.
• heating the oil intermittently during transportation, or
• a combination of two or more of the above mentioned methods.
C.10.3 TRANSPORTATION OF RESIDUAL FUEL OIL
This section will look at water transports, pipelines, railroads and
trucks as means of moving residual fuel oil. Since sites remote from
water will have special problems in obtaining resid, the emphasis of
this section is on pipelines for heavy oil.
C.10.3.1 Water-Borne Transport of Residual Fuel Oil
C.10.3.1.1 Coastal and River Transport - Over a short distance in
protected waters residual fuel oil is generally carried in barges or in
tanks mounted on barges. The barges do not contain heating coils but
in some cases the deck mounted tanks are insulated.
The oil is loaded at a temperature much higher than the pour point.
Usually the total voyage time is short and hence the oil arrives at
the users location at a temperature at which it can be handled normally.
C.10.3.1.2 Ocean Transport - Residual fuel oil is transported in ocean
tankers which are specially designed to carry and handle high viscosity,
high specific gravity products in bulk. The cargo tanks, which form an
integral part of these tankers are not insulated, though in some cases
they do contain steam-tracings to maintain the temperature of the product
above its pour point. The cost of transporting the product in tankers
with heating coils is higher because the capital costs, repair and main-
tenance costs and voyage costs of such tankers are higher than those of
a tanker without the heating elements. Hence, such tankers are generally
used only when the product and voyage specifications require them and
where their full utilization is assured in a dedicated trade.
When residual fuel oil is transported in tankers without heating coils,
225
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the product is loaded at a temperature sufficiently high so that in
spite of the natural cooling down that occurs during the voyage at sea
the temperature of the oil, on arrival, will still be well above the
pour point.
The cargo handling system of these tankers is specially suited to handling
hot, viscous liquids and the deck pipelines, along which cargo to or
from shore flows are insulated and steam-traced.
C.10.3.2 Pipelines for Residual Fuel Oil
C.10.3.2.1 Hot Oil Pipelines - Over a short distance residual fuel oil
can be transported in an uninsulated pipeline. Typical examples of
such installations are pipelines at tank farms, storage terminals, etc.
where the pipeline is used infrequently for a short period. In some
cases these pipelines are heated by steam-tracing or electricity. Over
longer distances residual fuel oil must be transported in special pipe-
lines. The oil is preheated to about 180°F (82°C) before it is pumped
through the pipeline which, in order to reduce the heat loss, is insulated.
Depending upon such operating factors as the velocity, pressure and
viscosity of the oil in the pipeline, insulation of the pipeline, ground
temperature, and the distance between the initial pumping station and
the terminal, the pipeline system may include a number of pumping stations
and/or reheat stations. Normal design conditions include an inlet
temperature of 180°F (82°C) and outlet of 130°F (54°C) , with 1200 psi
maximum operating pressure.
C.10.3.2.1.1 Design and construction - The design of a "hot oil pipe-
line" is much more complicated than that of a pipeline for crude oil or
other low viscosity products. During the design stage, several factors
such as the physical properties of the residual fuel oil (viscosity,
specific gravity), the insulation system and the selected equipment have
to be balanced in order to obtain the most economical operating conditions
such as inlet and outlet temperatures, maximum operating pressure and
flow rate and the distance between reheat/pumping stations.
226
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The construction of a residual fuel oil pipeline is also elaborate and
expensive, mainly due to the fact that the insulation system has to be
protected against damage during construction.
A typical cross section of a residual fuel oil pipeline will have an
inner steel pipe which actually carries the oil. Its size will depend
on the volume of oil to be transported. Surrounding the pipe is an anti-
corrosion coating which generally will have been applied at the steel
mill. Completely covering the pipe will be insulating material and an
outer protective jacket must be applied to protect the insulation and
permit the pipe to be handled during construction without too much
difficulty. Depending upon the type of insulation selected, it is
applied "in situ" or factory applied before the pipe is delivered at
site. The outer protective jacket thickness can be reduced to about
40 mil. (0.1 mm) if the pipeline is bedded in a soft soil, but where
the soil includes hard materials like rock, a steel casing with bulk-
heads and support systems may have to be used.
Thermal expansion will take place in a steel pipeline carrying heated
oil. This expansion has to be taken up by bellows in the pipe joints
or by making U-shaped loops in the pipe. If the expansion movements are
to be resisted, special anchor blocks have to be incorporated in the
system and the resulting stresses must be within tolerable limits.
C.10.3.2.1.2 Operations - The most significant difference between the
operating procedures of a hot and a normal oil pipeline is the routine
shut-down procedure which must be established.
Short stoppages (e.g^ power failures) can be tolerated on a hot line with-
out the need to clear the line or take steps to prevent plugging. Pumping
normally may be stopped for 3 to 12 hours, depending on the line size,
without undue cooling. When pumping ceases, any heated fuel oil in the
pipeline begins to cool down, and although an insulated line cools more
slowly than a bare line, eventually ground temperature will be reached.
227
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If the pour point of the oil is higher than the ground temperatures,
the oil could gel and plug the line. Several methods may be used to
overcome this difficulty, among them:
• flushing the line
• providing in-line heating elements
• using very high pressure pumps
Clearing the line of high pour material with a low pour flushing oil
requires a ready supply of flush oil. Approximately twice the pipeline
content must be made available for insulated pipelines [one content
for line clearing and one content (or less) for pre-heating after pro-
longed shut-down]. If the flush oil cannot be used at the destination,
a separate tank will be required for its collection and a pump to return
the flush oil to the originating station during the next shut-down (the
same oil can be used a number of times before its pour point becomes too
high). When this stage is reached, it can be disposed of by degrading
into a heavier fuel oil.
To ensure the removal of all the high pour point oil from the pipeline
and to prevent any unnecessary amount of contamination of the flushing
oil if it is not to be consumed, separator elements are used between
the high and low pour oils.
Where normal pumping is by electrically-driven units, the stand-by pump
or pumps should be provided with diesel engine or gas turbine drive,
so that in the event of a power failure, the stand-by pump can be used
to put flush oil into the system.
An electric heating cable may be installed within the pipe, the heating
capacity being calculated so that the temperature of the oil may be
raised from ground temperature to the minimum temperature required to
pump the oil within a reasonable time. When pumping recommences, the
heating may be switched off. This method would be very costly to install
in long pipelines, as power feeder cables would be required along the
228
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pipeline to supply the sections of heating cable. Additional costs will
be involved in areas where no main electricity supply is near at hand.
Providing a high pressure pump to move the gelled oil at a gradually
increasing rate as hot oil is pumped along the pipeline may be economic,
in certain circumstances, particularly for short lines. An accurate
determination of the pressure required to move the oil is essential, and
pipe-wall thickness and pressure rating of fittings must be suitable for
this "cold" pumping duty. With this method it may take a considerable
time to build up to the full flow rate—a time factor which should not be
forgotten when comparing with other methods.
C.10.3.2.1.3 Estimated transport costs - Table C.10-1 is a rough cost
estimate for a 600 mile long insulated hot oil pipeline, based on the
following assumptions:
Flow: 100,000 B/d
Location: Midwest
Cost Base: Mid-1974 Costs
Line Length: 600 miles (966 Km)
Line Size: 16" Outer Diameter (40.3 cm)
0.375" Wall thickness (0.945 cm)
Line Position: Buried 4' (1.22 m) below ground
Insulation: Polyurethane of 2" (5 cm) thickness
Ground Surface Temperature: 0°F (-18°C) (minimum)
Minimum Oil Temperature:' 120°F (49°C)
Oil Temperature at Inlet: 140°F (60°C)
Oil Temperature at Outlet: 120°F (49°C)
Distance between reheat stations: 70 miles (1^.3 km)
Properties of Oil;
Density: 28° API (0.885 units at 15°C)
Pour Point: 110°F (43°C)
Of the almost $l/Bbl operating cost, about 20c/Bbl is accounted for by
the cost of heating the oil plus the capital charge associated with the
one-third of the capital cost accounted for by the insulation require-
ments .
229
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Table C.10-1
Capital and Operating Costs
for a Hot Oil Pipeline
$ Million
Capital Cost:
Basic pipeline plus equipment, land, etc. 100
Heating stations 1
Insulation 48
Total 149
Operating Costs:
Capital charge 25
Operating costs 7
Power and heating 4
Total 36
Total in $/Bbl 0.98
Of which:
Regular Pipeline 0.73
Hot Oil Cost 0.25
0.98
230
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C.10.3.2.2 Residual Fuel Oil Pipelines Without Insulation - Over a short
distance, residual fuel oil can be moved in uninsulated lines, although
as the cost of energy continues to escalate these uninsulated lines
begin to incur substantial energy costs. Because of the high cost
penalty (as shown in Table C.10-1) incurred by hot oil lines, studies
are being carried out to investigate the possibilities of transporting
residual fuel oil over long distances in ordinary product pipelines.
In this case the viscosity of the residual fuel oil would have to be
reduced to an acceptable level by blending it with a diluent with a very
low viscosity. The viscosity of the diluent will determine the ratio of
blending.
Below are some rough estimates of the blending ratios required for some
diluents so that the mixture has a viscosity of 400 SSU at 30°F (-1°C),
a level at which it can be handled easily.
Cold Residual Oil Line Diluents
Product
Gasoline
Kerosene
Diesel #2
Solvent #1
Toluene
Xylene
The blending alternative has several problems linked with it, the main
one being what to do with the mixture at the point of arrival. There
can be two ways of treating this:
• use the mix as is
• separate the components
If mixed with #2 oil, residual fuel oil (#6) can be used as //4 fuel oil,
This would eliminate the need for investment in a separating plant,
231
Viscosity
SSU at 35° F
32.5
33.7
59.0
33.6
33
33
Percent Product
in Blend
26-40
37
55
38
36
36
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storage, etc. but would carry a penalty of the cost differential between
the #2 and #6 oil.
When mixed with gasoline or with hydrocarbon solvents, the constituent:
elements will have to be separated. This method has the following problems
- Additional investment and operating costs for the
separating plant and storage
- Problems of demand and marketing the diluent product
at the point of arrival.
C.10.3.3 Other Transportation Modes
C.10.3.3.1 By Railroad - When residual fuel oil is transported by rail
cars, this is usually done by unit trains which run a shuttle service
between a refinery or tank farm and the industrial user or utility.
Unit trains often consist of up to 50 cars of tank capacities of about
22,000 gallons each (about 525 Bbl, 80 LT).
The rail car tanks are insulated and the oil is loaded at temperatures
well above its pour point. After loading the train proceeds to the
destination with as few stops as possible, and in order to reduce the
turnaround time both the loading and discharging operations are usually
highly automated.
Most unit trains are dedicated to a project and form an integral part
of the user's operations. Hence their capacity and scheduling is designed
to suit the consumption pattern and storage tank capacities at the ter-
minals. One such unit train operation in Canada delivers 25 million
barrels of oil annually over a distance of 375 miles (604 Km).
C.10.3.3.2 Trucks - Residual fuel oil is transported by road tankers
to the smaller users. The truck's fuel oil tanks do not contain any
heating elements and are generally not insulated. Hence the transport
of this product by trucks is limited to short distances and comparatively
232
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small quantities. Most truck transport operations service small industrial
and commercial operations. Due to road traffic problems trucks are not
a reasonable supply system to be used for a large volume residual oil
user.
C.10.4 STORAGE OF RESIDUAL FUEL OIL
The main problem affecting storage of No. 6 fuel oil is to maintain the
oil at a temperature above its pour point. This is done by
- heating the oil by steam fed heating coils, and/or
- by insulating the tanks to reduce the heat loss.
In the past, when the cost of energy was lower, heating the oil was
preferred to insulating the tanks. In addition to the heating costs,
the heating coils incur a higher maintenance cost due to corrosion from
the sulfur content of the oil. With the higher cost of energy there is
an increasing tendency to insulate tanks storing residual fue}. oil or
crude in order to reduce the heat loss.
The following table illustrates the savings achieved by insulating the
tank.
Costs of Fuel Oil Storage Tanks
Uninsulated Good
Parameter Tank Insulation
Heat Loss
(BTU/ft2 - hr.) 155 7
Fuel Cost per yr. $ 95,000 $ 4,300
Insulation Cost - $50,OOQ
Five Year Cost $475,000 $71,500
One other problem in the storage of residual fuel oil is that the wax
contents could cause a problem if the wax were permitted to build up on
the tank sides. Stratification of tank contents could allow this to
happen and, even when tanks are heated, mixers are considered necessary
233
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to prevent such stratification. Furthermore, mixers keep water and
sludge stirred up and in motion, helping to prevent bottom sedimentation.
234
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C.ll FUTURE RESIDUAL FUEL OIL DEMAND
C.ll.l INTRODUCTION
The level of future demand for residual fuel oil will ultimately depend
on the outcome of the factors discussed in the previous chapters. How-
ever, in order to provide an estimate of the quantitative impact of
these factors, we tried to review recently published forecasts to obtain
a consensus view of futurfe demand on a PAD district basis. Unfortunately,
the publicly-available forecasts were deficient on two important counts:
the data was presented only on an aggregate national basis (i.e. no
regional or PAD district breakdown) and/or no product breakdown was given.
In fact, we were unable to Ipcate any reliable recent public forecasts
which split national oil or product demand out by PAD districts or regions.
Only one forecast, the Exxon forecast of December, 1975*, indicates an
estimate of residual fuel oil usage, and that estimate is limited to the
residual fuel oil consumed by electric utilities.
The lack of recent published forecasts on a regional or prpducf basis
leaves only the more general primary energy forecasts for the total U.S.
In the following section we present the conclusions of a representative
sampling of these primary energy forecasts and comment as to how we would
expect residual fuel oil demand to be related to the oil growth indicated
in the forecasts. We will also discuss briefly the extent to which we
believe that residual fuel oil demand might be met from domestic refining
sources.
"Energy Outlook, 1975-1996", December, 1975, Exxpn Company, U.S.A.
(including press release documents dated December 9, 1975).
235
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In the event that the EPA decides to do further analysis of the potential
demand for the CAFB process, it would be advisable to obtain a specific
regional forecast of residual fuel oil consumption. The undertaking of
the creation of such a forecast is clearly outside the scope of the present
contract. However, in the event that EPA should proceed with their
analysis of the feasibility of the CAFB process, a forecast should be
made involving specific consideration of growth in demand by end-use
sectors on a regional basis, as well as a thorough study of the regional
impact of natural gas curtailments and nuclear plant delays. On the
supply side, the forecast should focus on the changes in average yields
of residual fuel oil by domestic refiners, and on the availability of
residual fuel oil from foreign refining sources.
C.11.2 RECENT FORECASTS OF PRIMARY ENERGY BALANCES
Table C.ll-1 summarizes the projections of primary energy balances as
stated in a representative sample of recent public forecasts. It is
necessary to be cautious in comparing these forecasts directly one with
another since the underlying assumptions behind each forecast tend to
differ. However, some general trends are revealed by reviewing these
forecasts. Total energy demand is projected to reach 96.1 to 103.6
quadrillion Btu's by 1985, giving an average annual growth rate of 2.5%
to 3.2% from 1974 to 1985. Projected growth in total energy consumption
to 1985 compares with an average of 4.3% per annum over the period 1965-
1972. The projected demand for oil in 1985 shows a consensus range of
about 2 million barrels per day*, from 20.6 to 22.7 million barrels per
day (42.1 - 46.5 quadrillion Btu's). These projections imply an average
rate of growth over the period 1974 to 1985 of 2.1 to 3.0% per annum,
as compared to an average of 4.9% in the period 1965-1972. Thus, not
only is growth in overall energy consumption expected to fall off, but
oil demand growth is projected to drop even more sharply in most cases.
The projections reflect the higher price of energy generally and the
*
Ignoring for the moment the Sherman Clark estimate which is exceptionally
high due primarily to a low coal production forecast.
236
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Table C.ll-1
A Comparison of
Forecast Source and Date
Sun Oil (Dec. 1975)
Exxon-"U'orld Energy
Outlook" (Dec. 1975)
U.S. Pept. of Interior,
Bureau of Mines —
"United States Energy
Through the Year 2000"
(Jan. 1976)*
Mobil Oil-"U.S. Energy
Sources: The Next
Decade" (May 1975)
PTRTNC-"Electric Power
and Oil Import De-
pendency" (May 1973)
Sherman H. Clark Assoc.,
July 1975
Oil**
Domestic
Conven-
Total tional Shale Other
42.1 17.9 ? 4.1
(Alaskan)
44.8 21.6 0.5 0.6
(Proc. gain)
46.5 NA 0.9
Some
43.0 26.6 1.0 Syncrude
Shale & Alaska 5.1
Coal Liq. Proc. gain
43.8 22.5 0.8 of 1.0
15.7
49.3 (range 0.2 3.9
to 19.6) (Alaskan)
Recent Forecasts of Total U.S. 1985 Energy Demand
(Quadrillion Btu's)
Coal Nuclear
Lower 48
Imported Total Conventional
20.1 18.1 9.0 24.1 23.0
22.1 19.8 9.6Est' 19.6 17.6
NA 21.3 11.8 20.1 17.3
15.4Est' 18.4 12.3 22.5 21.5
14.4 21.0 8.2 22.7 21.2
16.1
29.5 16.1 9.2 19.4 (could be
(range from 18.0 with
25.6) deregulation)
Natural Gas
Imported
Alaskan LNG Syngas
None 1. 1
Inc. 1.0
(Syngas
0.4
counted
under
1.5 0.6 oil)
NA 1.0Est- NA
(Syngas-coal 0.5;
pet. 0.6; counted
NA 1.5 as primary fuels)***
(Syngas-
1.0 1.5 coal 0.9;
pet. 0.4)
Other
Not Specified
1.0
(Canada)
0.7
NA
NA
0.5 Ca.;
0.3 other
Alaska
Other
3.9
3.9
3.9
4.1
3.6
3.7
Total
96.1
97.7
103.6
100.3
99.3***
97.7
*0nly press release available to date.
**Includes NGl.'s and condensate unless noted.
***It is unclear in original report as to whether double counting of primary fuels used as feedstocks for syngas
manufacture has occurred. The present account assumes that feedstocks were included in primary fuel demand figures.
Note: Forecasts may not be quoted in their original units. The following assumptions were made in converting forecasts
to Btu's: 5.6 million Btu's/barrel of crude oil equivalent; 1.03 million Btu's/MCF of natural gas.
-------
quadrupling of oil prices in particular. Table C.ll-2 shows a tabulation
of the growth rates for consumption of each primary fuel which are implied
in the forecasts in Table C.ll-1. Note that nuclear energy is expected
by all the forecasts to be growing very rapidly in the next decade while
natural gas is assumed to be a stagnant or even declining energy source.
In most of the forecasts reviewed, oil was assumed to be the balancing
fuel. That is, a level of total energy demand was forecast and then
supplies of all fuels other than oil were projected (assuming that non-
oil fuels would be supply- rather than demand-constrained in the coming
decade). The difference between total projected demand and projected
supplies of non-oil fuels was assumed to be absorbed by oil, which was
not considered supply-constrained during the forecast period. This
methodology makes total oil demand extremely sensitive to the supply
projections of the other primary energy forms (notice, for example, the
effect of Sherman Clark Associates' low projection of coal supply on
their oil demand). Any slippage in assumed contributions by non-oil
fuels (such as nuclear) which is not matched by compensating declines
in total energy demand will result in increased oil consumption.
C.11.3 IMPLICATIONS FOR RESIDUAL FUEL OIL DEMAND
While none of the current public forecasts provide breakdowns of oil
consumption by product, it is possible to estimate the relative growth
rates which might be inferred for residual fuel oil. In general, slower
total oil demand growth is expected to be achieved by significantly less
growth in light products (particularly gasoline) which is partially offset
by increased demand for certain heavy products (i.e., residual fuel oil
and, to a lesser extent, distillate fuel oil).
Gasoline demand, which currently accounts for approximately 40% of total
product demand, is expected to depart markedly from historic high growth
trends over the next decade. The declining rates of growth, and perhaps
zero or negative growth in the early 1980's, will result from more
efficient cars (efficiency standards are explicitly mandated by the new
238
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Table C.ll-2
A Comparison of Growth Rates Assumed In Recent Forecasts of U.S. Energy Demand
(Average % Per Annum, 1974-85*)
Source
Sun Oil (Dec. 1975)
Exxon (Dec. 1975)
U.S. Dept. of Interior
(Jan. 1976)
Mobil Oil (May 1975)
FIRING (May 1975)
Oil
2.1
2.7
3.0
2.3
2.5
Coal
2.9
3.8
4.5
3.1
4.4
Natural Gas
0.7
(1.1)
(0.9)
0.1
0.2
Nuclear
20.2
21.0
23.5
23.8
19.3
Other
2.3
2.3
2.3
2.7
1.5
Total
2.5
2.7
3.2
2.9
2.8
Sherman H. Clark Assoc.
(July 1975) 3.6
Sohio (Dec. 1975-
oil only) 2.8
1.8
(1.2)
20.4
1.8
2.7
*1974 base data from U.S. Department of Interior, Bureau of Mines.
-------
Energy Policy and Conservation Act of 1975), from consumer sensitivity
to higher gasoline prices, and from a projected slower rate of growth in
the total car population. Because of the importance of gasoline in
relation to total petroleum product consumption, the projected decline
in future growth rates will have a significant effect on growth in oil
consumption as well as on the proportions of light and heavy products
consumed. Partially offsetting the gasoline declines will be rapid
increases in the petrochemical industry's demand for naphtha as a feed-
stock. However, in the period to 1985, increased petrochemical naphtha
demand is not expected to alter the basic demand trend for more heavy
products.
For all the reasons about natural gas problems, delays in nuclear
plant construction and licensing, and the inability of coal production
to increase sufficiently to absorb all deficits created by natural
gas shortages and nuclear delays—residual fuel oil consumption is
expected to grow more rapidly than total oil consumption during the
coming decade.
Between 1970 and 1973, residual fuel oil demand increased at an average
rate of 8.6% per annum. But there has been a two-year hiatus in the
upward growth pattern of residual fuel oil. Following the OPEC price
increases and Arab oil embargo, residual fuel oil demand actually declined
8% in 1974 over 1973 and early estimates place 1975 consumption lower than
1974 levels.
Over the next ten years it is possible that nationwide residual fuel oil
demand will grow at the rapid historic rates; individual regions where
gas curtailments are most severe and where residual fuel oil may have
previously been of minor importance, may experience dramatic surges in
demand. On average, we would expect residual fuel oil consumption to
increase at annual average rates two to three percentage points above
the averages for total oil demand. These future growth rates are
expected to begin to decline in the mid-1980's as nuclear and coal energy
sources become prepared to assume some of the electricity generation and
large industrial demand loads.
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C.12 FUTURE SUPPPLY OF RESIDUUM
C.12.1 INTRODUCTION
As discussed in C.ll no detailed forecasts of future petroleum product
supply/demand balances have been available for this study. Thus, these
conclusions are a consensus of the data we have developed in this study,
rather than a publicly available forecast.
This chapter first presents a range of estimates of future residuum
supply and next discusses its derivation. The sensitivity of residuum
supply to various factors is discussed and some conclusions as to future
residual fuel oil supply/demand balances are reached.
C.12.2 POTENTIAL FUTURE RESIDUUM SUPPLY
With the exception of residual fuel oil imports, virtually all residuum
demand in the United States must be met by supplies from domestic refining.
In a sense then, residual fuel oil production is a balancing element
which is the net result of residuum production less all other uses of
residuum. Table C.12-1 shows actual 1973 and potential 1985 refinery
supply of residuum and imports of residual fuel oil. These potential
supply situations should not be thought of as "forecasts" but rather
are being used to illustrate a range of possible future outcomes.
Refinery capacity is expected to continue to expand in the United States
to 1985, but whether it will do so at the rate shown in Table C.5-2
(about 3.7% per year) is not certain. Environmental constraints and
uncertainty over government policies may slow refinery growth substantially.
We show in Table C.12-1 a low range of refinery growth which has been set
241
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Table C.12-1
Future Supply and Use of Residuum in the United States
(MMBBL)
1973
1985 Potential Supply/Demand
Low High
Crude Run to Stills
Residuum Yield
Less:
Refinery Fuel
Asphalt & Road Oil
Lubes & Waxes
Coker Feed
Conversions
Subtotal
Residual Fuel Oil
Residual Fuel Oil
Demand
Imports
4,537
1,946
44
175
76
250
1,045
1,590
356
1,016
660
5,755
2,465
230
220
100
250
1,045
1,845
620
1,655
1,035
6,645
2,850
265
220
100
280
1,175
2,040
810
1,865
1,055
242
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to our average petroleum demand growth rate of 2% per year, while the
high case uses 3.2% per year refinery growth which is close to the rate
of refinery growth shown in Table C.5-2 for the period 1976-1980. The
values shown in Table C.12-1 are for crude runs to still so that future
refinery capacity would be a larger volume. If capacity utilization
were 90% in both cases, then the anticipated refining capacities are
17.5 and 20.2 million barrels daily for the low and high cases. This
compares to a current refining capacity of about 15 MMBCD.
We have assumed that the mix of crudes available to U.S. refiners will
continue to yield roughly the same amount of residuum. This assumption
may understate the future availability of residuum as lighter domestic
crudes decline in production and foreign crudes, which would tend to be
heavier than domestic crudes, are imported. Thus over time natural
residuum yield may increase as a percent of crude runs, but we have held
it as a constant percent in Table C.12-1. Besides possible future
residuum yield changes, the amount of sulfur in future imports of crude
oil is likely to be higher than it is today. The international availa-
bility of sweet crudes is limited compared to the availability of sour
crudes which indicates that the average sulfur content of imported crudes
will tend to increase. This will increase the need for sulfur removal
processes.
From the residuum yield we have subtracted other residuum uses to derive
the potential residual fuel oil supply. We have assumed that the needs
for asphalt, road oil, lubes and waxes will grow at 2% per year in both
cases, while we have shown static coker and conversion uses for residuum
in the low growth case and a minimal 1% per year growth in the higher
case. Refinery use of residuum as fuel is shown to expand dramatically
under the assumption that residuum will replace lost natural gas supplies
and become the main refinery fuel source.
Refinery gas, coke and other fuel sources will continue to be used for
refinery fuel, but residuum is expected to become the main fuel. This
243
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high use of residuum for fuel could be reduced if more refineries use
coal as a fuel. Such a situation is not expected to develop within the
next decade, however.
Coker and conversion uses of residuum have been shown with no or very
low growth between 1973 and 1985 to demonstrate the impact of gasoline
demand on residuum use. It should be noted that we expect absolute
gasoline demand to increase between now and 1980, but then begin to
remain level or decline so that by 1985 residuum used in gasoline
production could be expected to have grown only minimally. The no-growth
situation is probably too low an estimate of what will happen by 1985
but is not totally unlikely.
The net result of meeting all other uses for residuum leaves residual
fuel oil as the balancing element. Residual fuel oil production is
shown to expand either at 4.8% per year or at 7.1% per year between 1973
and 1985. The low rate has domestic residual fuel oil supply growing
at a slightly higher rate than demand which has been assumed to grow
at 4.1% per year from 1973 to 1985 in the low case. The high rate assumes
refinery residual fuel oil production will expand at a much higher rate
than the 5.1% per year shown for growth in residual fuel oil demand from
1973 to 1985.
Even at the higher growth rate of residual fuel oil production, imports
of residual fuel oil will still be higher than at present. A production
expansion rate of about 14% per annum between 1973 and 1985 would be
required to eliminate residual fuel oil imports by 1985. Such a growth
rate appears impossible to attain. In Table C.12-1 imports of residual
fuel oil are shown expanding at between 3.8 and 4.0% per year for the
two cases. Imports of residual fuel oil in this potential situation are
about 2.9 MMBCD which compares to current imports of about 1.8 MMBCD.
These imports, of course, are in addition to imports of crude oil or
other products. The spread between low and high case import levels
shown on Table C.12-1 appears unrealistically narrow and is due to the
244
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assumptions which have been made rather than to any particular preciseness
in forecasting imports.
In general agreement with our conclusions that there is now more of an
incentive for refiners to produce residual fuel oil relative to other
products and that such conditions may continue in the future, the 1985
figures on Table C.12-1 show residual fuel oil production being 10.8%
and 12.2% of crude runs for the low and high cases while the 1973 actual
runs showed that resid production was equal to 7.8% of crude runs. It
should be noted that in March 1976 the FEA proposed rulings that would
lessen the incentive for domestic refiners to produce residual fuel oil,
especially for the East Coast market. The final FEA rulings could
materially affect future production levels.
C.12.3 SENSITIVITY OF RESULTS TO VARIOUS FACTORS
C.12.3.1 Government Product Import Controls
The high side of the potential supply picture presented in Table C.12-1
is based on high refinery capacity growth and yet still requires large
volumes of product imports. Without strong government assistance to
the refinery industry, it is unlikely that product imports could be
wholly eliminated by 1985. Indeed with most of the refining capacity
in the Caribbean area designed for and dependent on U.S. markets, it could
be politically difficult to eliminate those refineries from the U.S.
supply situation as well as being difficult purely from supply oriented
considerations.
Holding product imports to their present level would require substantial
refinery growth above the high case rate. Such growth, again, would
require government incentives. Proposed FEA rules would seem to act in
the opposite direction, so it is not clear that the government is necessarily
trying to reduce imports by encouraging the domestic refining industry.
245
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C.12.3.2 Crude Oil Prices
Since the inception of the Entitlements Program, U.S. refiners have
enjoyed a substantial crude cost benefit as compared to foreign refiners
due to the lower average domestic crude prices. This benefit can last as
long as domestic crude production is set less than world oil prices and
should encourage refinery growth and increase domestic supplies of
residuum. Such increases in supplies, however, must use foreign crudes
since domestic crude production is not adequate to meet current demand.
Thus, any marginal increases in residual fuel oil supplies will come from
foreign crudes, whether or not the crude is refined domestically.
C.12.3.3 Residuum Product Prices
Residuum products supply a variety of markets and thus are sensitive to
price changes in different ways. Refinery fuel usage of residuum in
the long run must compete with any other available energy source. If
those energy sources, for example coal, were available at lower cost
than residuum, then they could be substituted for residuum usage in the
long run. In the shorter run, it may be physically difficult for
refineries to use fuels other than liquid or gaseous hydrocarbons. Thus
to 1985 we feel that refinery fuel usage is relatively insensitive to
end product pricing.
Asphalt and road oil have always been low value products and their usage
is relatively sensitive to price changes. But with all competing products
also facing cost increases due to increased oil prices, it is unlikely
that asphalt and road oil market shares will be seriously eroded by price
increases which are consistent with general energy cost increases.
Lubes and waxes are highly specialized, premium products whose use is
relatively insensitive to price. Their prices generally are not set by
raw material costs but rather by manufacturing and distribution costs,
and their cost is a relatively small component of the product or service
in which they are incorporated. Thus we would expect lube and wax demand
246
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to be relatively insensitive to price change.
Coker feed and residuum to conversion units basically depend on gasoline
demand and prices to determine the volume so used, although petroleum
coke does have specific market demand as an end product. Gasoline is
a premium product compared to residual fuel oil so that residuum will
selectively go to gasoline, but the conversion incurs substantial costs.
As gasoline demand stops growing and refining capacity continues to
expand, a larger fraction of gasoline demand can be met by the naturally
occurring gasoline fractions and less conversion processing will be
needed. Thus residuum will be freed for other end-product use. We
expect that gasoline will continue to be a premium product so that
residuum conversions will still be economically rational in the future.
C.12.3.4 Fuel Substitutability
Residual fuel oil must compete with other energy forms but as we have
discussed previously, we expect oil to be the "swing" fuel at least
for the next decade. This implies that oil price increases could be
higher than for other fuels and oil demand would still increase. In
addition, fuel cost is generally still a relatively small part of the
cost of a finished product so that some price insensitivity in the
manufacturing sector is evident. Thus we expect residual fuel oil
demand will be relatively insensitive to normal price increases.
C.12.3.5 Product Quality Variations
Of concern to this study is the sensitivity of residual fuel oil price
and supply to two quality parameters, sulfur and metals content.
We have not found any evidence to lead us to conclude that metal content
directly affects today's price of residual fuel oil. Generally, product
specifications list a maximum allowed metals content which is based on
boiler requirements and the metals content specification is usually a
relatively minor item in the product quality listing. These metals
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limitations have been developed over the years and the oil industry
already operates to accommodate industry requirements. Some fuel oil
uses, such as ship bunkers, can take fairly high metals content and we
believe that the oil industry is able to divert high metal content oils
to uses which are unaffected by those metals. It is doubtful whether
oil suppliers would supply a high metals fuel oil to a user at a price
discount. This would be especially true if the user needed relatively
small volumes of such oil. That is to say, the oil supplier would have
to set up a dedicated transportation and storage system to handle a
high metals product and would not do so unless the volumes involved
would justify such expenses. The oil supplier would be unlikely to
give a price discount for the. high metals product in such a situation,
although to the extent that high metal and high sulfur contents go
together, a price discount would be observed but would be attributed
to the sulfur content.
Metal content probably does affect residual fuel oil price indirectly
by making some crude sources not suitable currently for use in making
resid. Such effects cannot be detected in current fuel oil market
prices. We conclude that metal content currently has a very minor
effect on residual fuel oil prices and supplies. In the future, metal
content specifications may become more important but still will probably
not be a sensitive element in price or supply decisions.
The sulfur content of residual fuel oil is the main variable in
determining prices charged for the different grades of residual fuel oil.
In the United States the New York Harbor area is the most active residual
fuel oil market. In March 1976 2.8% sulfur residual fuel oil could be
obtained on a contract basis for $10.00 per barrel while 1.0% sulfur fuel
oil cost $11.70 per barrel, 0.5% sulfur fuel oil cost $12.45 per barrel
and 0.3% sulfur, the lowest sulfur content fuel oil regularly available
in the market, cost $13.20 per barrel. The sulfur premium per percent
of sulfur ranges from $0.94 per barrel for 1.0% sulfur fuel oil to
$1.28 per barrel for 0.3% sulfur fuel oil which reflects the increasing
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difficulty of obtaining ever-lower sulfur contents. These premia vary
over time to reflect market conditions, but from the beginning of 1973
to 1976 the premia have all risen about 30-40 cents, reflecting increases
in crude oil sulfur premia. These sulfur premia are about the same as
the additional cost to desulfurize high sulfur oil. Table C.9-5 showed
that desulfurization of an Arabian mix oil to 0.3% sulfur content cost
52 to 57 cents per million BTU's which is equal to $3.29 to $3.60 per
barrel of resid. Since the oil mixture went from 3.8% to 0.3% sulfur
content the cost was shown to be $0.94 to $1.03 per percent of sulfur
removed. For the Iranian oil the lowest cost for obtaining 0.3% sulfur
fuel oil was shown in Table C.9-6 to be $1.21 per percent sulfur removed.
Thus sulfur premia in the marketplace reflect the cost of desulfurization
but apparently provide no incentive for any process which costs more
than current processes. Current sulfur premia are generally not large
enough to encourage the construction of new desulfurization facilities.
Market conditions in Europe and the United States have lately been tend-
ing to reduce further the sulfur premia as there has been some relaxation
of sulfur restrictions. Coupled with the slight easing of sulfur
restrictions has been a general oversupply of fuel oil in the market
which has resulted in relatively weak prices.
We anticipate, as discussed in C.6.5.3, that residual fuel oil prices
will probably remain relatively steady in real terms for most of the
next decade and that oil supplies will generally not be tight. We
also anticipate these same conditions to apply to low sulfur oils so
that sulfur premia will not be excessive. In fact, sulfur premia will
probably continue to be as low as the lower cost desulfurization processes
which will have a dampening effect on the installation of desulfurization
facilities.
C.12.3.6 Technological Trends
The result of technological trends which would allow the environmentally
sound use of high sulfur residual fuel oil without prior removal of the
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sulfur content would be to reduce the need for low sulfur fuel oils and
increase the demand for high sulfur oils. If this shift in demand were
of a significant size it could have the effect in theory of lowering
the price differential between the two categories of oil until a user
would be indifferent as to installing a system to use the high sulfur
oil or as to buying the low sulfur oil directly, i.e. the sulfur premium
would become equal to the additional cost of using the high sulfur oil
directly.
Several conditions will cause problems with the above scenario. First,
as shown above, sulfur premia are already as low as the cost of desulfuri-
zation so that end users are already indifferent as to whether to use low
sulfur oil or some sulfur removal process and we do not anticipate a
major change in this situation. Next, the assumption made above that
a new process would affect the price of available oil is probably not
valid until such time as the new process affects the use of a significant
quantity of fuel oil. With current U.S. demand for residual fuel oil
at about 2.5 million barrels per day a single installation, or even
ten or twenty separate facilities, each using 10 MBCD, would be unlikely
to affect the price of oil to any significant degree. If twenty facilities
were to utilize common purchasing arrangements then some impact on price
might be effected. However, and this is the final problem with the
scenario posed above, all of this assumes an essentially elastic supply
of oil which can continue to match demand. Oil supplies can appear
infinitely elastic to an individual user, but when viewed from a national
or global perspective there are definite limitations on availabilities
of low sulfur, high sulfur, or any grade, oils. Thus in the future
the ability to shift between grades of oil may become less important
than being able to shift away from oil to coal or other energy sources.
In summary, environmentally sound uses of high sulfur fuel oils will
probably not be able to affect overall oil prices or supplies and over
the next decade may face price competition from available oil supplies.
Such uses of high sulfur fuel oil could be useful in lowering sulfur
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emissions, so cannot be considered strictly from an economics standpoint.
C.12.4 CONCLUSIONS
Demand for residual fuel oil which in 1975 was about 2.5 million barrels
per day could reach 4.5 - 5.0 MMBCD by 1985. Imports of residual fuel
oil probably will continue to supply 60-65 percent of U.S. demand although
a high rate of refinery expansion coupled with a slow growth in gasoline
demand could reduce imports requirements.
The declining U.S. domestic production of crude oil will require increased
imports of crude oil. Assuming world economic and political stability,
such import requirements will be met mainly by the OPEC petroleum
exporting countries and the effect on the United States will be primarily
felt in the balance of trade.
Rising imports by the U.S. and other consuming countries will enable
oil producing countries to continue to raise prices, although we expect
prices in real terms to remain fairly stable for most of the next decade.
By or before 1985, however, we would expect supply constraints to have
developed to the point where oil prices could be expected to jump sig-
nificantly in real terms. When that happens, additional incentive will
be added for oil users to switch to other fuels.
Residual fuel oil will continue to be used primarily in areas convenient
to water transport since that is the most economic method to transport
residual fuel oil over any distance. Other transportation modes, such
as pipelines or unit trains, will enable some users to be located away
from water transport access. This may be important in allowing current
natural gas users to shift to using residual fuel oil.
Residual fuel oil production in the United States will mainly be con-
centrated in areas with access to water transport: refineries located
away from water routes will probably continue to convert most residuum
into lighter products. The Gulf Coast region will probably expand its
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residual fuel oil production rapidly as the need to replace dwindling
natural gas supplies increases.
In 1973 domestic residual fuel oil production was 7.8% of crude runs to
stills or 18.2% of residuum yield which in turn was 42.9% of total crude
runs. Most of the residuum was used for feedstock to conversion units
(66.5%) with smaller volumes going to refinery fuel (0.2%), asphalt and
road oil (9.0%), and lubes and waxes (3.9%).
By 1985 it is anticipated that some major shifts will have taken place
in residuum yield. Refinery fuel usage will increase as natural gas
supplies are lost. It is expected that residuum used for feedstock to
conversion units will decline primarily as a result of gasoline demand
becoming static under the impact of higher prices, increased mass trans-
portation availability and increased automobile fuel usage efficiencies.
Less residuum being used for conversion units will permit more residual
fuel oil production and it is expected that domestic residual fuel oil
production could increase to 25-28% of residuum yield or 11-12% of
total crude runs.
It is not anticipated that major changes will occur in the next decade
in the supply of or demand for residual fuel oil due to technological
changes which would make the fuel oil more environmentally acceptable
for use without further processing in the manufacturing stages. In
other words, the normally anticipated demand increases for residual fuel
oil of all sulfur levels will be high enough to overshadow any additional
increase in demand which would result from being able to burn high,
rather than low, sulfur resid. This is due mainly to the long lead times
required to prove and install new technology which suggests that relatively
few improved installations will have been made in the next decade. Another
reason for this conclusion is that the cost to install such technological
systems plus the cost of high sulfur fuel oil has been shown to be
currently as high or higher than the cost of buying very low sulfur fuel
oil. This has dampened any efforts to install new desulfurization equip-
ment in refineries and would probably have an effect on any decision
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to install technological systems to control sulfur problems at the
point of use. Such incentives could reemerge if a shortage of low sulfur
crude oils were to develop. The EPA should keep this subject under
particularly close review.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/2-76-166
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Residuum and Residual Fuel Oil Supply and Demand
in the United States—1973-1985
5. REPORT DATE
June 1976
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)J.Monk Jr. , M.Menino, E.Quackenbush,
N.Godley, L.Clark, M. Cloyd, I.Jashnani, and
R. Stickles
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Inc.
Acorn Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
EHB536
11. CONTRACT/GRANT NO.
68-02-1332, Task 19
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 11/75-4/76
14. SPONSORING AGENCY CODE
EPA-ORD
is.SUPPLEMENTARY NOTES jERL-RTP task officer for this report is S.L.Rakes, Mail Drop
61, 919/549-8411, Ext 2825.
16. ABSTRACT
rep0rt gjves results of a. study of the supply and demand of petroleum
residuum in the United States, now and in 1985 , with particular emphasis on residual
fuel oil. The report details the historical residuum balance , then examines the major
factors which affect the supply and demand. Factors include governmental influences,
foreign factors , energy production trends , demand trends , technological innovations
in sulfur removal processes , and residual fuel oil handling problems. Based on
these factors, a potential 1985 residuum supply scenario is formulated and discussed.
The sensitivity of the future scenario to the influence of the various factors is also
examined.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Petroleum Industry
Residual Oils
Supply (Economics)
Demand (Economics)
Energy
Desulfurization
Air Pollution Control
Stationary Sources
Petroleum Residuum
13B
05C
21D
07A,07D
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Till* Report)
Unclassified
21. NO. OF PAGES
255
20. SECURITY CLASS (This page)
Unclassified
22.
EPA Form 2220-1 (9-73)
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