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-11-
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TABLE OF CONTENTS
PAGE
PREFACE i
LIST OF TABLES xi
LIST OF FIGURES xxix
EXECUTIVE SUMMARY
ES.l Background ES-1
ES.2 Description of Offshore Oil and Gas Industry ES-1
ES.3 Overview of Regulatory Approaches ES-2
ES.3.1 Drilling Fluids and Drill Cuttings ES-2
ES.3.2 Produced Water ES-3
ES.3.3 Combinations of Selected Regulatory Options ES-4
ES.4 Economic Methodology Overview ES-4
ES.5 Model Projects ES-7
ES.6 Industry Activity Projections ES-7
ES.7 Pollution Control Compliance Costs ES-7
ES.8 Regulatory Impacts on Model Projects ES-10
ES.9 Regulatory Impacts on Oil and Gas Industry ES-12
ES.10 Regulatory Impacts on Production ES-13
ES.ll Secondary Impacts of the Regulations ES-13
ES.12 Impact on Small Businesses ES-13
SECTION ONE INTRODUCTION AND SUMMARY OF
REGULATORY OPTIONS 1-1
1.1 Introduction 1-1
1.2 Summary of Regulatory Options 1-2
1.2.1 Drilling Fluids and Drill Cuttings 1-2
1.2.2 Produced Water 1-5
1.2.3 Combinations of Selected Regulatory Options 1-6
SECTION TWO CHARACTERIZATION OF OFFSHORE OIL
AND GAS ACTIVITY 2-1
2.1 Offshore Leasing 2-1
2.1.1 Federal Leasing 2-2
2.1.2 State Leasing Activity 2-10
2.2 Offshore Oil and Gas Exploration 2-11
2.3 Offshore Oil and Gas Development 2-16
2.3.1 Development Logistics 2-16
2.3.2 Inventory of Offshore Production Platforms 2-17
-iii-
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2.3.3 Offshore Oil and Gas Production 2-23
2.4 Support Activities 2-23
2.5 Industry Downturn and Recovery 1986-1988 2-29
2.5.1 Federal Offshore Leasing 2-29
2.5.2 Exploration 2-34
2.5.3 Production 2-38
SECTION THREE FINANCIAL PROFILE 3-1
3.1 Corporate Participants in Offshore Development 3-1
3.1.1 Categorization of Participants 3-1
3.1.2 Industrial Concentration in Offshore Activities 3-6
3.2 Market and Financial Trends 3-8
3.2.1 Market Environment 1975-1986 3-8
3.2.2 Trends in Capital and Exploration Expenditures 3-11
3.2.3 Trends in Offshore Production Reserves 3-11
3.2.4 Financial Trends 3-15
3.2.5 Increases in Industry Debt 3-17
3.3 Financial Condition of Industry Segments 3-19
3.3.1 Ratios Used to Analyze Industry Segments 3-21
3.3.2 Ratio Analysis of Major Integrated Companies 3-22
3.3.3 Ratio Analysis of Independent Companies 3-37
3.4 Financial Profiles of Typical" Companies 3-42
3.4.1 Financial Profile of Typical" Majors 3-43
3.4.2 Financial Profile of Typical" Independents 3-43
3.4.3 Financial Comparisons Among Typical" Oil Companies 3-50
3.5 Financial Condition in 1986 and Future Outlook 3-57
3.5.1 1986 Financial Performance 3-57
3.5.2 Future Strategy for the Majors 3-57
3.5.3 Future of the Independents 3-58
SECTION FOUR WELL AND PLATFORM PROJECTIONS 4-1
4.1 Projected OCS Oil and Gas Production, 1986-2000 4-2
4.1.1 MMS Projections 4-2
4.1.2 Pre-1986 Production 4-7
4.1.3 Future OCS Production from 1986 and Later Sources 4-8
4.2 Forecast of Offshore Oil and Gas Wells, 1986-2000 4-8
4.2.1 Productive Wells 4-18
4.2.2 Unproductive Drilling Efforts 4-22
4.2.3 Total Well Projections 4-26
4.3 Platform Projections, 1986-2000 - Unrestricted Development 4-26
4.3.1 Total Platforms 4-26
4.3.2 Platforms in 4-Mile Category 4-34
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TABLE OF CONTENTS (cont.)
PAGE
4.4 Platform Projections, 1986-2000 - Restricted Development 4-35
4.4.1 Total Platforms 4-35
4.4.2 Implications for Platform Projections 4-45
4.5 Summary 4-48
4.6 References 4-61
SECTION FIVE ECONOMIC METHODOLOGY 5-1
5.1 Description of the Economic Model 5-1
5.1.1 Economic Model Overview 5-1
5.1.2 Parameter Description 5-2
5.1.3 Model Calculation Procedures 5-4
5.1.4 Interpretation of Model Results 5-6
5.2 Construction of Regional Offshore Oil and Gas Projects 5-7
5.2.1 Overview 5-7
5.2.2 Description of the Offshore Oil and Gas Projects 5-8
5.2.3 Results of Base Case Simulations - NSPS 5-30
5.2.4 Results of Base Case Simulations - BAT Projects 5-35
5.3 References 5-39
SECTION SIX COSTS OF COMPLIANCE 6-1
6.1 Drilling Fluids and Drill Cuttings 6-1
6.1.1 Assumptions 6-1
6.1.2 Current Permit Requirements 6-5
6.1.3 Cost of Regulatory Options 6-11
6.2 Produced Water - BAT 6-22
6.3 Produced Water - NSPS 6-33
6.4 Combined Cost of Selected Regulatory Options 6-41
6.5 References 6-52
SECTION SEVEN IMPACTS ON REPRESENTATIVE FACILITIES 7-1
7.1 Drilling Fluids and Drill Cuttings 7-1
7.1.1 Financial Summary Statistics 7-1
7.1.2 Sensitivity Analysis 7-9
7.2 Produced Water - BAT 7-9
7.3 Produced Water - NSPS 7-20
7.3.1 Financial Summary Statistics 7-20
7.3.2 Sensitivity Analysis 7-28
7.4 Combined Effects of Selected Regulatory Options 7-28
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TABLE OF CONTENTS (cont.)
PAGE
SECTION EIGHT IMPACTS ON REPRESENTATIVE COMPANIES 8-1
8.1 Drilling Fluids and Drill Cuttings 8-1
8.1.1 Impacts on the General Offshore Oil and Gas Industry 8-3
8.1.2 Impacts on "Typical" Oil Companies 8-3
8.2 Produced Water - BAT 8-13
8.2.1 Impacts on the General Offshore Industry 8-13
8.2.2 Impacts on Typical" Oil Companies 8-13
8.3 Produced Water - NSPS 8-15
8.3.1 Impacts on the General Offshore Industry 8-15
8.3.2 Impacts on Typical" Oil Companies 8-18
8.4 Combined Effects of Selected Regulatory Options 8-18
8.4.1 Impacts on the General Offshore Oil and Gas Industry 8-18
8.4.2 Impacts on Typical" Oil Companies 8-23
SECTION NINE IMPACTS ON PRODUCTION 9-1
9.1 Methodology 9-1
9.2 Drilling Ruids and Drill Cuttings 9-2
9.3 Produced Water - BAT 9-2
9.4 Produced Water - NSPS 9-2
9.5 Combined Effects of Selected Regulatory Options 9-6
9.6 References 9-8
SECTION TEN SECONDARY IMPACTS OF BAT AND NSPS REGULATIONS 10-1
10.1 Impacts on Federal Revenues 10-2
10.2 Impacts on State Revenues 10-5
10.3 Impact on Balance of Trade 10-13
10.4 Impacts on Service Industries 10-14
10.5 Impacts on Inflation 10-14
10.6 References 10-15
SECTION ELEVEN SINGLE WELL STRUCTURES IN THE GULF OF MEXICO 11-1
11.1 BAT Structures 11-3
11.2 NSPS Structures 11-8
11.3 Combined Effects 11-8
11.4 References 11-10
SECTION TWELVE SMALL BUSINESS ANALYSIS 12-1
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TABLE OF CONTENTS (cont.)
PAGE
APPENDIX A
A.1
A.2
A.3
SELECTION OF OFFSHORE OIL AND GAS PROJECTS
General Parameter Categories
A. 1.1 Geographic Region
A. 1.2 Number of Well Slots
A.1.3 Type of Production
Description of Model Projects
A.2.1 Gulf of Mexico Model Projects
A.2.2 Atlantic Model Projects
A.2.3 Pacific Model Projects
A.2.4 Alaskan Model Projects
References
A-l
A-l
A-2
A-2
A-6
A-9
A-9
A-14
A-14
A-18
A-20
APPENDIX B
B.I
B.2
B.3
BASE CASE TIMING OF PROJECT DEVELOPMENT
Phases of Project Development
Duration of Project Development Phases
B.2.1 Gulf of Mexico
B.2.2 Pacific
B.2.3 Atlantic
B.2.4 Alaska
References
B-l
B-l
B-l
B-2
B-6
B-ll
B-ll
B-14
APPENDIX C
C.1
C.2
C.3
C.4
C.5
LEASE PRICES
Average Lease Cost Per Tract
Discovery Efficiency
Number of Platforms Per Discovery Well
Ratio of Expected Production
References
C-l
C-l
C-3
C-8
C-8
C-9
APPENDIX D
D.I
D.2
D.3
D.4
D.5
EXPLORATION COST ASSUMPTIONS
Geophysical and Geological Costs
Discovery Efficiency
Drilling Costs
Number of Platforms Per Discovery Well
References
D-l
D-l
D-l
D-3
D-3
D-7
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TABLE OF CONTENTS (cont.)
PAGE
APPENDIX E
El
E.2
E.3
DELINEATION PHASE ASSUMPTIONS
Cost Per Delineation Well
Number of Delineation Wells Per Project
References
E-l
E-l
E-l
E-3
APPENDIX F
F.I
F.2
F.3
F.4
F.5
F.6
DEVELOPMENT PHASE ASSUMPTIONS
Platform/Gravel Island Cost
Lease Equipment Costs
Development Well Costs
Number of Production Wells Per Platform
Rate of Installation of Development Wells
References
F-l
F-l
F-2
F-4
F-9
F-9
F-9
APPENDIX G
G.I
G.2
G.3
G.4
G.5
PRODUCTION/OPERATION PHASE ASSUMPTIONS
Peak Production Rates
G.I.I Gulf of Mexico
G.1.2 Pacific
G.1.3 Alaska
G.1.4 Atlantic
Production Decline Rate
Years at Peak Production
Operation and Maintenance Costs (O&M)
References
G-l
G-l
G-l
G-4
G-4
G-9
G-9
G-12
G-12
G-19
APPENDIX H
H.1
H.2
H.3
PRODUCED WATER ASSUMPTIONS
Modeling Assumptions
H.1.1 Projects with Oil Production
H.1.2 Projects with Gas-Only Production
Peak Water Production
H.2.1 Projects with Oil Production
H.2.2 Projects with Gas-Only Production
Average Water Production
H.3.1 Projects with Oil Production
H.3.2 Projects with Gas-Only Production
H-l
H-l
H-l
H-2
H-6
H-6
H-9
H-9
H-9
H-ll
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TABLE OF CONTENTS (cont.)
PAGE
H.4 Total Annual Water Production
H.4.1 Existing Structures (BAT)
H.4.2 Projected Structures (NSPS)
H.5 References
H-ll
H-13
H-20
H-20
APPENDIX I
I.I
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
1.10
1.11
1.12
1.13
1.14
1.15
BASE CASE FINANCIAL ASSUMPTIONS AND RATES 1-1
Incremental Impact of Model Project on Corporate Income Tax Rate 1-1
Severance Taxes 1-1
Royalty Rates 1-3
Rental Payments 1-4
Depreciation 1-4
Basis for Depreciation 1-5
Capitalized Costs 1-5
Inflation Rate 1-5
Escalation of General Project Costs in Real Terms 1-6
Oil Depletion Allowance 1-6
Salvage 1-7
Investment Tax Credit 1-7
Windfall Profits Tax 1-7
Discount Rate 1-8
References Ml
APPENDIX J
J.I
J.2
ERG ECONOMIC MODEL FOR OFFSHORE
PETROLEUM PRODUCTION
Introduction
J.I.I Model Phases
J.I.2 Economic Overview of the Model
Step-By-Step Description of the Model
J.2.1 Phase One - Leasing
J.2.2 Phase Two - Exploration
J.2.3 Phase Three - Delineation
J.2.4 Phase Four - Development
J.2.5 Phase Five - Production
J.2.6 Summary Statistics
J-l
J-l
J-l
J-2
J-3
J-6
J-6
J-9
J-ll
J-12
J-17
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-X-
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LIST OF TABLES
Page
ES-1 Summary of Regulatory Packages ES-5
ES-2 Distribution of Oil, Oil/Gas, and Gas Production ES-8
Platforms by Region and Size
ES-3 Combined Cost of Selected Regulatory Packages ES-9
ES-4 Summary of Impacts of Combined Regulatory Options ES-11
on Typical Projects
1-1 Summary of Regulatory Packages 1-7
2-1 Outer Continental Shelf (OCS) Federal Lease Sale Statistics 2-3
2-2 OCS Leasing Statistics, 1980-1986 2-6
2-3 Total Royalty Revenues by Commodity and Year From All 2-8
Offshore Federal Leases, 1953-1986
2-4 Total OCS Federal Offshore Leasing Summary, 1975-1986 For 2-9
All Regions
2-5 Summary of State Offshore Lease Terms 2-12
2-6 Historical and Planned State Offshore Leasing Activities 2-13
2-7 Total Offshore Exploratory Drilling in the United States 2-14
Federal and State Leasees Alltime to January 1, 1985
2-8 Federal Waters Inventory as of March, 1988 2-18
2-9 State Waters Inventory of Offshore Platforms and Producing Wells 2-20
2-10 Pacific Offshore Platforms : 2-21
2-11 Production and Value of U.S. Crude Oil and Condensate 2-24
Onshore-Offshore
2-12 Production and Value of U.S. Natural Gas - Onshore-Offshore 2-25
2-13 Support Activities 2-26
2-14 Offshore Drilling Activity, 1973-1985 2-28
2-15 Crude Oil Prices, 1980 to November 1987 2-30
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LIST OF TABLES (cont.)
2-16 OCS Leasing Statistics, 1980-1987 2-31
2-17 Five-Year OCS Leasing Plan 2-33
2-18 Annual Average Number of Active Offshore Drilling Rigs 2-35
2-19 Gulf of Mexico Leases Due to Expire, 1988-1989 2-37
3-1 U.S. Oil Companies Engaged in Offshore Exploration 3-3
Development and Production
3-2 Sample of Companies Providing Support Services to Offshore 3-4
Developers in 1986
3-3 Oil Industry Concentration Ratios: Offshore Activities 3-7
and U.S. Activities
3-4 Total U.S. Petroleum Demand, U.S. Average Crude Oil Wellhead 3-9
Price, 1975-1986
3-5 Total U.S. Natural Gas Demand, U.S. Average Natural Gas 3-10
Wellhead Price, 1975-1986
3-6 Trends in Capital and Exploration Expenditures (United 3-12
States, 1974-1984)
3-7 Offshore Wells Drilled and Drilling Costs 1975-1985 3-13
3-8 Dollar Value of Annual Oil and Gas Production 1975-1986 3-14
3-9 Financial Trends for 25 Major Petroleum Companies (1973-1985) 3-16
3-10 Financial Statistics for 26 Large U.S. Oil Companies 3-18
(1980-1986)
3-11 Debt/Capital Ratios (%) For Major Integrated and Independent 3-20
Companies
3-12 Return on Equity (%) Major Integrated Oil Companies: 3-23
19 Company Group (1977-1985)
3-13 Return on Equity (%) For Three Samples of Major Integrated 3-25
Oil Companies (1977-1986)
-xii-
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LIST OF TABLES (cont.)
3-14 Return on Assets (%) Major Integrated Oil Companies: 3-26
19 Company ERG Group (1977-1985)
3-15 Return on Assets (%) Comparison of Average Yield for 4 Samples 3-29
of Major Companies (1977-1986)
3-16 Current Ratio Major Integrated Oil Companies: 19-Company 3-30
ERG Group (1977-1985)
3-17 Current Ratio Comparison of Average Yields for 4 Samples 3-31
of Major Integrated Oil Companies
3-18 Debt/Capital Ratio (%) Major Integrated Oil Companies in 3-32
19-Company ERG Group (197-1985)
3-19 Estimated Versus Reported Net Asset Value of Six Major 3-36
U.S. Integrated Oil Companies, 1986
3-20 Return on Equity (%) Independent Oil Companies in ERG . 3-38
17-Company Sample
3-21 Return on Assets (%) Independent Oil Companies in ERG 3-39
17-Company Sample
3-22 Current Ratio Independent Oil Companies in ERG 3-40
17-Company Sample
3-23 Debt/Capital Ratio (%) Independent Oil Companies in ERG 3-41
17-Company Sample
3-24 Balance Sheet for a Typical" Major Integrated Oil Company 3-44
3-25 Income Statement for a Typical" Major Integrated Oil Company 3-45
3-26 Financial Ratio and Performance Indicators for a Typical" 3-46
Major Integrated Oil Company
3-27 Balance Sheet for a Typical" Independent Oil Company 3-47
3-28 Income Statement for a "Typical" Independent Oil Company 3-48
3-29 Financial Ratio and Performance Indicators for a Typical" 3-49
Independent Oil Company
-xiii-
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LIST OF TABLES (cont.)
3-30 Profitability Comparisons Between Typical" Offshore Oil 3-51
Companies
3-31 Liquidity Comparisons Between "Typical" Offshore Oil Companies 3-53
3-32 Leverage Comparisons Between 'Typical" Offshore Oil Companies 3-54
3-33 Growth and Spending Comparisons Between Typical" Offshore 3-56
Oil Companies
4-la MMS Federal OCS Model Outputs - Total 1990, 1993, 1995, and 4-4
2000 Production ($32/bbl of Oil - 1986 Dollars)
4-lb MMS Federal OCS Model Outputs - Total 1990, 1993, 1995, and 4-5
2000 Production ($21/bbl of Oil - 1986 Dollars)
4-lc MMS Federal OCS Model Outputs - Total 1990, 1993, 1995, and 4-6
2000 Production ($15/bbl of Oil - 1986 Dollars)
4-2a OCS Production from Pre-1986 Sources ($32/bbl of Oil - 4-9
1986 Dollars)
4-2b OCS Production from Pre-1986 Sources ($21/bbl of Oil - 4-10
1986 Dollars)
4-2c OCS Production from Pre-1986 Sources ($15/bbl of Oil - 4-11
1986 Dollars)
4-3a OCS Production from 1986 and Later Sources ($32/bbl of Oil - 4-12
1986 Dollars)
4-3b OCS Production from 1986 and Later Sources ($21/bbl of Oil - 4-13
1986 Dollars)
4-3c OCS Production from 1986 and Later Sources ($15/bbl of Oil - 4-14
1986 Dollars)
4-4a 1986 and Later NSPS Production ($32/bbl of Oil - 1986 Dollars) 4-15
4-4b 1986 and Later NSPS Production ($21/bbl of Oil - 1986 Dollars) 4-16
4-4c 1986 and Later NSPS Production ($15/bbl of Oil - 1986 Dollars) 4-17
4-5a Federal OCS Well Projections by Region - 1986-2000 4-19
($32/bbl of Oil - 1986 Dollars)
-xiv-
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LIST OF TABLES (cont.)
Page
4-5b Federal OCS Well Projections by Region - 1986-2000 4-20
($21/bbl of Oil - 1986 Dollars)
4-5c Federal OCS Well Projections by Region - 1986-2000 4-21
($15/bbl of Oil - 1986 Dollars)
4-6a Well Projections in State Waters by Region, 1986-2000 4-23
($32/bbl of Oil - 1986 Dollars)
4-6b Well Projections in State Waters by Region, 1986-2000 4-24
($21/bbl of Oil - 1986 Dollars)
4-6c Well Projections in State Waters by Region, 1986-2000 4-25
($15/bbl of Oil - 1986 Dollars)
4-7a Federal and State Post-NSPS Offshore Wells, 1986-2000 4-27
($32/bbl of Oil - 1986 Dollars)
4-7b Federal and State Post-NSPS Offshore Wells, 1986-2000 4-28
($21/bbl of Oil - 1986 Dollars)
4-7c Federal and State Post-NSPS Offshore Wells, 1986-2000 4-29
($15/bbl of Oil - 1986 Dollars)
4-8 Total Offshore Producing Wells and Dry Holes - Average 4-30
Number of Wells Per Year
4-9 Platform Configuration Summary - Unrestricted Activity 4-31
4-10 Platform Projections - Total Unrestricted Activity 4-32
($32/bbl of Oil - 1986 Dollars)
4-11 Platform Projections - Total Unrestricted Activity 4-33
($21/bbl of Oil - 1986 Dollars)
4-12 Platform Projections - Within 4 Miles Unrestricted Activity 4-36
($32/bbl of Oil -1986 Dollars) (All Projects)
4-13 Platform Projections - Within 4 Miles Unrestricted Activity 4-38
($21/bbl of Oil - 1986 Dollars) (All Projects)
4-14 Platform Projections - Within 4 Miles Unrestricted Activity 4-40
($32/bbl of Oil - 1986 Dollars) (Oil Producing Projects)
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LIST OF TABLES (cont)
'Jage
4-15 Platform Projections - Within 4 Miles Unrestricted Activity 4-42
($21/bbl of Oil - 1986 Dollars) (Oil Producing Projects)
4-16 Pacific Platforms Considered in Restricted Development 4-46
Analysis Federal Waters
4-17 Actual Drilling Rates for the Pacific - 1986-1989 4-47
4-18 Platform Configuration Summary - Restricted Activity 4-49
4-19 Platform Projections - Total Restricted Activity 4-50
($21/bbl of Oil - 1986 Dollars) (All Projects)
4-20 Platform Projections - Total Restricted Activity 4-51
($15/bbl of Oil -1986 Dollars) (All Projects)
4-21 Platform Projections - Within 4-Miles Restricted Activity 4-52
($15/bbl of Oil - 1986 Dollars) (All Projects)
4-22 Platform Projections - Within 4-Miles Restricted Activity 4-54
($15/bbl of Oil - 1986 Dollars) (Oil Producing Projects)
4-23 NSPS Structure Allocations Unrestricted Activity 4-56
4-24 NSPS Structure Allocations Restricted Activity 4-57
4-25 NSPS Structure Allocations Unrestricted Activity 4-58
(High Development Scenario)
4-26 NSPS Structure Allocations Unrestricted Activity 4-59
(Low Development Scenario)
4-27 Average Annual Number of Wells 4-60
5-1 Distribution of Oil, Oil/Gas, and Gas Producing Platforms 5-9
by Region and Size
5-2 Baseline Parameters for Gulf of Mexico Projects in State Waters 5-10
5-3 Baseline Parameters for Gulf of Mexico Projects in State Waters 5-11
(cont.)
5-4 Baseline Parameters for Gulf of Mexico Projects in Federal 5-12
Waters
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LIST OF TABLES (cont.)
age
5-5 Baseline Parameters for Pacific Projects 5-13
5-6 Baseline Parameters for Atlantic Projects 5-14
5-7 Baseline Parameters for Alaska Projects 5-15
5-8 Baseline Parameters for Model Projects 5-16
5-9 Total Exploratory Offshore Wells Drilled to January 1, 1985 5,17
5-10 Average Well Depths and Costs - 1986 Data 5-18
5-11 Lease Equipment Costs - Gulf, Pacific and Atlantic 5-20
5-12 Lease Equipment Costs for Alaska Projects 5-21
5-13 Development Well Cost - 1986 Data 5-22
5-14 Peak Offshore Per-Well Production Rates 5-23
5-15 Production Decline Rates 5-24
5-16 Operating Costs for Gulf of Mexico Platforms 5-26
5-17 Operating Costs for Pacific, Atlantic and Cook Inlet Platforms 5-27
5-18 Operation and Maintenance Costs for Alaska Projects 5-28
5-19 Crude Oil Prices, 1980 to November 1987 5-29
5-20 Wellhead Prices and Regional Relationships - 1985 Data 5-31
5-21 Relationship of Domestic Oil and Gas Prices - 1982-1987 5-32
5-22 Baseline Financial Summary Statistics, 5-33
NSPS Projects With Oil Production
5-23 Baseline Financial Summary Statistics, 5-34
NSPS Projects with Gas-Only Production
5-24 Baseline Financial Summary Statistics, 5-37
BAT Projects with Oil Production
5-25 Baseline Financial Summary Statistics, 5-38
BAT Projects with Gas-Only Production
xvii-
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LIST OF TABLES (cont.)
6-1 Regional Volumes of Drilling Fluids and Drill Cuttings 6-3
6-2 Toricity and Static Sheet Failure Rates for Water-Based 6-6
Drilling Fluids
6-3 Offshore Oil and Gas Monitoring Costs for Drilling Fluids 6-7
and Drill Cuttings
6-4 Summary of Current Requirements for Drilling Fluids 6-8
6-5 Summary of Incremental Monitoring Costs from Current 6-10
Drilling Fluids Baseline
6-6 Annual Regulatory Cost of Alternative Pollution Control 6-12
Options, Drilling Fluids and Drill Cuttings -
Gulf of Mexico, Unrestricted Activity
6-7 Annual Regulatory Cost of Alternative Pollution Control 6-13
Options, Drilling Fluids and Drill Cuttings -
Pacific, Unrestricted Activity
6-8 Annual Regulatory Cost of Alternative Pollution Control 6-14
Options, Drilling Fluids and Drill Cuttings -
Alaska, Unrestricted Activity
6-9 Annual Regulatory Cost of Alternative Pollution Control 6-15
Options, Drilling Fluids and Drill Cuttings -
Atlantic, Unrestricted Activity
6-10 Summary Table of Regulatory Costs of Alternative Pollution 6-17
Control Options, NSPS Drilling Fluids and Drill Cuttings,
Annual Regulatory Cost, Unrestricted Activity
6-11 Annual Regulatory Cost of Alternative Pollution Control 6-18
Options, Drilling Fluids and Drill Cuttings -
Gulf of Mexico, Restricted Activity
6-12 Annual Regulatory Cost of Alternative Pollution Control 6-19
Options, Drilling Fluids and Drill Cuttings -
Pacific, Restricted Activity
6-13 Annual Regulatory Cost of Alternative Pollution Control 6-20
Options, Drilling Fluids and Drill Cuttings -
Alaska, Restricted Activity
-xviii-
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LIST OF TABLES (cont.)
Page
6-14 Annual Regulatory Cost of Alternative Pollution Control 6-21
Options, Drilling Fluids and Drill Cuttings -
Atlantic, Restricted Activity
6-15 Summary Table of Regulatory Costs of Alternative Pollution 6-23
Control Options, NSPS Drilling Huids and Drill Cuttings,
Annual Regulatory Cost, Restricted Activity
6-16 Annual Cost of Pollution Control Options, NSPS Drill Fluids 6-24
and Drill Cuttings
6-17 Existing Structures by Region 6-26
6-18 BAT Produced Water, Total Capital and O&M Costs by Region 6-27
6-19 BAT Pollution Control Options for Produced Water, Oil and 6-28
Gas Platforms, Gulf of Mexico
6-20 BAT Pollution Control Options for Produced Water, Oil and 6-29
Gas Platforms, Pacific
6-21 BAT Pollution Control Options for Produced Water and 6-30
Gas Platforms, Gulf of Mexico and Pacific Regions
6-22 BAT Pollution Control Options for Produced Water, 6-31
Oil Only Platforms, Gulf of Mexico
6-23 Annual Cost of Pollution Control Options, BAT Produced 6-32
Waters
6-24 NSPS Pollution Control Options for Produced Water, Oil and ' 6-34
Gas Platforms, Gulf of Mexico
6-25 NSPS Pollution Control Options for Produced Water, Oil and 6-35
Gas Platforms, Atlantic and Pacific
6-26 NSPS Pollution Control Options for Produced Water, Oil and Gas 6-36
Platforms and Oil-Only Platforms, Alaska
6-27 NSPS Pollution Control Options for Produced Water, Gas-Only 6-37
Platforms
6-28 NSPS Produced Water, Total Capital and O&M Costs by Region 6-38
xix-
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LIST OF TABLES (cont.)
6-29 Annualized Costs of NSPS Produced Water Control Options, 6-39
Granular Filter Technology Costs, Unrestricted Activity
6-30 Annualized Costs of NSPS Produced Water Control Options 6-40
Membrane Filter Technology Costs, Unrestricted Activity
6-31 Annualized Costs of NSPS Produced Water Control Options, 6-42
Granular Filter Technology Costs, Restricted Activity
6-32 Annualized Costs of NSPS Produced Water Control Options, 6-43
Membrane Filter Technology Costs, Restricted Activity
6-33 Annualized Cost of Pollution Control in the Year 2000, 6-44
NSPS Produced Water, Granular Filtration Technology Costs
6-34 Annualized Cost of Pollution Control in the Year 2000, 6-45
NSPS Produced Water, Membrane Filtration Technology Costs
6-35 Combined Cost of Selected Regulatory Packages 6-47
6-36 Combined Cost of Selected Regulatory Packages - 6-48
Gulf Region
6-37 Combined Cost of Selected Regulatory Packages - 6-49
Alaska Region
6-38 Combined Cost of Selected Regulatory Packages - 6-50
Pacific Region
6-39 Combined Cost of Selected Regulatory Packages - 6-51
Atlantic Region
7-1 Pollution Control Options for Drilling Fluids and Drill 7-2
Cuttings, Model Project Impacts, Oil and Gas Platforms,
Gulf of Mexico
7-2 Pollution Control Options for Drilling Fluids and Drill 7-3
Cuttings, Model Project Impacts, Oil and Gas Platforms and
Oil-Only Platforms, Gulf of Mexico
7-3 Pollution Control Options for Drilling Fluids and Drill 7-4
Cuttings, Model Project Impacts, Oil and Gas Platforms,
Atlantic and Pacific
-xx-
-------
LIST OF TABLES (cont.)
7-4 Pollution Control Options for Drilling Fluids and Drill 7-5
Cuttings, Model Project Impacts, Oil and Gas Platforms and
Oil-Only Platforms, Alaska
7-5 Pollution Control Options for Drilling Fluids and Drill 7-6
Cuttings, Model Project Impacts, Gas-Only Platforms,
Gulf of Mexico
7-6 Pollution Control Options for Drilling Fluids and Drill 7-7
Cuttings, Model Project Impacts, Gas-Only Platforms,
Atlantic, Pacific, and Alaska
7-7 Pollution Control Options for Drilling Fluids and Drill 7-10
Cuttings, Model Project Impacts, Sensitivity Analysis
Gulf of Mexico, Gulf Ib Project, Oil and Gas Production
7-8 Pollution Control Options for Drilling Fluids and Drill 7-11
Cuttings, Model Project Impacts, Sensitivity Analysis
Gulf of Mexico, Gulf 12 Project, Oil and Gas Production
7-9 BAT Pollution Control Options and Produced Water, Model 7-13
Project Impacts, Oil and Gas Platforms, Gulf of Mexico
7-10 BAT Pollution Control Options and Produced Water, Model 7-14
Project Impacts, Oil and Gas Platforms, Gulf of Mexico
(cont.)
7-11 BAT Pollution Control Options and Produced Water, Model 7-15
Project Impacts, Oil and Gas Platforms, Pacific
7-12 BAT Pollution Control Options and Produced Water, Model 7-16
Project Impacts, Gas Platforms, Gulf of Mexico
7-13 BAT Pollution Control Options and Produced Water, Model 7-17
Project Impacts, Gas Platforms, Gulf of Mexico and
Pacific Regions
7-14 BAT Pollution Control Options and Produced Water, Model 7-18
Project Impacts, Oil Only Platforms, Gulf of Mexico
7-15 BAT Pollution Control Options and Produced Water, Model 7-19
Project Impacts, Oil Only Platforms, Gulf of Mexico
(cont.)
-xxi-
-------
LIST OF TABLES (cont)
Page
7-16 NSPS Pollution Control Options for Produced Water, 7-21
Model Project Impacts, Oil and Gas Platforms, Gulf of Mexico
7-17 NSPS Pollution Control Options for Produced Water, 7-22
Model Project Impacts, Oil and Gas Platforms, Gulf of Mexico
(cont.)
7-18 NSPS Pollution Control Options for Produced Water 7-23
Model Project Impacts, Oil and Gas Platforms, Atlantic
and Pacific
7-19 NSPS Pollution Control Options for Produced Water, 7-24
Model Project Impacts, Oil and Gas Platforms, and Oil-
Only Platforms, Alaska
7-20 NSPS Pollution Control Options for Produced Water 7-25
Model Project Impacts, Gas-Only Platforms, Gulf of Mexico
7-21 NSPS Pollution Control Options for Produced Water 7-26
Model Project Impacts, Gas-Only Platforms, Pacific,
Atlantic, and Alaska Regions
7-22 NSPS Pollution Control Options for Produced Water 7-29
Model Project Impacts, Sensitivity Analysis, Granular
Filter Costs, Gulf of Mexico, Gulf Ib Project, Oil and
Gas Production
7-23 NSPS Pollution Control Options for Produced Water, 7-30
Model Project Impacts, Sensitivity Analysis, Granular
Filter Costs, Gulf of Mexico, Gulf 12 Project, Oil and
Gas Production
7-24 NSPS Pollution Control Options for Drilling Fluids 7-31
Drill Cuttings, and Produced Water, Impacts of Selected
Combinations of Regulatory Options, Gulf of Mexico,
Gulf Ib and Gulf 12 Project, Oil and Gas Projects
8-1 Oil and Gas Exploration and Development Expenditures 8-2
8-2 Exploration and Development Expenditures by Major Oil 8-4
Companies in 1986
8-3 Annual Cost of Pollution Control Options, Drilling Fluids 8-6
and Drill Cuttings
-xxii-
-------
LIST OF TABLES (cont.)
8-4 Effluent Guidelines Impacts on Typical Major Oil Company 8-7
Compliance Costs Financed by Working Capital, Drilling
Fluids and Drill Cuttings
8-5 Effluent Guidelines Impacts on Typical Major Oil Company 8-8
Compliance Costs Financed by Long-Term Debt, Drilling
Fluids and Drill Cuttings
8-6 Changes in Financial Ratios for a Typical Major as a Result 8-9
of Effluent Guidelines Regulations, Drilling Fluids and
Drill Cuttings
8-7 Effluent Guidelines Impacts on Typical Independent Oil Company 8-10
Compliance Costs Financed by Working Capital, Drilling
Fluids and Drill Cuttings
8-8 Effluent Guidelines Impacts on Typical Independent Oil Company 8-11
Compliance Costs Financed by Long-Term Debt, Drilling
Fluids and Drill Cuttings
8-9 Changes in Financial Ratios for a Typical Independent as a 8-12
Result of Effluent Guidelines Regulations, Drilling Fluids
and Drill Cuttings
8-10 Annual Cost of Pollution Control Options, BAT Produced Water 8-14
8-11 Changes in Financial Ratios for a Typical Major as a 8-16
Result of Effluent Guidelines Regulations, BAT Produced
Water
8-12 Changes in Financial Ratios for a Typical Independent as a 8-17
Result of Effluent Guidelines Regulations, BAT Produced
Water
8-13 Annual Cost of Pollution Control Options, NSPS Produced 8-19
Water
8-14 Changes in Financial Ratios for a Typical Major as a 8-20
Result of Effluent Guidelines Regulations, NSPS Produced
Water
8-15 Changes in Financial Ratios for a Typical Independent as a 8-21
Result of Effluent Guidelines Regulations, NSPS Produced
Water
-xxiii-
-------
LIST OF TABLES (cont.)
Page
8-16 Combined Cost of Selected Regulatory Packages 8-22
8-17 Changes in Financial Ratios for a Typical Major as a 8-24
Result of Effluent Guidelines Regulations, Selected
Combinations of Regulatory Options
8-18 Changes in Financial Ratios for a Typical Independent as a 8-25
Result of Effluent Guidelines Regulations, Selected
Combinations of Regulatory Options
9-1 Estimated 1988 Production from BAT Structures 9-3
9-2 Potential Loss of Production, BAT Produced Water 9-4
9-3 Potential Loss of Production, NSPS Produced Water 9-5
9-4 Potential Loss of Production, Impacts of Combined 9-7
Regulatory Packages, Restricted Activity
9-5 Potential Loss of Production, Impacts of Combined 9-9
Regulatory Packages, Unrestricted Activity
10-1 Ratio of Federal-to-State Production, Projected Productive 10-3
Development Wells in Offshore Region
10-2 Potential Loss of Federal Revenues, Impacts of Combined 10-4
Regulatory Packages
10-3 Recent OCS Lease Sales 10-6
10-4 Potential Impact of Compliance Costs on State Revenues 10-7
10-5 Potential Impact of Compliance Costs on Texas State Revenues 10-9
10-6 Total Texas State Revenues and Bonus Revenues 10-10
10-7 Potential Impact of Compliance Costs on Louisiana State 10-11
Revenues
10-8 Total Louisiana State Revenues and Bonus Revenues 10-12
11-1 Existing Structures by Region 11-4
11-2 Estimated 1988 Production from BAT Structures 11-5
-xxiv-
-------
LIST OF TABLES (cont.)
Page
11-3 Comparison of Production from BAT Gulf IB Structures to 11-6
Regional and U.S. Production
11-4 NSPS Structure Allocations, Restricted Activity 11-9
A-l Number of Structures by the Number of Wellslots Available, A-5
Gulf of Mexico
A-2 Number of Wellslots on Pacific OCS Platforms A-7
A-3 Distribution of Oil, Oil/Gas, and Gas Producing Platforms A-8
by Region and Size
A-4 Sample 12-Well Structures Used in Selecting 12-Well Model A-ll
Project
A-5 Sample Structures Used in Selecting 24-Well Model Project A-12
A-6 Sample Structures Used in Selecting 40-Well Model Project A-13
A-7 Project Descriptions, Gulf of Mexico A-15
A-8 Project Description, Atlantic Region A-16
A-9 Project Descriptions, Pacific Region A-17
A-10 Platforms in Cook Inlet A-19
A-ll Project Descriptions, Alaska A-21
B-l Project Timing, Gulf of Mexico B-4
B-2 Project Timing for Recent Pacific Coast Platforms B-7
B-3 Project Timing, Pacific Region B-9
B-4 Project Timing, Atlantic Region B-12
B-5 Project Timing, Alaska B-15
C-l Gulf of Mexico Lease Prices C-2
C-2 Pacific Lease Prices C-4
C-3 Atlantic Lease Prices C-5
-XXV-
-------
LIST OF TABLES (cont)
C-4 Alaska Lease Prices C-6
C-5 Total Exploratory Offshore Wells Drilled to January 1, 1985 C-7
C-6 Lease Prices for Model Projects C-10
D-l Total Exploratory Offshore Wells Drilled to January 1, 1985 D-2
D-2 1986 Well Cost Data - By Well Type D-4
D-3 Average Well Depths and Costs - 1986 Data D-5
D-4 Exploratory Well Costs for Atlantic Region D-6
E-l Number of Delineation Wells for Typical Offshore Projects E-2
F-l Lease Equipment Costs - Gulf, Pacific, and Atlantic F-3
F-2 Lease Equipment Costs for Alaska Projects F-5
F-3 Average Well Depths and Costs - 1986 Data F-6
F-4 Total Development Offshore Wells Drilled to January 1, 1985 F-7
F-5 Development Well Cost - 1986 Data F-8
G-l Cumulative Production Per Well - Gulf of Mexico Assumptions G-3
G-2 Peak Production Rates - California G-5
G-3 1986 Gas to Oil Ratios - California G-6
G-4 Average First-Year Production for Oil Wells in Cook Inlet G-7
Alaska
G-5 Initial Production from Endicott Field, Beaufort Sea, Alaska G-8
G-6 Engineering Estimate of Peak Production Rates - Alaska G-10
G-7 Peak Offshore Per-Well Production Rates G-ll
G-8 Production Decline Rates G-13
G-9 1986 Operation and Maintenance Costs for Gulf of Mexico G-15
Platforms
-xxvi-
-------
LIST OF TABLES (cont.)
Page
G-10 Annual Operating Costs - 12-Slot Platform in Gulf of Mexico G-16
G-ll Labor Assumptions for Small Gulf Projects G-18
G-12 Operating Costs for Gulf of Mexico Platforms G-20
G-13 Operating Costs for Pacific, Atlantic, and Cook Inlet Platforms G-21
G-14 Ratio of 1986 Operation and Maintenance Costs - California G-22
and Gulf Coast
G-15 Operation and Maintenance Costs for Alaska Projects G-23
H-l Initial Watercut - Alaska H-4
H-2 Offshore WaterGas Ratios - California H-5
H-3 Water Production Estimates - Gulf of Mexico H-8
H-4 Revised Peak Water Production Rates - Existing and Projected H-10
Structures
H-5 Revised Average Annual Water Production Rates - Existing and H-l2
Projected Structures
H-6 Description of MMS Data Base Structure Counts H-14
H-7 Existing Structures by Region H-15
H-8 Estimated Average Annual Produced Water Generated by Projects H-16
in the Gulf of Mexico
H-9 Estimated Average Annual Produced Water Generated by H-l9
Pacific Projects
H-10 NSPS Structure Allocations, Restricted Activity H-21
H-ll Estimated Average Annual NSPS Water Production, $21/bbl H-22
Restricted Development Scenario
1-1 Twenty-Year Averages for Risk-Free, Corporate Borrowing, 1-9
and Inflation Rates
1-2 Debt/Capital Ratio, Major Integrated Oil Companies in MO
19 Company ERG Group
-xxvii-
-------
LIST OF TABLES (cont)
1-3 Cost of Capital Calculations 1-12
J-l Effect of Tax and Accounting Systems on Cash Flows J-4
J-2 Exogenous Variables Provided to ERG Economic Model J-5
J-3 Cost and Cash Flow Uses in the Model J-18
-xxviii-
-------
LIST OF FIGURES
Page
ES-1 Economic Methodology Overview ES-6
2-1 Offshore Mobile Rig Utilization Data, Gulf of Mexico, 2-36
1983-1988
5-1 General Schematic Diagram of ERG Economic Model 5-3
A-l OCS Planning Areas: Lower 48 States A-3
A-2 OCS Planning Area: Alaska A-4
B-l Gulf of Mexico: Time from Lease Sale to First Spud Date B-3
B-2 Gulf of Mexico: Time from Lease Sale to Initial Production B-5
B-3 Pacific Region: Time from Lease Sale to First Spud Date B-8
B-4 Pacific Region: Time from Lease Sale to Initial Production B-10
B-5 Alaska Region: Time from Lease Sale to First Spud Date B-13
G-l North Cook Inlet Field, Alaska: Gas Production G-14
H-l WatenOil Relationship H-3
H-2 Water and Gas Production from North Cook Inlet Field, Alaska H-7
-xxix-
-------
EXECUTIVE SUMMARY
ES.l BACKGROUND
The EPA proposed effluent limitations guidelines and standards for the
offshore segment of the oil and gas industry on August 26, 1985. The proposed
regulations covered produced water, drilling fluids, drill cuttings, produced
sand, deck drainage, and well treatment fluids, as well as sanitary and
domestic wastes discharges. A Notice of Data Availability and Request for
Comments relating to the discharge of drilling fluids and drill cuttings was
published on October 21, 1988.
In light of new information and data collected since 1985, the Agency has
decided to repropose effluent limitations guidelines for the offshore oil and
gas industry. This report evaluates the cost and economic impacts of BAT and
NSPS regulatory options for drilling fluids, drill cuttings, and produced
water.
ES.2 DESCRIPTION OF OFFSHORE OIL AND GAS INDUSTRY
The offshore oil and gas industry searches for and produces oil and gas in
areas off the nation's coasts. Most existing production is offshore Texas,
Louisiana, California, and Alaska. Several other offshore areas, including
the waters off Alabama and Florida and Georges Bank in the Atlantic, have been
explored to a lesser extent.
The industry leases areas to be developed from states (for areas within 3
miles from shore)1 or the Federal government. Exploration wells are drilled
to determine the presence of hydrocarbons on a leased tract. Development
wells and production platforms are installed where hydrocarbons are found.
Offshore oil and gas production accounted for 14.4 percent of United States
oil production and 27.3 percent of natural gas production in 1986.
'State waters in Texas and Florida include areas within 3 leagues or
about 10.4 statute miles of shore.
ES-1
-------
ES3 OVERVIEW OF REGULATORY APPROACHES
ES3.1 Drilling Fluids and Drill Cuttings
Five options for BAT and NSPS were developed for the control of drilling
fluids and drill cuttings. The following requirements are included in some
combination in the various options:
No discharge of drilling fluids or drill cuttings.
No discharge of diesel oil in detectable amounts or no discharge of
drilling fluids and drill cuttings associated with oil-based drilling
fluids.
No discharge of "free oil" as measured by the static sheen test.
Toxicity limitation as measured by a 96-hour LCjo test.
Limitations on cadmium and mercury.
Zero discharge drilling fluids and drill cuttings based on water depth
or distance from shore. The zero discharge requirement is presumed to
be met by barging the fluids and cuttings to shore for disposal. The
August 26, 1985 proposal based part of those requirements on water
depth, not distance from shore.
These requirements have been combined into five regulatory options, which are
the focus of the economic impact analysis:
Zero Discharge - all drilling fluids and drill cuttings are barged to
shore for treatment and disposal.
4-Mile Barge; 1,1 Other - fluids and cuttings from wells drilled within
4 miles of shore are barged to shore for disposal. Fluids and cuttings
from wells beyond 4 miles of shore must meet a 1,1 mg/kg limit on
mercury and cadmium content in the discharged fluid, pass the toxicity
test, substitute mineral oil for diesel oil, and pass the static sheen
test.
4-Mile Barge; 5,3 Other - fluids and cuttings from wells drilled within
4 miles of shore are barged to shore for disposal. Fluids and cuttings
from wells beyond 4 miles of shore must meet a 5,3 mg/kg limit on
cadmium and mercury content (respectively) in the stock barite, pass
the toxicity test, substitute mineral oil for diesel oil, and pass the
static sheen test.
1,1 All - all fluids and cuttings must meet a 1,1 mg/kg limit on
mercury and cadmium content in the discharged fluids, pass the toxicity
test, substitute mineral oil for diesel oil, and pass the static sheen
test.
5,3 All - all fluids and cuttings must meet a 5,3 mg/kg limit on
cadmium and mercury content (respectively) in the stock barite, pass
ES-2
-------
the toxicity test, substitute mineral oil for diesel oil, and pass the
static sheen test.
The above options, though slightly different in name, are the same as those
discussed in the preamble to this regulation. Other options, based on water
depth, were also considered. These other options are discussed in other
technical support documents, such as the Development Document, and preliminary
analyses are contained in the record for the rulemaking.
ES3.2 Produced Water
Two technologies are evaluated for the treatment and discharge and to
achieve a zero discharge of produced water:
Filtration and discharge.
Injection.
These options are also combined with a 4-mile boundary to create three
regulatory options for consideration in this report:
Zero Discharge - all produced water is injected.
All Filter - all produced water is filtered and discharged at the
offshore facility.
4-Mile Filter; BPT Other - produced water from facilities within 4
miles of shore is filtered and discharged at the offshore facility
while other facilities must meet BPT requirements.
Other options considered based on better BPT treatment, reinjection with a
specified distance and filtration beyond that distance, and various
shallow/deep consideration were evaluated previously. Material concerning
these other options can be found in the record for this rulemaking.
Each requirement is described more fully in Section One. Two sets of cost
assumptions were investigated for the produced water treatment and zero
discharge options as a focus for this report. The first set, based on the use
of membrane filter technology, reflects recent developments in this
technology, its use in the oil and gas industry, and the reduction in platform
space required for the equipment. The new equipment is assumed to fit in the
available space without requiring platform additions. The second set of
costs, based on granular filter technology, assumes that platform additions
are necessary to accommodate the required pollution control equipment, and
ES-3
-------
assumes a factor to cover costs of transportation of the equipment to the
offshore location and other related expenses. Two of the regulatory packages
analyzed in this report assume membrane filter costs while four assume
granular filter costs. More detail on the cost basis for both granular and
membrane filtration technology is available in the proposed rulemaking
Development Document.
ES33 Combinations of Selected Regulatory Options
The Agency selected six "packages" of regulatory options for detailed
economic impact analysis. Each package has an option for:
Drilling fluids and drill cuttings (combined BAT and NSPS).
BAT produced water.
NSPS produced water.
Table ES-1 summarizes the packages.
ES.4 ECONOMIC METHODOLOGY OVERVIEW
The economic impact analysis methodology is summarized in Figure ES-1.
There are eight major parts in the economic analysis:
Definition of model projects.
Development of industry activity projections.
Impact of BAT and NSPS costs on model projects.
Total effluent guidelines costs for the offshore oil and gas industry.
Impact of effluent guidelines on the offshore oil and gas industry.
Potential impact of BAT and NSPS costs on production.
Secondary impacts of effluent guidelines costs.
Small business impacts of effluent guidelines costs.
Figure ES-1 summarizes the major inputs and outputs for each part of the
analysis.
ES-4
-------
TABLE ES-1
SUMMARY OF REGULATORY PACKAGES
Regulatory
Package
Effluent
Effluent
Control
Option
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1.1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter
All Filter
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
BPT All
BPT All
F** Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other - Membrane
4-Mile Filter; BPT Other - Membrane
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
** Selected Package.
Notes: All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Source: Industrial Technology Division, U.S. Environmental Protection Agency.
ES-5
-------
FIGURE ES-1
Economic Methodology Overview
BACKGROUND SECTIONS
IMPACTS SECTIONS
PJ
in
Profile ol Industry
Aotlvltle*
(Section Two)
Effluent Guideline*
Option*
(Section One)
Financial Profit*
ol the Induetry
(Section Three)
Lading data
Exploration data
D eye I op m e n I d | a
Typical
Platform
Effluent*
Regulatory
Option*
Co*t ol Capital
Definition of
Model Projecta
(Section Five)
Regulatory Impacts on
Modal Facilities
(Saotlon Seven)
Pollution Control
Coat* Par Well
or Per Protect
(Section Six)
Financial Profit* of lyploal obmpanlca
Development ol
Platform Promotions
(Section Four)
Will P»l««ll»»
r.i ia**-too*
Total Regulatory Coats
for the Industry
(Section Six)
Regulatory Impaots
on the Industry
(Seotlon Eight)
MMS projection!
State projection*
Hl*lorlc*l Statlatlc*
Secondary Impacts
of Regulations
(Seotlon Ten)
Regulatory Impacts
on Produotlon
(Seotlon Nine)
Impact* on Single
Well Structures In
Quit of Mexico
(Seotlon Eleven)
Small Bualness
Impaots ol
Regulations
(Seotlon Twelve)
-------
ES.5 MODEL PROJECTS
To analyze the cost and impact of effluent guidelines regulations, 34
model projects are defined. These projects account for a diversity of
platform size (i.e., number of(wellslots), geographic location, and production
type encountered in offshore areas. Table ES-2 summarizes the characteristics
of the model projects. The geological and economic features of the model
projects are defined based on the literature and on industry contacts and are
described in detail in Section Five. It is assumed that the wells drilled in
these offshore projects use a water-based drilling fluid for the 0 to 10,000-
ft depth range and an oil-based fluid in the 10,000 to 14,000-ft depth range.
ES.6 INDUSTRY ACTIVITY PROJECTIONS
Four alternative projections of industry drilling and production activity
are formulated for the period 1986-2000 to assess the cost of the regulations.
The projections vary according to the level of development as well as the
price of oil. Under the most reasonable projections ($21/bbl with restricted
development2), an average of 759 wells are drilled per year. These
projections are based on projected production estimates for 1986-2000
developed by the Minerals Management Service and past activity levels in
Federal and State waters. A total of 766 projects or facilities are projected
for the entire 1986-2000 period. For comparison, the $21/bbl - unrestricted
development scenario projects an average of 978 wells per year and a total of
851 facilities during the 1986-2000 time period.
ES.7 POLLUTION CONTROL COMPLIANCE COSTS
The regulatory costs were developed by the Industrial Technology Division,
U.S. Environmental Protection Agency, Washington, D.C. and are described in
the development document for the proposed rule. Table ES-3 presents the
annualized cost for each of the six regulatory packages. In the year 2000,
total annualized costs range from $30 to $1,081 million (restricted
preamble to the proposed rule discusses "constrained" and
"unconstrained" development. These terms correspond to the "restricted" and
"unrestricted" development scenarios, respectively, discussed in this
document.
ES-7
-------
TABLE ES-2
DISTRIBUTION OF OIL, OIL/GAS, AND GAS PRODUCING PLATFORMS
BY REGION AND SIZE
PRODUCTION TYPE
REGION AND
WELLSLOT SIZE
Gulf la1
Gulf lb§
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Atlantic 24
Pacific 16
Pacific 40
OIL
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
OIL/GAS
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
GAS
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
COMMENTS
No gas -only platforms among large Gulf
platforms .
No gas -only platforms among large Gulf
platforms .
No gas -only platforms among large Gulf
Atlantic 24
Pacific 16
Pacific 40
Pacific 70
Cook Inlet 12/24
Beaufort Sea 48
- Gravel island
- Platform
Norton Basin 34
Navarin 48
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
Yes
Yes
No
No
Yes"
No
No
No
No
No gas -only platforms among large Gulf
platforms .
No gas -only platforms among large Gulf
platforms.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
Source: ERG model project configurations based on typical projects reported in the
Department of the Interior Mineral Management Service platform
inspection system, complex/structure database, and the literature.
The Gulf la shares production equipment with three other single-well stuctures
while the Gulf Ib has its own production equipment.
bThe gas-only case is modeled as 12 wells.
ES-8
-------
TABLE ES-3
COMBINED COST OF SELECTED REGULATORY PACKAGES
SKILL IONS, 1986 DOLLARS
$21/bbl
Regul story
Package Effluent
A Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
B Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
C Drilling Fluid and Drill Cuttings
Produced Water BAT
Produced Water - NSPS
Combined Cost
D Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
E Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water NSPS
Combined Cost
F** Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water NSPS
Combined Cost
Effluent
Control
Opt i on
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
4-Mile Barge; 1,1 Other*
All Filter
All Filter
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1,1 Other*
BPT All
BPT All
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other -
4-Mile Filter; BPT Other -
Annual! zed Cost
Restricted
$30
$41
$16
$88
$30
$845
$206
$1,081
$30
$480
$95
$605
$30
$151
$62
$242
$30
$0
$0
$30
$30
Membrane $13
Membrane S11
$54
in the Year 2000
Unrestricted
$50
$41
$27
$118
$50
$845
$275
$1,170
$50
$480
$128
$657
$50
$151
$81
$282
$50
$0
SO
$50
$50
$13
$17
$80
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
** Selected Package.
Notes: All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Entries may not sum due to independent rounding.
Source: ERG estimates.
ES-9
-------
development) or from $50 to $1,170 million (unrestricted development). All
costs are given in terms of 1986 dollars.
ES.8 REGULATORY IMPACTS ON MODEL PROJECTS
Thirty-four model projects were considered in the analysis, spanning a
wide range in size, productivity, and profitability. Table ES-4 summarizes
the economic impacts seen for a typical project for the selected sets of
effluent control options. These impacts are based on the most reasonable
average oil price projected for the 15-year period, i.e., $21/bbl in 1986
dollars. The Gulf 12 oil and gas project is used in the example.
Under the membrane filter cost assumptions, the corporate cost and
production cost per BOE increases by 1 to 4 percent for existing projects and
from 1 to 2 percent for new projects. The net present value of the project
decreases by 5 to 7 percent for existing projects and from 3 to 4 percent for
new projects. For new projects, the internal rate of return declines from 2
to 3 percent under the various regulatory packages. The typical project,
however, will recover the cost of the incremental pollution control.
Under the granular filter cost assumptions, the corporate cost per barrel -
of-oil equivalent (BOE) and production cost per BOE increase from 15 to 26
percent for existing projects and from 1 to 3 percent for new projects. The
net present value of the project decreases from 20 to 24 percent for existing
projects and from 5 to 6 percent for new projects. The internal rate of
return for new projects decreases by 4 to 5 percent under the various
regulatory packages.
For projects larger than the Gulf 12-well platform, impacts are generally
less than those seen in Table ES-4, because the costs are spread over a larger
amount of production or form a smaller portion of the total investment and
operating costs. The inverse is true for projects smaller than the Gulf 12-
well platform. Costs must be spread over a smaller amount of production and
form a larger portion of total investment and operating costs; hence, impacts
are larger.
ES-10
-------
TABLE ES-4
SUMMARY OF IMPACTS OF COMBINED REGULATORY OPTIONS ON TYPICAL PROJECTS
Change in Typical Project Financial Summary Statistics*
Effluent
Guideline Effluent
BAT Produced Water
NSPS Drilling Fluid and Drill Cuttings
Produced Water
« Drilling Fluid and Drill Cuttings
i Produced Water
*~* Drilling Fluid and Drill Cuttings
Produced Water
Drilling Fluid and Drill Cuttings
Produced Water
Drilling Fluid and Drill Cuttings
Produced Water
Effluent
Control
Option
Zero Discharge
Filtration
4-Mile Barge; 1,1 Other
Zero Discharge
4-Mile Barge; 1.1 Other
Zero Discharge
4-Mile Barge; 1.1 Other
Filtration
4-Mile Barge; 1,1 Other
Filtration
4-Mile Barge; 1,1 Other
BPT
Cost
Assumption
Granular Filter Costs
Membrane Filter Costs
Granular Filter Costs
Membrane Filter Costs
Granular Filter Costs
Membrane Filter Costs
Granular Filter Costs
Membrane Filter Costs
NA
Corporate Production
Cost per Cost per
BOE BOE
19. OX
3.6X
15. 2X
1.6X
2.0X
1.2X
1.4X
0.8X
0.2X
26. 2X
4.2X
20. 7X
1.3X
3.4X
2.2X
2.5X
1.8X
0.6X
Internal
Rate of
Return
NA
NA
NA
NA
-4.5X
-3. OX
-3.5X
-2. OX
-1.0X
Net
Present
Value
-24. 2X
-7.0X
-19. 9X
-4.7X
-6. IX
-4. OX
-4.5X
-3.1X
-0.9X
Notes: * Based on a Gulf 12 oil and gas project.
BOE = barrels of oil equivalent.
NA = not applicable.
Source: ERG estimates.
-------
ES.9 REGULATORY IMPACTS ON OIL AND GAS INDUSTRY
Offshore development is financed by a small number of very large major and
independent oil companies. Data on publicly held companies are used to define
balance sheets for representative major and independent oil companies. These
balance sheets are then used to judge the impact of pollution control
requirements of these proposed effluent guidelines and standards. Two methods
for financing the regulatory costs are considered -- working capital and long-
term debt. The incremental costs of additional pollution control are
negligible when compared to the financial base of these companies.
Impacts are minimal for a typical major under any set of pollution control
options and either set of development assumptions. The financial ratios
affected by debt financing change by less than 1 percent under any combination
of options and costs. The current ratio declines by no more than 0.4 percent.
Financing all BAT and NSPS costs by working capital would decrease that
parameter by no more than 4 percent.
The change in financial ratios for a typical independent under the various
combinations of regulatory options and price assumptions is greater than that
seen for a typical major. Under the most reasonable projected development
scenarios, $21/bbl oil price with restricted development, the financial ratios
affected by debt-financing increase by no more than 1.6 percent under the
options investigated. Under regulatory package B (Zero Discharge for produced
water), working capital may decrease by 39 percent and the current ratio may
decline by 3 percent. Under regulatory package F (4-Mile Filter; BPT Other),
working capital declines by 2 to 4 percent. All other ratios change by no
more than 0.2 percent for this regulatory package. For the other packages, :
current ratio declines by 1.7 percent or less, and working capital decreases
by 1 to 22 percent. It must be questioned, however, whether a typical
independent would chose to fund all of these expenditures out of working
capital or whether some mix of working capital and debt would be used.
ES-12
-------
ES.10 REGULATORY IMPACTS ON PRODUCTION
The total amount of production3 from BAT and NSPS structures was
calculated. This estimate was compared to the total production under the six
sets of regulatory options. Under regulatory package F, the potential loss in
production is less than 0.1 percent of total offshore production. Under
regulatory package B, production declines by 1.8 percent. The production
declines for the other packages range from 0 to 0.7 percent.
ES.ll SECONDARY IMPACTS OF THE REGULATIONS
The impact of the effluent guidelines regulations on Federal revenues,
State revenues, and the balance of payments is analyzed. Federal revenues are
impacted by the tax effects of effluent guidelines expenditures and by
potential reductions in lease/bonus bids. The potential impact of the
regulations on Federal revenues is estimated to be between $28 and $1,017
million (1986 dollars) in the year 2000, depending upon the regulatory
package. For regulatory package F, the potential loss in Federal revenues is
estimated to be $50 million in the year 2000. State revenues might be
affected by reductions in lease/bonus bids. The maximum impact of the
guidelines on State revenues is $2 to $64 million in the year 2000. For
either Texas' and Louisiana's estimated share of the impact, lost revenues are
less than 0.5 percent of the State's total 1986 revenues. No significant
impacts on the balance of trade or inflation are projected.
ES.12 IMPACT ON SMALL BUSINESSES
The effluent guidelines expenditures will be financed by major and
independent oil companies. These are not small businesses by any standard;
therefore, no Regulatory Flexibility Analysis was undertaken.
'Production is expressed in terms of BOE (barrels-of-oil equivalent) in
order to compare both oil and gas production on a common basis. The
conversion factor is based on the heating value of the product. A barrel of
oil is 5.8 million BTU and an MMCF of gas is 1,021 million BTU. An MMCF of
gas is equivalent to 176.03 BOE.
ES-13
-------
SECTION ONE
INTRODUCTION AND SUMMARY OF REGULATORY OPTIONS
1.1 INTRODUCTION
This report evaluates the economic impact of proposed effluent
limitations guidelines and standards of performance on the offshore oil and
gas industry. This industry searches for and produces hydrocarbons located in
offshore areas. The industry is included as a subcategory of the oil and gas
extraction point-source category under the Clean Water Act (the Act). Two
activities of the offshore oil and gas industry generate effluents. First,
drilling for oil and gas involves the use and discharge of drilling fluids and
drill cuttings. Drilling fluids are liquids used to lubricate the drill bit
and carry away cut rock to the surface in a well drilling operation. Drill
cuttings are fragments of the host rock removed by the drilling operation.
Second, the production of oil and gas results in the generation and discharge
of waters associated with the hydrocarbons (i.e., produced waters) in the
subsea reservoirs.
The Environmental Protection Agency (the Agency) is required under
Sections 301, 304, 306, and 307 of the Act to establish effluent limitations
guidelines and standards of performance for industrial dischargers. To
further these requirements, the following effluent guidelines and standards
are being proposed:
BCT - Effluent reductions employing the best conventional
pollutant control technology as required under Section 304(b)(4).
BAT - Effluent reductions employing the best available control
technology economically achievable as required under Section
304(b)(2).
NSPS - New source performance standards covering new sources as
required under Section 306(b) of the Act.
On August 26, 1985, the Agency proposed BAT and NSPS for drilling
fluids, drill cuttings, and produced water waste streams. In the same notice,
BCT was proposed to be equal to BPT effluent limitations guidelines. The
Agency, however, reserved BCT effluent limitations guidelines for additional
1-1
-------
conventional pollutant parameters for these waste streams for future
rulemakings. On October 21, 1988, the Agency published a Notice of Data
Availability and Request for Comments relating to the discharge of drilling
fluids and drill cuttings.
Since 1985, the Agency has gathered additional data and other
information concerning the treatment and disposal of drilling fluids, drill
cuttings, and produced water. In light of this additional information, the
Agency has decided to repropose effluent limitations guidelines for the
offshore oil and gas industry. This report evaluates the costs and economic
impacts of the BAT and NSPS regulatory options for drilling fluids, drill
cuttings, and produced waters examined for the reproposal. BCT options are
discussed in the Development Document.
1.2 SUMMARY OF REGULATORY OPTIONS
1.2.1 Drilling Fluids and Drill Cuttings
Five options for BAT and NSPS were developed for the control of drilling
fluids and drill cuttings. The following requirements are included in some
combination in the various options:
No discharge of drilling fluids or drill cuttings.
No discharge of diesel oil in detectable amounts or no discharge
of drilling fluids and drill cuttings associated with oil-based
drilling fluids.
No discharge of "free oil" as measured by the static sheen test.
Toxicity limitation as measured by a 96-hour LC50 test.
Limitations on cadmium and mercury.
Zero discharge of fluids and cuttings based on distance from
shore. The zero discharge requirement is presumed to be met by
barging the fluids and cuttings to shore for disposal.
Each requirement is discussed more fully below.
No Discharge of Oil-Based Drilling Fluids: This requirement, which is
included in all options under consideration, is a continuation of the
effective prohibition on the discharge of oil-based fluids that results from
the BPT requirement of "no discharge of free oil." The discharge of cuttings
1-2
-------
associated with oil-based fluids is also prohibited. Cuttings associated with
diesel oil-based fluids are assumed to fail a visual sheen test, a BPT
requirement. Cuttings associated with mineral oil-based fluids are assumed to
pass a visual sheen test. Under all the BAT/NSPS regulatory approaches,
however, all cuttings associated with either diesel oil- or mineral oil-based
fluids must be barged. The barging of cuttings associated with mineral oil-
based fluids is therefore a BAT/NSPS cost.
No Discharge of Diesel Oil in Detectable Amounts: Diesel oil is a
complex mixture of petroleum hydrocarbons. It is known to be highly toxic to
marine organisms and to contain priority and toxic nonconventional pollutants.
Diesel oil is an "indicator" pollutant for control of the discharge of
priority pollutants. Diesel oil has been used in water-based drilling fluids
as a lubricity agent and as a "spotting" agent to free stuck pipes. This
requirement prohibits the discharge of drilling fluids and drill cuttings to
which diesel oil has been added for lubricity or spotting purposes. Such
wastes must be transported to shore for proper disposal or reuse. An
alternative method to comply with this requirement is the substitution of less
toxic mineral oil for diesel oil. This requirement is included in all
regulatory options.
No Discharge of "Free Oil" (static sheen test for fluids and cuttings'):
BPT regulations prohibit the discharge of "free oil" based on a visual sheen
test. That is, no sheen, slick, or iridescence may be visible as the drilling
fluid is discharged into the receiving water body. A static sheen test is a
more sensitive indicator of "free oil" than the visual sheen test. The static
sheen test involves mixing the waste to be discharged with seawater in a
container, allowing the mixture to stand for a period of time, and then
observing whether the waste caused a sheen, iridescence, gloss, or increased
reflectance on the surface of the test seawater. The occurrence of any such
observed effect would prohibit the discharge of that waste into the receiving
seawater. This requirement applies to all options.
Toxicity Limitation: All options limit the toxicity of the discharge of
drilling fluids as measured using a 96-hour LC^ toxicity test. The toxicity
limitation is established at a 30,000 ppm suspended particulate phase (SPP).
The purpose of the requirement is to reduce the levels of toxic constituents
in drilling fluid discharges, including those contributed by spotting and
lubricity agents and other specialty additives.
1-3
-------
Limitation on Mercury and Cadmium Content: All options limit the amount
of mercury and cadmium in drilling fluids. For some options, the
concentration of mercury or cadmium in the discharged drilling fluids must not
exceed 1 mg/kg each (dry-weight basis). These options are termed "1,1 All" or
"1,1 Other" throughout this report. This requirement is presumed to be met by
the use of barite in which mercury and cadmium concentrations do not exceed 1
mg/kg each. For the other options, the not-to-exceed limit is 3 mg/kg mercury
and 5 mg/kg cadmium dry-weight basis in the stock barite. These options are
referred to as "5,3 All" and "5,3 Other" throughout the report.
Zero Discharge Based on Distance from Shore: Under the "Zero Discharge"
option, all fluids and cuttings must be barged to shore for treatment and
disposal. Under these circumstances, limitations on mercury, cadmium,
toxicity, and diesel oil are rendered moot since the fluids and cuttings will
not be discharged. Under "4-Mile Barge" options, all fluids and cuttings from
wells drilled within 4 miles of shore must be barged to shore for treatment
and disposal. Fluids and cuttings from wells beyond 4 miles of shore must
adhere to limitations on mercury and cadmium content, toxicity, and diesel
oil.
These requirements have been combined into five options:
Zero Discharge - all fluids and cuttings are barged to shore for
treatment and disposal.
4-Mile Barge; 1,1 Other - fluids and cuttings from wells drilled
within 4 miles of shore are barged to shore for disposal. Fluids
and cuttings from wells beyond 4 miles of shore must meet a 1,1
mg/kg limit on mercury and cadmium content, pass the toxicity
test, substitute mineral oil for diesel oil, and pass the static
sheen test.
4-Mile Barge; 5,3 Other - fluids and cuttings from wells drilled
within 4 miles of shore are barged to shore for disposal. Fluids
and cuttings from wells beyond 4 miles of shore must meet a 5,3
mg/kg limit on cadmium and mercury content (respectively), pass
the toxicity test, substitute mineral oil for diesel oil, and pass
the static sheen test.
1,1 All - all fluids and cuttings must meet a 1,1 mg/kg limit on
mercury and cadmium content, pass the toxicity test, substitute
mineral oil for diesel oil, and pass the static sheen test.
5,3 All - all fluids and cuttings must meet a 5,3 mg/kg limit on
cadmium and mercury content (respectively), pass the toxicity
test, substitute mineral oil for diesel oil, and pass the static
sheen test.
1-4
-------
Due to the dangers and high costs involved in barging drilling wastes in
arctic conditions, Alaska has been exempted from barging requirements under
the 4-Mile Barge options. Wells drilled in this region, however, must comply
with either the 1,1 All or 5,3 All requirements under the 4-Mile Barge; 1,1
Other and the 4-Mile Barge; 5,3 Other options, respectively.
1.2.2 Produced Water
Two methods are considered for the treatment and discharge or zero
discharge of produced water:
Filtration and discharge.
Injection.
Two sets of costing assumptions are investigated, one reflecting the use of
membrane filters and the other reflecting granular filter costs. The reader
is referred to the development document for more details.
These options are combined with the 4-mile boundary described in Section
1.2.1 to create the three options for consideration for BAT (existing) and
NSPS (future) production facilities:
Zero Discharge - all produced water is injected.
All Filter - all produced water is filtered and discharged at the
.offshore facility.
4-Mile Filter; BPT Other - produced water from facilities within 4
miles of shore is filtered and discharged at the offshore facility
while other facilities must meet BPT requirements.
BPT (Best practicable Control Technology Currently Available) requirements
currently limit the discharge of oil and grease in produced water to a daily
maximum of 72 mg/L and a 30-day average of 48 mg/L.
1-5
-------
1.23 Combinations of Selected Regulatory Options
The Agency selected six "packages" of regulatory options for further
analysis. Each package has an option for:
Drilling fluids and drill cuttings.
BAT produced water.
NSPS produced water.
The packages are summarized in Table 1-1.
1-6
-------
TABLE 1-1
SUMMARY OF REGULATORY PACKAGES
Regulatory
Package
Effluent
Effluent
Control
Option
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter
All Filter
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
BPT All
BPT All
F** Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other - Membrane
4-Mile Filter; BPT Other - Membrane
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
** Selected Package.
Notes: All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Source: Industrial Technology Division, U.S. Environmental Protection Agency.
1-7
-------
SECTION TWO
CHARACTERIZATION OF OFFSHORE
OIL AND GAS ACTIVITY
The offshore oil and gas industry leases, explores, and develops areas
located off the coasts outside the inner boundary of the territorial seas of
the United States. The industry leases (i.e., acquires the right to operate
on) offshore areas from Federal or state governments. Once an area is leased,
exploration wells are drilled to determine whether hydrocarbons are present.
If oil or gas is found in sufficient quantities, development wells and a
production platform are put in place. From these facilities oil and gas are
produced and conveyed to markets.
Sections 2.1 through 2.4 provide an overview of the activities of the
offshore oil and gas industry. Section 2.1 describes the Federal and state
leasing programs under which offshore development occurs. Section 2.2
describes the exploration activities undertaken by developers searching for
oil and gas in leased areas. Section 2.3 profiles production activity now
under way on offshore leases. Section 2.4 describes the activities which
support and maintain offshore leasing, exploration, and development. Section
2.5 reviews the industry downturn and recovery during the 1986 to 1988 period.
2.1 OFFSHORE LEASING
Offshore developers lease areas from the Federal government or from state
governments. The Federal government has jurisdiction over areas beyond 3
miles from the coast. State government jurisdiction, therefore, is over areas
within 3 miles of the coast. The exceptions to this rule are Texas and
Florida, which have jurisdiction over areas up to 3 leagues (9 nautical miles,
or 10.4 statute miles) from their shores. The exact line of jurisdiction in
Alaska is still under negotiation.
Leased tracts are available for both oil and gas development. Either
commodity, or both, is produced depending on its presence on the tract and on
the economics of transporting the commodity to market.
2-1
-------
2.1.1 Federal Leasing
Lease Sales
Federal leasing involves the auction of lease tracts in areas of Federal
jurisdiction. Lease tracts are the unit of territory leased. The standard
offshore lease tract is 5,760 acres or 9 square miles. In any one lease sale,
a large number of tracts might be offered in a specific area. The government
will lease only those tracts in which an acceptably high bonus bid (i.e.,
initial payment by the developer to operate on the lease) is received. The
acceptability of bids is determined within the U.S. Department of the Interior
(DOI).
Table 2-1 provides a history of all of the Federal offshore lease sales
through December 1985. As shown in the table, lease sale activity has
accelerated somewhat in recent years. Throughout the 31-year history of the
program, nearly 419.5 million acres have been offered and nearly 41 million
acres leased. A total of 77,553 lease tracts were offered, 9,009 tracts were
bid on, and 8,063 tracts leased during that period. In 1985, 87 million acres
were offered and over 3 million acres were leased, and 15,754 tracts were
offered and 642 tracts were leased. Most of the leasing that has occurred has
been off the coasts of Texas, Louisiana, and California. In more recent
years, tracts have also been offered off the Atlantic and Alaskan coasts.
Table 2-2 provides a summary of Federal leasing activity for 1980-86. The
number of tracts offered per year ranges from 483 to 27,984. Six percent of
the tracts offered during the 6-year period were bid on. Of the tracts bid
on, 90 percent of the bids were accepted.
Leasing Revenues
Payments made by lessees are of two types: bonus payments and royalties.'
Bonus payments are initial amounts paid by developers for the right to operate
on a lease. Royalties are per-unit payments made by operators for each unit
of oil or gas produced on the lease.
'A third category, annual rental payments at $8/hectare (equals $20/acre),
is of insufficient magnitude to be considered in the economic analysis.
2-2
-------
rO
I
Ul
TABLE 2-1
OUTER CONTINENTAL SHELF (OCS) FEDERAL LEASE SALE STATISTICS
1954-1985
lid Opening
1 10/13/54 LA
IS 10/13/5* LA
2 11/09/54 TX
} 07/12/55 TX.LA
S 05/26/59 n.
6 08/11/59 LA
7 02/24/60 TX.LA
8SA 05/19/60 LA
PHe 12/15/61 SCA
9 03/13/62 LA
10 03/16/62 TX.LA
11 10/09/62 LA
P-l 05/14/6) CA
12 04/28/64 LA
P-2 10/01/64 OK.VA
IIS 12/14/65 TX
14 03/29/66 LA
15 10/18/66 LA
P-3 12/15/66 CA
16 06/13/67 LA
17SA 09/05/67 LA
P-4 02/06/68 CA
18 05/21/68 TX
19 11/19/68 LA
19A 01/14/69 LA
20S 05/13/69 LA
198 12/16/69 LA
21 07/21/70 LA
22 12/15/70 LA
23 11/04/71 LA
24 09/12/72 LA
25 12/19/72 LA
26 06/19/73 TX.LA
32 12/20/73 HATLA
33 03/28/74 LA
34 05/29/74 TX
SI 07/30/74 TX.LA
36 10/16/74 LA
Subtotal:
(1954-74)
Sal* Offering
199 748,819
108 523,630
38 111,789
210 674.095
80 458,000
38 81,813
385 1.610,254
10 22.085
16 80,640
401 1,808,276
410 I.875.9S4
19 33,855
129 669,777
28 34,028
196 1.090,074
658 947.520
18 35.993
52 227,898
1 1 ,995
206 971,489
8 16,995
110 540,609
169 728.551
26 46.824
38 96,389
120 165.605
27 93.764
34 73.360
127 593.485 1
18 55,872
78 366.682
132 604,029
129 697,643
147 817,297
206 930,918
245 1.355,678
258 1.298.739
297 1.42LJ46
5.371 21.912.000 «
Only the offering and bidding date for thl.
the ewarded leaaee
bidder/leseeee. See
Mr* eubaequenclr term!
Blda Hada
336 90
5 5
90 19
384 121
23 23
56 28
444 173
1 1
6 6
538 212
666 210
26 14
70 58
69 23
222 101
113 50
64 18
79 32
7 1
743 172
1 1
164 75
556 141
38 21
40 26
43 38
58 16
59 21
.043 127
33 13
324 74
690 119
551 104
373 89
402 1 14
352 123
57 49
387 157
.113 2.665 II
phoephete leeaa
natad and mil ^
394,721
25.000
67.149
402,567
132.480
62,967
813,663
2,500
30.240
981.407
977.092
24,858
312,975
32.671
580.853
72.000
35.993
134.717
1.995
812.202
2.495
383,341
666.631
40.262
61.628
50.880
60.153
50,889
593,485
42,222
346.693
548.374
566,373
496,917
522.397
680.335
249 . 704
733.927
.994.976
! are
Table 4 footnote (or detella.
"SA." PH Indlcacae e phoaphate laeea asle; P
th« eala nue&e
Indicate! Pacific (area:
" Sale Tracta Acrea
S 302.924,814
1.231500 ' 90 194'721
73.801.896 IS 5 25'000
323,240.032 2 " *7'"'
1 711 872 ' IJ1 *02'567
174.411.628 5 21 1J2'480
575.175,650 6 " M'820
75 250 ' '*' 704.526
'," 8SA 1 2.500
314.218.540 '" <«> (30.240)
605.357 718 » 206 »56-*0'
6*. 265. 290 I0 205 956.592
13.989.953 " ' ""
93,850,031
53,579.753
56.324.364
275.384.739
185.214,816
89.937,020
1,627.749,269
30,364
1,293.601,113
1,620.393.212
398.430,736
71,036,938
4.070,549
230.460.74)
163.451.158
2,877.429,559
172,733.981
1.399.133.464
6.191,018,227
6,248,160,989
3,404.892,968
6.474,003,574
3.334.292.556
P-l 57 312,945
12 23 32.671
P-2 101 580.853
I3S 50 72.000
14 17 35.056
15 24 104,717
P-3 1 1.993
16 158 744.456
I7SA 1 2,495
P-4 71 363.181
18 110 541,304
19 16 29,679
I9A 20 48, 304
20S 4 5,625
198 16 60,153
21 19 44,642
22 119 553,898
23 11 37,222
24 62 290,321
25 116 5)5,874
26 100 547.17)
)2 87 485.397
)) 91 421.218
88,799,334 34 102 565.112
2.521.756.919 SI 19 100.241
J4 1.548. 166. 799 )6 144 675.587
TTK 10, 8*4.254
totaled here since
High-lid Bonusee
Submitted Accaptad
$ 116.378.476
1,233,300
23,357.029
108,528,726
1,711.872
90.286.693
285.180.648
75.250
(122,000)
177,745,105
268,724,090
44,399,399
12,807,387
60,340.626
35.533.701
33.740.309
89.054,406
101,730.216
21,189.000
311.957.288
30,564
603.204.284
602.473,717
150.482,797
45.588,052
3,678,045
66,908.196
98,101.013
851,388,399
96,491,023
386,297,925
1.673,054,912
1.598,590,620
1.491,617,119
2,175,095,514
1.502.429.426
76.617,645
1,445.175,340
$15.051.200.712
Iddlna systeaj: 10
$ 116.378.476
1.233.500
2), 357, 029
108,328.726
1,711,872
88.033,120
282.641,815
75.250
(122,000)
I77.260.3U5
268,333,397
4'3.887.359
12,807,337
60,340,626
35.533,701
33,740.309
88,843,96)
99,164,930
21.189.000
510.079.178
30.564
602.719.262
59). 899. 046
149.868,789
44.0)7,339
713,150
66.908,196
97,769,013
847.295,760
96.304.32)
585.827.925
1.665. 519. 631
I.59I.)97.)80
1.491.065.2)1
2.092.510.854
1,471.851.831
30,2)6,800
1,428,261.330
$14,829,362.517
tracts (51,513 scr
bidding systea; 287 tracts (1,370.031 acres) were offered In
sale; US Indlc.tes "d """ "lth '" l"
bonuses); another 1*9 tracts (693,173
High Bide lalactad
No. A*ount
0
0
0
0
0
9 $
26
0
0
6
5
5
1
0
0
0
1
8
0
14
0
4
31
3
6
34
0
2
8
2
12
3
4
2
23
21
30
13
0
0
0
0
0
2.251,573
2,538.833
0
0
484.800
390,693
512,040
250
0
0
0
208.44)
2.563.286
0
1.878.110
0
485.022
8.576.671
614,008
1.350.713
2.962,895
0
332.000
4,092.839
186.500
470,000
7,535.281
7. 19). 240
551.888
82.584.660
30.577.595
46,380.845
16,914,010
775 S22I.838.195
a) were
a high
ecres)
(634,832 acres) for en average .52 ,2*8.22 per
offered In e
Average 81d PI rat -Year
par Acre Rentala
S 294.84
49.34
347.84
269.59
12.92
2.267.28
401.18
30.10
4.03
185.34
280.51
2.712.79
40.93
1.846.90
61.18
468.62
2,534.44
946.98
10.618.50
685.17
12.25
1.659.56
1.097.16
5,049.59
907.90
127.14
I.I 12. 30
2.190.07
1.529.70
2.587.29
2.017.87
3,108.0*
2.908.40
3.071.83
4.967.76
2,604.5)
301.64
H/A
rnyelty
$ 1,18*. 175
50.000
201.450
1.207.722
397,440
388,200
2.113.599
7.500
N/A
2.855.43)
2.869.6)8
161.780
938.838
326.780
1.742.562
216.000
350.570
523.600
9.980
2.233.458
7.485
1.089.543
1.623.915
296.820
485,030
16.875
601.350
446.420
1,661.694
372.230
870.996
.607,661
.641.519
.456.197
.263.675
.695,3*8
)00.729
2,026,812
$35.243.244
aid-bonus aystcia. Of
were bid on the high-
acre ($1.427
2*2.455
Table 3 footnotea for an explenetlon.
-------
TABLE 2-1 (Cent)
to
I
Bid Opening
17 02/04/75
18 05/28/75
ISA 07/29/75
15 12/11/75
41 02/18/76
19 04/13/76
40 08/17/76
44 11/16/76
47 06/21/77
Cl 10/27/77
41 01/28/78
45 04/25/78
65 10/31/78
51 12/19/78
49 02/28/79
48 06/29/79
58 07/31/79
58A 11/27/79
BF 12/11/79
42 12/18/79
A62 09/10/80
55 10/21/80
62 11/18/80
53 05/28/81
IS-I 06/30/81
A66 07/21/81
56 08/04/81
60 09/29/81
66 10/20/81
59 12/08/81
67 02/09/82
68 06/11/82
1S-2 08/05/82
71 10/13/82
69-1 11/17/82
Su
TX
TX.LA
TX.LA
CA
COM
COA
Mld-ATL
TX.LA
COM
LCI
S. ATL
TX.LA
COM
TX.LA
Mld-ATL
CA
COM
COM
Beaufort
N. ATL
COM
COA
COM
CA
AK
COM
S. ATL
LCI
COM
Mld-ATL
COH
S. CA
ATL.CA.AK
Dlaplr
COM
btotal: 6
Sale
515
283
145
211
112
189
154
61
221
115
224
1 4*5
89
128
109
148
121
124
46
116
192
210
81
III
175
212
285
151
209
251
234
140
554
338
144
,811
Offering
2,870.3*4
l.)46,412
1.772.958
1,257,59)
687.604
1,008.500
876,750
254,488
1.074,536
768,580
1.275.27)
709.727
511,709
643,987
620,557
792,845
577.517
588.601
172.320
660.409
909.575
1,195.569
458,308
603,61)
996.308
,077,91)
,622,557
858,247
,081,364
,440,176
,219,826
716,840
), 142, 068
1,825,770
7)2.570
16.351.634
Nimber
281
191
179
166
81
244
410
117
424
240
99
28)
62
288
74
112
316
322
62
189
506
64
268
301
7
419
120
1)
2))
240
290
66
48
2)2
151
7,120
Blda Made
Tracta Acrea
14) 796.367
102
80
70
41
81
101
48
152
91
J7
1OI
15
88
44
55
88
96
25
7)
147
)7
74
81
5
162
54
1)
107
98
1)7
15
40
12)
67
486.127
408,009
384,540
191,718
437,524
575,012
201,825
739,326
518,080
124,511
490,752
201,295
449,691
250,500
294,018
424,010
450,914
88.0)7
415,602
706.042
210,648
420,058
432,817
28,466
829,900
307.321
73.158
532.041
557,9)2
695,749
176,25)
227,727
68), 026
119.999
14.349,215
La
S 484,721,874 "
402,752,355 38
317,001,113 38A
901.960.364 "
428.003,629 *'
1,732,170,868 "
3,513.411,802 40
831.015,950 **
2.928,091,214 ' *'
677.075.681 ' cl
150.927.700 *'
1,559,145,260 4i
87,592,568 '*
2.155,261.107 . S1
66.005,881 **
994,681,701 1 *
1,111,990,620
4,681,195,907
945,445,102
1,270,789,890
7.119,464,691
197,417,469
1,500,570,271
4,885,810,689
5,582,362
5,227,548,535
561,050,365
4,697,309
2,402,400,552
578,952,000
2,681,699,84)
210,486,278
14,439,195
4,589,972,518
1.185,091.610
960.832,628,693
58
58A
BF
42
A62
55
62
53
IS-1
A66
56
60
66
59
67
68
IS-2
71
69-1
aaea laaued
TrectB Acres
111
86
66
56
14
76
9]
41
124
87
41
90
15
81
39
54
81
90
24
61
116
15
67
60
1
156
47
1)
102
50
115
29
16
121
56
626,585
406,942
116,101
110,049
161,286
409,058
529,466
178,127
605,427
495,107
244,807
438.756
201,295
412,416
222,014
288,260
391,181
421.519
85.776
158.671
551.641
199.261
383.121
120.567
5.694
799,899
267.580
71,158
508,287
284,659
590,265
147.066
204,955
662,861
281.211
12.403.696
Hlph-Bld Bonuaea
Subnltted ArrmnrmA
S 300,632.667
250,681.156
171,511.620
438.190.780
183.498.244
571,871,587
1,135.802,179
381.911,757
1,214.002,429
400,319,543
109,695,692
767.407.369
61.176.7)0
884,589.799
41.720.618
573.956.402
1.261. 358. 089
1,9)2,894.290
491.728,138
827,832,854
2.805,524,391
117,550,113
1.416.448.959
2,277,856,761
1,091,718
2,666.828.152
163.829.954
4.405.899
1.280,983.917
424.927.000
1.251.793.459
132.252,632
12.110.706
2,067,604.786
6)4.919.980
$27,481,110,592
$ 274,690.955
232.916,050
163,214,006
417,312,141
175,976.49)
559.8)6.587
1.127.936.425
379.148.962
1.170.093.412
198.471,111
100,741,441
733,656,893
61,176,710
871,464,998
40,001,611
572,825,418
1.247,489,022
1.911,137.938
488.691,117
816.516.546
2.676.927,671
109.751,071
1,417,961,511
2,088,881.824
170.496
2.649,628,752
142,766,174
4,405.899
1,241.468,752
121,911.000
1.191.654.719
117.875.281
11.149.450
2,055.6)2,1)6
609,178,22)
$26.588,881,28)
Hlfh
30
16
14
14
7
5
8
5
28
4
14
11
0
7
5
1
7
6
1
10
31
2
7
21
4
6
7
0
5
47
22
6
4
4
II
"Ho
Blda (ejected
$ 25,941,712
17,765.106
8,297.614
20,878.639
7,521,751
12,0)5,000
7,865,754
2.762,795
41,908,997
1,848,210
8,952,249
11,750,476
0
11.124,801
1,718,987
1,130.984
13.869,067
19.556.352
3,037,001
11,316,308
128,596.720
7.799.040
18,487.448
24,648.000
2,921,242
17,199,600
21.063,780
0
37,515.165
101.268.000
58.138.740
14.177.151
1.161.256
11.972.450
25,741,757
$726.172,172
Average lid
S 418.19
572.16
485.32
1.145.96
1.091.09
1.368.60
2.110.33
2.128.53
1.932.68
804.49
411.52
1.672.13
303.92
2.113.07
180.16
1.987.18
3.189.02
4.539.15
5.697.27
2,276.51
4,852.54
550.79
3,699.12
6.516.21
29.95
3,112.45
1.280.99
60.23
2.446.39
1,130.91
2.022.29
668.77
54.40
3.101.00
2.166.24
N/A
Fl rat -Tear
$ 1.879.761
1.220.856
1,008.906
910.147
481,867
1,226.718
1.714,176
534.396
1.816.302
1,601.584
792,576
1.316.281
601,885
1.217.261
718.848
867.489
1.171,570
1,264,590
277.808
1. 161. 216
1.654.962
645,120
1.149.969
927.112
18.412
2,199,736
866,304
236.856
1.524.903
921.600
1,770.795
441,911
663.552
2.146,112
841,657
S18.045.464
(1975-82)
MOTE: In Sale 53 (Hay 1981), Chevron USA and Phillips Pvtrolaus) jointly psld the hlghee
per acre bid so far, of $65,014.16 on Tract So. 450 In th« Santa Harts lasln. Alt of* the
Che trsct's 5,131 acres brought In 93)3,596,200 of the total accepted bonus paystenta o
$2,088.881,824. In the sasM !*, high bidders afterward* relinquished lesslng rights t
12 other trscts. thus forfeiting one-fifth or $41,081,734 of their $205.408,672 In bids
Bids for 9 other trscts were rejected as Insufficient. The sversgs bid per acre
$6.516.21 on 120.567 tcrcs. As adjusted, totsls for thle sale slso reflect Issuance
1984 of lesses for 5 trscts previously delsyed by litigation.
-------
TABLE 2-1 (Cont.)
to
01
Bid Opening Sale Offering Bide Made
Leaaes teeued
69-2 03/08/83 COM 125 665, 47S 20 13 68.106 S 48.755,129 69-2 II
57
70
76
72
7»
74
73
79
83
81
84
87
80
98
102
94
03/15/83 Norton 418 2,379,751 98 64 364,364 371,803,984 57
04/12/83 St. Ceo 479 2,688,787 150 97 546,609 547.731,283 70
04/26/83 Hld-ATL 4.050 22,664,991 53 40 227,727 86.022,680 76
05/25/83 CCOM 7,050 37.867,762 1,015 656 3,249.135 4,582,847,288 72
07/26/83 S. ATL 3.582 20,156.426 12 11 62,625 14,262.040 78
08/24/83 UCOM 5,848 32,620,248 773 436 2,410,782 2,350,359,669 74
11/30/83 Cen-CA 137 768,341 14 8 43,799 24,045,646 73
01/05/84 ECOI1 8,868 50,631,513 226 156 897.786 500,261,361 79
04/17/84 Navarln 5,036 28,048.995 425 116 1,058,932 1,148.701.653 83
04/24/84 CCOM 6,502 34.743,780 793 529 2,650,070 2.126.776.904 . 81
07/18/84 UCOM 5.446 30.038,593 593 402 2,173.704 1.263.576.675 84
08/22/84 Dlaplr 1.419 7,773.447 432 232 1,233.573 1,365.968.674 87
10/17/84 S. CA 657 3.147,352 30 25 125,100 73,163,686 ': 80
05/22/85 CCOM 4,531 24,006,157 644 444 2,241,598 1,566,926.725
08/14/85 UCOM 4.879 27.199,074 265 210 1,156,841 519.116.036
12/18/85 ECOM 6,344 35.823.478 114 82 450.259 155,241,798
Subtotal: 65,371 361.224.173 5.657 3,591 18,961,010 $ 16.746.361.231
( 1983-85)
Total: 77,553 419.487.807 21.890 9,009 45,305,201 $119,127,156,723
(1954-85)
and had to forfeit their one-fifth bonus deposits.
In Sale 7) (November 1983), litigation delayed the scheduled bid opening until Oeceaber.
Pending settle»ent of International boundary disputes with Che Soviet Union (Sale 83/Aprll
1984) and Canada (Sale 87/August 1984), Issuance of aoate leases remains on hold, although
the data are herein reported. These Include 17 tracts on 96,784 acres for SIOA,174.0OO tn
bids received (Sale 83) and 4 tracta on 22.773 acres for $$,104.000 In bids received (Sale
tram the day of the bid opening, they also mmj be withdrawn by the bidder. If the bids are
either rejected or withdrawn, the bonus depoelta together with accrued interest Moneys will
be rsturned to the bidders.
98
102
94 *
*
59
96
37
623
II
406
»
156
180
453
361
231
23
409
195
38
3.297
8,063
In Sal*
(of the
Laaaee h
acree) ,
58.117
335.898
540,917
210.648
3.089.812
62.625
2,246.005
43.801
897,786
1,024.772
2.278.129
1.949,186
1.230.486
114.363
2.076.907
1.075,188
215,948
17.450,588
40,743,543
94 (December
High-Bid Bonueee
S 39.741.340
325.267.372
427,343,830
71.141.240
3.469.214.969
13.062.040
1.549.262,300
16.022,336
310,586,261
631,228,331
1,446,584,927
945,717,312
877,131.327
66.231 ,426
1,147.434.447
391.137.53*
122,022.098
$11.849,129,092
$54,381,440,396
$ 37,570.900
317,873,372
426,458,830
68,410,240
3.367,606.134
13.062.040
1,501.712,517
16.022,336
llO.586.2dl
624,491,331
1 ,323,036,649
844,850.488
871.964,327
62.121.252
1,079,377.760
359,175.656
49,473.298
$11,273,793,391
$52,692,039.191
38) and forfeited the one-fifth bonul depoelt
eve not been
laeued to high bidden In Sale 94
pending reeolutlon of the
High Bide
2
5
1
3
33
0
30
0
0
6
76
41
1
2
35
15
0
250
895
($12,331
$ 2
7
2
101
47
6
123
100
5
4
68
31
$ 502
$1,450
.200).
for another 39
hold lapoeed under Military
Rejected Average Btd
tenunt
, 170 440
.394.000
885,000
.731 .000
,608,835
r>
,549,783
0
0
,737,000
,548,278
,866,824
.167,000
110.174
.056,687
961 .880
0
786,901
797.467
per Acre
J 646.47
946.34
788.40
324.77
1.089.91
208.58
66H.62
365.02
345.95
609.40
580.76
433.44
708.63
543.20
519.70
334.06
229.10
N/A
N/A
ri rut-Tear
Rentale
681 984
9,269,616
141 808
2 69) 158
2 784 366
6 834 5)7
5 847 6)9
3 910 184
347 157
6,230,829
3,225 597
647.844
S 52,568.782
$125.857.375
Time. 33 leaees
trecta (205
Stipulation
.511
5.
Source: U.S. Department of the Interior, Minerals Management Service
Federal Offshore Statistics; 1985. DCS Report , MMS 87-0008,
Table 2
-------
TABLE 2-2
OCS LEASING STATISTICS, 1980-1986
YEAR
1980
1981
1982
1983
1984
1985
1986
NO. OF
TRACTS
OFFERED
483
1,398
1,410
1,689
27,984
15,754
10,724
NO. OF
TRACTS
BID ON
258
520
404
1,325
1,530
736
155
NO. OF
TRACTS
SOLD
218
430
357
1,251
1,404
642
142
AVERAGE BONUS
BID PER TRACT*
(millions of $)
19.3
15.4
11.2
4.6
2.9
2.3
1.3
*Current dollars.
Source: "Federal Offshore Statistics: 1984," U.S. Department of the
Interior, Minerals Management Service, MMS 86-0067; "Federal Offshore
Statistics: 1985," U.S. Department of the Interior, Minerals
Management Service, MMS 87-0008, from Tables 2 and 3; and "Outer
Continental Shelf Statistical Summary, 1986," U.S. Department of the
Interior, Minerals Management Service, MMS 86-0122.
2-6
-------
Tables 2-1 and 2-2 provide economic data on the Federal offshore lease
sales for which summary data have been published to date. The tables show che
bonus payments (or "bid prices") that have been received for leased areas.
During the period from October 1954 through December 1985, bonus payments
totaling over $52 billion were received by the Federal treasury for offshore
tracts, with the average tract leasing for $6.5 million (Table 2-1). Average
lease bonus payments per tract peaked during 1980-1982 when the average ranged
from $11.2 million to $19.3 million per tract. These figures have declined
and average bonuses for 1983 through 1986 range from $1.3 million to $4.6
million (Table 2-2). These declines reflect the recent downturn in drilling
activity due to depressed oil prices.
The other major category of payments made by lease developers is royalty
payments. These payments are set as a proportion of the value1 of oil and gas
produced. Royalty payments are set in most cases at between one-eighth and
one-sixth of the value of the produced oil and gas. For example, royalties on
a $20 barrel of oil would be $2.50 to $3.33.
Table 2-3 shows the royalties that have been received by the Federal
government for offshore oil and gas production. Note that over $27 billion in
royalties have been paid through 1986. As the number of operating platforms
grows, annual levels of royalty payments continue to grow. In 1984 alone,
over $3.8 billion of oil and gas royalty payments were made for OCS leases.
Outer continental shelf (OCS) leasing by the U.S. Department of the
Interior provides a considerable amount of revenue to the U.S. Treasury in the
forms of bonus and royalty payments. The Bureau of Land Management (BLM) OCS
office in New Orleans, which coordinates all Federal lease sales, is third
only to the Internal Revenue Service and the Bureau of Alcohol, Tobacco and
Firearms in government revenue production. Table 2-4 shows the annual revenue
to the U.S. government resulting from offshore oil and gas leases including
both bonus and royalty payments. Almost $10 billion was received in 1981 as a
result of Federal leasing, although the annual figure has declined with only
$3 billion received in 1986.
'Value, as used here, is equivalent to the wellhead selling price of oil or
gas. Because oil or gas are frequently not sold at the wellhead, the term
"value" is the wellhead value of the oil or gas established by MMS based on
information concerning regional wellhead selling prices.
2-7
-------
TABLE 2-3
TOTAL ROYALTY REVENUES BY COMMODITY AND YEAR
FROM ALL OFFSHORE FEDERAL LEASES, 1953-1986
ROYALTIES PAID (BILLIONS OF DOLLARS)1
YEAR
1953-1980
1981
1982
1983
1984
1985
1986
Total (1953-1986)
OIL
$5.378
1.575
1.740
1.640
1.823
1.707
1.015
$14.878
GAS
$4.669
1.712
2.075
1.815
2.091
1.906
1.518
$12.362
'Does not include royalties for substances other than oil and natural
fas; such subsidies amounted to $0.239 billion (cumulative) for the period
953-1986. Values in current dollars.
Sources: "Mineral Revenues: The 1985 Report on Receipts from Federal and
Indian Leases," U.S. Department of the Interior, Minerals Management
Service, MMS 86-0067, Table 8, and "Mineral Revenues: The 1986
Report on Receipts from Federal and Indian Leases," U.S. Department
of the Interior, Minerals Management Service, Table 8.
2-8
-------
TABLE 2-4
TOTAL OCS FEDERAL OFFSHORE LEASING SUMMARY, 1975-1986 FOR ALL REGIONS
to
I
VO
PRODUCTION
SALE ACTIVITY
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
NUMBER
OF
SALES
4
4
2
4
6
3
7
5
7
6
3
2
ACREAGE
OFFERED
7,247,247
2,827,342
1,843,116
3,140,696
3,412,249
2,563,452
7,679,740
7,637,122
120,054,037
154,383,680
87,028,709
58,670,103
ACREAGE
LEASED
1,679,877
1,277,936
1,100,741
1,297,280
1,767,512
1,134,238
2,265,649
1,886,359
6,587,879
7,494,803
3,368,043
734,419
TRACTS
LEASED
321
246
211
249
351
218
430
357
1,251
1,404
642
142
CRUDE AND
CONDENSATE
(MILLION
BBL)
330
317
304
292
286
277
290
321
348
370
389
389
GOVERNMENT
RECEIPTS
(BILLIONS
OF DOLLARS)*
GAS
(TRILLION
CU FT)
3.459
3.596
3.738
4.386
4.673
3.641
4.850
4.680
4.041
4.538
4.001
3.949
BONUS
1.088
2.243
1.569
1.767
5.079
4.205
6.599
3.987
5.749
4.037
1.488
0.187
ROYALTY
0.595
0.680
0.890
1.139
1.512
2.132
3.287
3.815
3.454
3.915
3.613
2.533
*Current dollars.
Source: "Federal Offshore Statistics: 1984," U.S. Department of the Interior, Minerals Management
Service, MMS 86-0067; "Federal Offshore Statistics: 1985," U.S. Department of the Interior,
Minerals Management Service, MMS 87-0008, Tables 3, 16, 19, and 20; and "Mineral Revenues: The
1986 Report on Receipts from Federal and Indian Leases," U.S. Department of the Interior,
Minerals Management Service, Royalty Management Program.
-------
Other Federal Lease Provisions
Besides the bonus and royalty payments associated with Federal leases,
there are a number of other key lease conditions. The duration of leases is
usually 5 years. In areas with harsh climates or in very deep waters, the
initial term may be set at 10 years. The leases are automatically renewable
if production is established.
Other conditions of the leases include various stipulations which may be
appended to the lease. Examples of these stipulations are:
Cultural Resources
Biological Resources
Drilling Fluids and Drill Cuttings and Formation Water Disposal
Military Area
NASA Area
Geologic Hazards
Undetonated Explosives and Radioactive Materials
The intent of the cultural resources and biological resources stipulations
is to ensure that if an archeological find or an endangered species or habitat
is found within a lease area, care will be taken to protect it. The military
area and NASA area stipulations are added to the lease if it is felt that
drilling activity may interfere with military or NASA operations. Geological
hazards analysis may be required under the geological hazards stipulation if
the bottom is known to be unstable or unable to support a drilling platform.
The disposal of drilling fluids and drill cuttings and formation or produced
waters has been restricted (under the geologic hazards stipulation) in some
areas to protect the marine environment.1 A final stipulation may require
that any undetonated explosives or radioactive materials be located prior to
drilling.
2.1.2 State Leasing Activity
Each state runs its own leasing program and there is no coordination
between the states and the Federal Minerals Management Service in the leasing
process. Most states do not publish historical data on individual lease
'Such a restriction differs from EPA effluent guidelines in that the former
is applied only where a unique or very sensitive ecology is involved.
2-10
-------
sales. Information on each of the states presented in the tables below is
based mostly on conversations with state land commission personnel. One
factor that is common to all state leasing programs is the slowdown in leasing
activity since late 1981. This has been attributed to the current oil glut
and slump in oil prices. State officials anticipate an increase in leasing
activity when the demand for and price of oil increase again.
Table 2-5 summarizes the key financial aspects of the state leasing
programs and Table 2-6 summarizes historical and planned leasing activities.
Overall approximately 28 percent of the offshore development that has occurred
to date has been in state waters.
2.2 OFFSHORE OIL AND GAS EXPLORATION
Prior to the lease sale, companies perform seismic investigations on sites
that have potential as hydrocarbon reservoirs. Based on seismic analysis of
the subsurface rock structures, the company will make an estimate of the
potential quantity of extractable oil and gas. The results of these
investigations are considered proprietary information. The expected market
value of the extractable oil and gas is the basis for deciding whether to bid
on a particular tract, and what the cash value of the bid should be. Seismic
investigations cannot fully define an oil formation. (Of those areas that
seismic studies identify as candidates for exploratory drilling, only 15
percent of the tracts drilled will prove to contain economic amounts of oil or
gas.)
After a company has leased a tract and the necessary permits have been
obtained, exploratory drilling can commence. Several exploration wells may be
drilled on a tract, depending on the high-potential areas indicated by seismic
and structural analysis. Exploration wells are usually drilled from mobile
drilling platforms that are operated by contractors for petroleum companies.
Table 2-7 provides historical statistics on the level of exploratory
drilling that has occurred in each offshore region up to January 1, 1985. An
estimated 7,468 exploratory wells had been drilled as of that time. Of these,
5,206 have been drilled in Federal waters. This is an average of
approximately .70 exploratory well per leased Federal tract, i.e., 5,206 wells
drilled on 7,418 tracts leased at the end of 1984 (see Table 2-1). Of all
wells, oil was found in 376 cases (5.0 percent), gas was found in 641 cases
(8.6 percent), and 6,451 (86.4 percent) were dry holes. Historically, 30
2-11
-------
TABLE 2-5
SUMMARY OF STATE OFFSHORE LEASE TERMS
STATE
Alabama*
A1 acUab
LEASE
DURATION
5 yr -
renewed if
producing
DRILLING
REQUIRED RENT BONUS
yes $5/acre/year Bid item- -has
ranged from
$438/acre to
$31,500/acre
... ...All C.nnAi fMnnc \Iar-ia\\~\o -
ROYALTY
RATE
16.67% minimum-
set by board
for each lease
sale
California0
10
I
Louisiana*1
Texas'
20 yr and then
for as long as
producing
yes
5 yr--renewed
if producing
5 yr--renewed
if producing
yes
yes
PRESENT-
$I/acre
FUTURE OPTION
10.000.000/
parcel first
3 yr, then
$I/acre
Not less than
1/2 of cash
bonus
$10/acre
Bid item--has
ranged from
$100,000 to
$250,000,000 for
5000-acre parcel
Bid item
Bid item -
minimum $180/acres
Sliding royalty
depending on
production,
ranging from
1/6 to 1/2
FUTURE OPTION
Bid item-percent
of net profits
Bid item-varies
from 20% up
Bid item -
minimum 25%
'Alabama Department of Conservation, State Lands Division, R. McRory, March 1987.
"Alaska Department of Natural Resources, Lease Sale Section, E. Phillips, March 1987.
'California State Lands Commission, A. Willard, March 1987.
"Louisiana State Mineral Board, M. Hays, March 1987.
'Texas General Land Office, S. Sharlot, March 1987.
-------
TABLE 2-6
HISTORICAL AND PLANNED STATE OFFSHORE LEASING ACTIVITIES
State
Alabama
Alaska
Currently
Leased
Acres
105,000
Production
Activity
(No. of
Platforms)
2
15
Future Planned
Lease Sales
One sale scheduled
Five sales planned
for July 1988
1988-1992
California 132,419
Florida 2,600,000
Louisiana 249,889
Texas
430,000
involving offshore tracts.
15 None currently planned;
environmental impact assessments
preceding for several potential
future sales.
0 None
800 Lease sales are held monthly;
leasing activity has declined
since 1980
113 Lease sales held twice per year;
leasing activity has declined
since the early 1980s.
Sources:
Alaska
Alabama
California
Florida
Louisiana
Texas
Litzen, Kelly. Alaska Dep't of Natural Resources,
Division of Oil and Gas. Telephone conversation, 1/88.
Douglas, Russ. Alaska Oil I Gas Conservation
Commission. Telephone conversation, 3/88.
Alaska Dep't of Natural Resources, Div. of Oil and
Gas. Five Year Oil and Gas Leasing Program. 1/88.
McRory, Robert. Alabama Dep't of Conservation, State
Land Division. Telephone conversation, 3/88.
Uillard, Al. California State Lands Commission.
Telephone conversation, 3/88.
California Dep't of Conservation, Div. of Oil and
Gas. 1987. 72nd Annual Report of the State Oil I Gas
Supervisor. Sacramento.
Hachenberger, Ed. Florida Dep't of Natural Resources,
Division of State Lands. Telephone Conversation, 3/88.
Alexander, Sarah. Louisiana Off. of Mineral Resources,
Mineral Board, Production Audit Section. Telephone
conversation, March 1988.
U.S. Department of Interior, Minerals Management
Service, as reported by OOC in a letter to EPA.
Boone, Peter. Texas General Land Office. Telephone
conservation, March 1988.
2-13
-------
TABLE 2-7
TOTAL OFFSHORE' EXPLORATORY DRILLING IN THE UNITED STATES
FEDERAL AND STATE LEASES ALLTIME TO JANUARY 1, 1985
NUMBER OF EXPLORATORY WELLS
LOCATION
ALASKA
State
Federal
Total
CALIFORNIA
State
Federal
Total
OREGON
Federal
WASHINGTON
State
Federal
Total
PACIFIC COAST"
Federal
PACIFIC OCEAN*
State
Federal
Total
FLORIDA
State
Federal
Total
LOUISIANA
State
Federal
Total
TEXAS
State
Federal
Total
OIL
19
1
20
20
24
44
--
39
25
64
61
206
267
35
10
45
GAS
7
7
10
10
--
17
17
96
253
349
182
91
273
DRY
54
19
73
139
155
294
8
2
4
6
38
195
224
419
15
9
24
920
3,079
3,999
700
1,032
1,732
TOTAL
80
20
100
169
179
348
8
2
4
6
38
251
249
500
15
9
24
1,077
3,538
4,615
917
1,113
2,050
(Cont.)
2-14
-------
TABLE 2-7 (Continued)
LOCATION
OIL
ALABAMA
State (Mobile
Bay)
ATLANTIC OCEAN
Federal
GRAND TOTAL
State
Federal
Total
NUMBER OF EXPLORATORY WELLS
135
241
376
GAS
297
344
641
DRY
36
1,830
4,621
6,451
TOTAL
N. GULF OF MEXICO"
Federal
GULF OF MEXICO
State
Federal
Total
--
96
216
312
278
344
622
241
1,635
4,361
5,996
241
2,009
4,921
6,930
36
2,2.62
5,206
7,468
'Offshore wells are defined as those producing from beyond natural
shorelines.
""Pacific waters north of Southern California.
'Southern California Pacific waters.
dln 1972 BLM designated certain areas previously not mapped or leased to
this area, including areas to the south of the Texas and Louisiana Federal
waters.
Source: Basic Petroleum Data Book. Volume VIII, No. 1, January 1988, Section
XI, Table 7.
2-15
-------
percent of exploratory drilling occurred in state waters and 70 percent in
Federal waters.
23 OFFSHORE OIL AND GAS DEVELOPMENT
23.1 Development Logistics
Once exploratory drilling has established that oil or gas is present on a
leased tract, the designated operating company contracts with a drilling
company to complete a number of delineation wells. These holes are used to
roughly define the areal extent and volume of reservoirs. (A leased tract is
the surface area for which the operating company has drilling rights. A
reservoir is that part of a subsurface formation that contains oil or gas.)
This information, along with porosity, permeability, specific gravity, and
viscosity measurements, is used to characterize the reservoir.
The estimated volume of producible reserves, the ease (cost) of
extraction, and the expected crude oil price will determine whether or not the
operating company will produce the field. Characteristics of the field
(volume, porosity, water saturation, and other data used to calculate
hydrocarbon volumes) will determine the number and spacing of production wells
required for the most efficient exploitation of the reservoir. Spacing can
vary from 15 acres/well (the densest spacing for any currently producing
field, found in the Beta field off California) to more than 200 acres/well (a
less dense spacing more common in the Gulf of Mexico).
Once the data from reservoir delineation have been fully analyzed and a
decision made to begin development, a production platform is put in place.
Platforms are custom designed for water depth, bottom stability conditions,
expected number of wells, size of drilling rig, and other factors. Additional
wells, called development wells, are drilled from this permanent production
platform. This platform may handle the production of a number of wells. The
optimum number of production wells, the depth of the field below the sea
floor, and the water depth over the field will determine the required number
and placement of production platforms.
2-16
-------
23.2 Inventory of Offshore Production Platforms
An inventory of existing production platforms on Federal- and state-leased
tracts is presented below. This inventory covers all Federal and state waters
and both oil and gas production. The boundaries of the offshore subcategory
waters are defined in 40 CFR 435. A platform is offshore if it is located
seaward of the inner boundary of the territorial seas. For this analysis, we
focus on structures that are in production and are likely to incur BAT costs
for produced water and drilling effluent disposal under the various regulatory
options.
Platforms in Federal Waters
Table 2-8 presents data on the number of platforms located on Federal OCS
leases. Overall, there are an estimated 2,253 platforms and approximately
12,300 producing wells. Note that of the 2,253 platforms in Federal waters,
2,233 are in the Gulf of Mexico. The count of structures in the Federal
waters of the Gulf of Mexico is based on March 1988 data from the MMS Platform
Inspection System, Complex/Structure data base. The count is restricted to
those structures that:
had not been removed as of March 1988
had at least one drilled, productive well slot
(Structures having no well slots, no drilled wellslots, no information
on the number of wellslots, or whose wells were used solely for
injection, disposal, or as a water source were excluded from the
count.)
were in production and had information on product types (oil, gas, or
both)
More details are given in Appendix H on how the count was obtained.
The inventory of structures off the California coast is estimated from
data from the California Division of Oil and Gas and the California Coastal
Commission. Onshore wells with offshore completions, and structures within
inland bays are not included in this inventory since they fall into a
different subcategory. At present, no production platforms are in place in
Federal waters off the coast of Alaska or in the Atlantic.
2-17
-------
TABLE 2-8
FEDERAL WATERS INVENTORY AS OF MARCH 1988
PRODUCING PLATFORMS
AREA
NUMBER OF
PRODUCTION
PLATFORMS
NUMBER OF
PRODUCING
WELLS
COMMENTS
Alaska
Atlantic
California
Gulf of Mexico
TOTAL FEDERAL OCS
20
2,233
2,253
380
11,892
12,273
All Federal OCS areas
still in exploration
phase.
All Federal OCS areas
still in exploration
phase.
See Table 2-11.
See text.
Source: ERG estimates.
2-18
-------
Platforms in State Waters
It is very difficult to obtain a precise count of offshore platforms in
State waters. This is because several States define "offshore" as producing
beyond the natural shore line. This definition includes wells and structures
that are not in the offshore category, such as wells spudded onshore but
completed offshore and structures in inland bays. States such as Louisiana
and Texas maintain counts of production wells, but not platforms.
Table 2-9 is a listing of platforms in State waters. Where it has been
possible to identify offshore structures, this has been done. The data for
Louisiana and Texas is starred because of the uncertainties associated with
them; it is not possible to precisely identify producing structures and wells
that are in the offshore subcategory. This is an area of research that will
be undertaken before final promulgation. Table 2-10 is a listing of the
platforms off the California coast.
Summary of Platform Count
A total of 2,260 structures was estimated for the count of existing
structures in production in the offshore subcategory. This figure includes
all structures in Table 2-8, plus the Pacific offshore structures in Table
2-9. The amount of pollution control equipment for produced water allocated
to the 2,233 structures in the Gulf of Mexico has:
Sufficient annual operating and maintenance costs to handle 154 percent
of the 1987 water production from State and Federal Gulf of Mexico
operations and
Sufficient capacity to handle an even larger volume of water.
Details are given in Appendix H.
Discussion of Platform Statistics
Assembling this platform inventory raised a number of issues as to how
offshore statistics are kept. The following factors should be carefully
considered in using and interpreting the platform and well data:
1. Reporting Date. For any statistic, there is a time delay in
reporting. For this inventory, it was necessary to use various counts from
2-19
-------
TABLE 2-9
STATE WATERS INVENTORY OF OFFSHORE PLATFORMS AND PRODUCING WELLS
State
Number of Number of
Production Producing
Platforms Wells
Comments
Alaska
15 platforms in Cook Inlet;
not in offshore category.
California
136
see Table 2-10.
Atlantic States
Gulf of Mexico
Alabama
Little or no current
development or
exploration activity
Gas fields in Mobile Bay are
not in offshore category.
Florida
Louisiana
Texas
800* 1,423*
113* 465*
No activity ongoing or
planned other than a
small number of
exploratory wells.
983 oil wells; 440
natural gas wells
415 natural gas wells;
approximately 50 oil wells
Uncertain how many are in offshore subcategory, coastal
subcategory, or are onshore wells with offshore completions.
Sources:
Alaska
Alabama
California
Florida
Louisiana
Texas
Douglas, Russ. Alaska Oil & Gas Conservation
Commission. Telephone Conversation, 3/88
McRory, Robert. Alabama Dep't of Conservation,
State Land Div. Telephone conversation, 3/88.
California Dep't of Conservation, Div. of Oil
and Gas. 1987. 72nd Annual Report of the State
Oil & Gas Supervisor. Sacramento.
Hachenberger, Ed. Florida Dep't of Natural
Resources, Division of State Lands. Telephone
Conversation, 3/88.
Bateman, Marlene. Louisiana Off. of Mineral
Resources, Mineral Board, Production Audit
Section. Telephone conversation, 3/88.
U.S. Department of Interior, Minerals Management
Service, as reported by OOC in a letter to EPA,
dated 8/13/1984.
Boone, Peter. Texas General Land Office.
Telephone conservation, March 1988.
2-20
-------
tabZJO.wk!
TABLE 2-10
PACIFIC OFFSHORE PLATFORMS
1987 DATA
Field
Platform
Name
Year
Installed
Water
Depth
(ft)
Number of
Producing Wells
in Field
FEDERAL
Beta
Beta
Beta
Carpinteria
Carpinteria
Carpinteria
Dos Cuadras
Dos Cuadras
Dos Cuadras
Dos Cuadras
Hueneme
Pitas Pt
Pt. Argue Uo
Pt. Argue Uo
Pt. Arguello
Pt. Pedernales
St. Clara
St. Clara
St. Clara
St. Ynez
Total Producing
Edith
Ellen
Eureka
Henry
Hogan
H ouch in
A
B
C
Hillhouse
Gina
Habitat
Harvest
Hermosa
Hidalgo
Irene
Gail
Gilda
Grace
Hondo
Wells
1983
1980
1984
1979
1967
1968
1968
1968
1977
1969
1980
1981
1985
1985
1987
1985
1987
1981
1979
1976
161
265
700
291
150
151
188
188
193
190
95
303
670
602
430
242
739
210
318
842
61
65
142
6
14
Not producing
Not producing
Not producing
11
60
21
380
STATE
Carpinteria Heidi
Carpinteria Hope
Hunt ing ton Emmy
Hunt ing ton Eva
Summer I and Hazel
Summer I and Hilda
S. El wood Holly
Total Producing Wells
1965
1964
1961
1964
1957
1960
1966
128
140
41
58
100
106
211
54
30
30
15
7
136
Notes: Platform Elly has no wells and is not included in this count.
Onshore wells with offshore completions, wells drilled from islands,
and wells drilled in inland bays are not included in the count.
Source: 73rd Annual Report of the State Oil & Gas Supervisor: 1987,
California Department of Conservation, 1988;
Oil & Gas Activities Affecting California's Coastal Zone,
A-Summary Report, California Coastal Conroisssion, December 1988.
2-21
-------
different sources. It was impossible to present the statistics with one
consistent reporting date. However, this introduces only a small error into
the counts because the number of platforms added between the earliest and
latest reporting date is estimated to be less than 1 percent of all platforms.
2. Old Shut-In Platforms. According to the U.S. Geological Survey (USGS,
Gulf of Mexico Summary Report 3, August 1982) approximately 5 percent of the
MMS file counts for the Gulf of Mexico platforms may be nonproducing
platforms. No adjustments to the inventory were made to account for shut-in
platforms.
3. Size of Platforms. Many of the platforms represented in the Texas and
Louisiana counts are old 1- to 6-well platforms while the California and
Alaska platforms are new 24- to 90-well platforms. Therefore, the platforms
in place vary a great deal in size and production capability. All production
platforms are included in the inventory, while separate statistics, when
available, are provided on the number of wells.
4. Platform Categories. The various statistical sources use different
procedures in counting offshore structures. Various types of structures such
as production structures may in some cases appear grouped in statistics as
"platforms." Only actively producing platforms are included in the counts.
5. Well Categories. Well types include producing wells, dry holes, shut-
in wells, injection wells, service wells and field drainage wells. In some
cases counts may group together several categories. Where possible, only
producing wells are included in the well counts.
6. New Technology. New technology, such as subsea manifolds that allow
centralized processing of crude from distant subsea wells, will complicate
platform and well inventories. Subsea completions involve installation of
wellhead equipment on the ocean floor. It is unlikely that these present a
significant problem for existing counts, since they currently represent a. very
small proportion of all production facilities. According to a 1982 tabulation
by Ocean Industry (Ocean Industry. July 1982), subsea production systems in
United States waters total less than 50. Therefore, no attempt was made to
adjust the platform count to include these structures.1
*A trend toward subsea completions would change the number of structures but
not the number of wells.
2-22
-------
7. New Platforms. In some cases (for example Alabama and California) new
platforms have been installed with proven wells but no crude is yet being
produced. These platforms have been included in the inventory.
233 Offshore Oil and Gas Production
Tables 2-11 and 2-12 show the quantity and market value of the oil and gas
produced from offshore platforms in recent years, and throughout the history
of the Federal outer continental shelf leasing program. The percentage of
U.S. oil production from offshore wells compared to total domestic oil
production has fluctuated over the last decade, while offshore natural gas
production has generally increased in relative importance. In 1975, offshore
oil production accounted for 16.2 percent of national production. During the
late 1970's and early 1980's when oil prices were high, more onshore
production took place and the offshore production dropped to 12-13 percent.
As low oil prices begin to shut in marginal onshore wells, offshore production
is regaining market share. In 1986, offshore production accounted for 14.4
percent of the national total. The percentage of domestic natural gas
produced offshore has climbed, from 20.7 percent in 1975 to a peak of 29.3
percent in 1984. Total offshore natural gas production has also fluctuated
between 4.2 trillion cubic feet (1975 production) to 5.5 trillion cubic feet
(1981 production). In 1986 over 457 million barrels of oil (14.4 percent of
U.S. production) and 4.6 billion million cubic feet of gas (27 percent of U.S.
production) came from offshore areas. Together the offshore oil and gas had a
market value of nearly $15 billion.
2.4 SUPPORT ACTIVITIES
The leasing, exploration, and development of offshore areas is controlled
primarily by large oil companies. These companies are described in detail in
Section Three below. While these major and independent oil companies (i.e.,
the operating companies) finance offshore development directly, a number of
contracting and service firms support the operators in all phases of offshore
activity (i.e., leasing, exploration, and development). Table 2-13 summarizes
the major support activities.
Before an oil company bids for a tract, and after being awarded a lease,
it must undertake geophysical investigations. Seismic investigations, which
2-23
-------
K)
I
TABLE 2-11
PRODUCTION AND VALUE OF U.S. CRUDE OIL AND CONDENSATE
ONSHORE - OFFSHORE
PRODUCTION
(THOUSANDS OF BARRELS)
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
ONSHORE
2,560,242
2,508,356
2,546,187
2,761,891
2,722,715
2,766,716
2,743,203
2,744,432
2,744,080
2,780,219
2,818,450
2,710,628
OFFSHORE
496,537
467,824
439,173
416,325
398,595
376,649
385,421
412,283
426,919
469,477
456,103
457,624
TOTAL
3,056
2,976
2,985
3,178
3,121
3,146
3,128
3,156
3,170
3,249
3,274
3,168
,779
,180
.360
.216
,310
,365
,624
,715
,999
,696
,553
,252
DOLLAR VALUE AT WELLHEAD
OFFSHORE (THOUSANDS OF DOLLARS)*
AS A
% OF
TOTAL
16.2
15.7
14.7
13.1
12.8
12.1
12.3
13.1
13.5
14.4
13.9
14.4
ONSHORE1
19,361.086
20.420,899
21,996,649
24,747,514
34,064,477
57,791.998
87,151,743
78,270,757
71,867,673
71,991,425
67,868,276
34,316,550
OFFSHORE*
3,754,
3,808,
3,794,
3.730,
4.986,
7,930,
12,244,
11,758,
11,180,
12,110,
10,982,
5,793,
973
641
073
310
855
018
641
641
818
707
960
520
TOTAL
23,116,059
24,229.540
25,790,722
28,477,824
39,051,332
65,722,016
99,396,384
90,029,512
83,048,491
84,102,132
78,851.236
40,110,070
WELLHEAD
PRICE PER
BARREL
(DOLLARS)
7.56
8.14
8.57
8.96
12.51
20.89
31.77
28.52
26.19
25.88
24.08
12.66
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
*Current dollars.
"Total dollar value distributed in proportion to percentages of production onshore and offshore.
Source: Basic Petroleum Data Book. Vol. VII, No. 1, January 1988, Section XI, Table 3a; Section VI,
Table 1.
-------
to
Ul
TABLE 2-12
PRODUCTION AND VALUE OF U.S. NATURAL GAS
ONSHORE - OFFSHORE
PRODUCTION
(MILLIONS OF CUBIC FEET)
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
ONSHORE
15,943,934
15,637,042
15,528,536
14,839,994
15,026,356
14,996,551
14,631,239
13,151,448
12,170,095
12,888,354
12,566,758
12,202,345
4
4
4
5
5
5
5
5
4
5
OFFSHORE
,164,727
,315,396
,496,927
,134,039
,444,904
.382.236
.546,462
,368,227
,486,905
,341,284
4,798,242
4,588.565"
TOTAL
20,108
19,952
20,025
19,974
20,471
20,378
20,177
18,519
16,657
18,229
17,198
16,790
,661
,438
,463
,033
,260
,787
,701
,675
,000
.638
.000
.910
OFF-
SHORE
AS A
% OF
TOTAL
20.7
21.6
22.5
25.7
26.6
26.4
27.5
29.0
26.9
29.3
27.9
27.3
DOLLAR VALUE AT WELLHEAD
(THOUSANDS OF DOLLARS)*
ONSHORE1
7,092,450
9,069,032
12,272,078
13,430,116
17,699,890
23,586,880
28,969,884
32,308,618
31,865,966
33,896,371
31,123,393
23,672,549
OFFSHORE1
1,852,612
2,502,744
3,553,876
4,616,384
6,413,744
8,465,302
10,981,964
13,188,147
11,748,403
14,047,577
12,043,587
8,901,816
TOTAL
8,945,062
11,571,776
15,825,954
18,076,500
24,113,634
32,052,182
39,951,848
45,496,765
43,614,369
47,943,948
43,166,980
32,574,365
WELLHEAD
PRICE
($/Mcf) YEAR
0.45
0.58
0.79
0.91
1.18
1.59
1.98
2.46
2.59
2.66
2.51
1.94
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
*Current dollars.
aTotal dollar value distributed in proportion to percentages of production onshore and offshore.
bGross natural gas withdrawals offshore, from Natural Gas Annual 1986
Sources: Basic Petroleum Data Book. Vol. VIII, No. 1, January 1988, Section XI, Table 6a; Natural
Gas Annual 1986. October 1987, Tables, 2, 3, and 4.
-------
TABLE 2-13
SUPPORT ACTIVITIES
INDUSTRY CATEGORY
SUPPORT ACTIVITY
Geophysical
Contractor
Drilling
Contractor
Well Logging
Contractor
Well Servicing
Contractor
Well Cementing
Contractor
Drilling Mud
Contractor
Chemical Supplier
Equipment Supplier
Marine Construction
Firm
Transportation
Contractor
Conducts seismic investigations prior to drilling
to determine probability and location of
hydrocarbons.
Operates rig and provides crew to drill
exploration, delineation, and/or development wells.
Provides and runs logging devices to determine
reservoir characteristics.
Provides services necessary to drill and maintain a
well such as well servicing, workovers, pulling
casing and tubing, and acidizing.
Provides equipment and crew to cement wells.
Provides drilling fluid formulations used to cool
and lubricate drillbit, remove cuttings from the
wellbore, and prevent the flow of fluids into the
wellbore while drilling.
Provides special chemicals to formulate drilling
fluids, cements, acids, and other specialized
formulations needed in the industry.
Supplies specialized equipment used in drilling,
production, and environmental control.
Constructs major offshore structures such as
production platforms and pipelines.
Provides transportation services to and from rigs.
Source: ERG.
2-26
-------
analyze patterns of subsea geologic structures to determine their potential
for oil and gas, account for over 90 percent of geophysical investigations.
Geophysical contractors usually perform these investigations under contract to
the oil company.
After an operating company has analyzed the results of its geophysical
investigations, and has decided where to drill an exploration well or wells, a
drilling contractor is selected. Ninety-eight percent of all exploratory and
development wells are contracted out to independent drilling contractors.
Only about 1 percent of all drilling rigs are owned by operating companies.
World- wide there are 105 companies that provide offshore drilling services.
Of these 105 companies, 86 are located in the United States. The annual level
of activity of drilling contractors is shown in Table 2-14.
During well drilling, well completion prior to production, and well
workover during production, other specialized contractors (i.e., servicing
companies) are often required. These contractors provide a variety of
services including well surveying, well logging, and pulling casings and
tubes. Contractors are also needed to cement wells, perforate well casings,
acidize and chemically treat wells, as well as to clean out, bail out, and
swab wells. Other contractors provide transportation services to and from
offshore rigs and platforms.
Among the firms which supply specialized services during offshore drilling
are the drilling fluid contractors. These firms supply the chemicals used to
lubricate and cool the drillbit during the drilling operations. Unique
chemical formulations are required for the various phases of well drilling and
a specialized industry has evolved to meet this demand. Some drilling fluid
contractors are integrated backwards into production of component raw
materials. For example, M-I Drilling Fluids and NL Industries are involved in
barite mining as well as the supply of oilfield chemicals. Barite is a major
component of drilling fluids.
Another group of companies that support the drilling operation are
equipment suppliers. These companies supply specialized equipment used in
drilling operation such as shale shakers (i.e., machines that separate
drilling cuttings from the drilling fluids). Some of the equipment suppliers
are also involved in the supply of drilling fluids.
If an economic quantity of oil or gas is discovered during exploratory
drilling, a field development plan is formulated and a marine construction
2-27
-------
TABLE 2-14
OFFSHORE DRILLING ACTIVITY. 1973-I985*
YEAR
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
NUMBER
OF WELLS
DRILLED
888
830
1,028
1,028
1,217
1,197
1,260
1,272
1,476
1,464
1,270
1,421
1.247
898
'Includes exploration, delineation, and
Source :
FOOTAGE
DRILLED1
8,354,069
7,402,256
9,783,176
9,817,244
11,519,851
11,756,744
12,392,501
12,503,275
14,422,470
14,537,052
12,831,906
14,259,153
12,815,948
9,407,734
development drilling,
AVERAGE
DEPTH
PER WELL
(FT.)
9,408
8,918
' 9,517
9,550
9,466
9,821
9,835
9,829
771
9,930
10,104
10,035
10,277
10,476
American Petroleum Institute, Basic Petroleum Data Book. January
1988. Section III. Table 10: 1986 Joint Association Survey on
Drilling Costs. November 1987, Table 1.
2-28
-------
firm is hired to build a production system. The marine construction industry
includes firms which build platforms, build and lay submarine pipelines, build
tankers to transport oil from platforms to shore, manufacture other well and
platform equipment, and build offshore service and supply vessels.
In summary, the ownership of the leased offshore mineral interests, and
thus the oil produced in leased areas, is entirely held by the operating
companies. The operating companies are dominated by a small group of major
firms, but the entire offshore oil and gas industry is diverse. The large
capital investment needed to explore leased tracts and develop offshore
reservoirs is primarily provided by major oil companies, which in turn are
supported by a large and independent service and manufacturing industry.
2.5 INDUSTRY DOWNTURN AND RECOVERY 1986-1988
The low oil prices of 1986 led to a downturn in the offshore oil and gas
industry. The downturn is particularly evident in terms of leasing and
exploration activities as well as in revenues. Table 2-15 lists the domestic
first purchase prices for crude oil (also called "wellhead prices") from 1980
to November 1987. The nadir was reached in July 1986 when a barrel of oil
sold for only $9.25, less than 30 percent of the 1981 price. Although oil
prices now appear to be stabilizing around $18 to $20 a barrel, the Gulf of
Mexico appears to be the only region that has begun to respond to the improved
market conditions (Wall Street Journal. 18 June 1987, 6, and 1 September 1987,
44).
2.5.1 Federal Offshore Leasing
Lease Sales - Past
Two measures of industry activity are the number of tracts that receive
bids and the average bonus bid per tract in Federal lease sales. Table 2-16
summarizes OCS leasing activity from 1980 to 1987. The average bonus bid per
tract steadily declined during this period. The number and percentage of
tracts receiving bids also declined. In 1980, more than half the tracts
offered received bids. Beginning in 1983, substantially larger numbers of
tracts were offered and, although the number of tracts receiving bids more
than tripled from the 1982 figure, only 6.1 percent of the offered tracts
2-29
-------
TABLE 2-15
CRUDE OIL PRICES. 1980 TO NOVEMBER 1987
YEAR
MONTH
1980 Average
1981 Average
1982 Average
1983 Average
1984 Average
1985 Average
1986
January
February
March
April
May
June
July
August
September
October
November
December
1986 Average
1987
January
February
March
April
May
June
July
August
September
October
November
DOMESTIC FIRST
PURCHASE PRICES*
21.59
31.77
28.52
26.19
25.88
24.09
23.12
17.65
12.62
10.68
10.75
10.68
9.25
9.77
11.09
11.00
11.05
11.73
12.51
13.89
14.50
14.53
14.95
15.29
15.95
16.88
17.06
16.25
15.95
15.45
*Current dollars.
Source: Petroleum Marketing Monthly. November 1987. U.S. Department of
Energy, Energy Information Agency, DOE/EIA-0380(87/11), Feb. 1988,
Table 1.
2-30
-------
TABLE 2-16
PCS LEASING STATISTICS. 1980- 1987
YEAR
1980
1981
1982
1983
1984
1985
1986
APRIL
1987
AUGUST
1987
NO. OF
TRACTS
OFFERED
1
1
21
27
15
10
5
5
483
,398.
,410
,689
,984
,754
,724
,881
,045
NO. OF
TRACTS
BID ON
258
520
404
1,325
1,530
736
155
313
367
NO. OF
TRACTS
SOLD
218
430
357
1,251
1,400
642
142
293
--
AVERAGE BONUS
BID PER TRACT
(millions of $)*
19
15
11
4
2
2
1
0
.3
.4
.2
.6
.9
.3
.3
.9
*Current dollars.
Source: "Federal Offshore Statistics: 1985," U.S. Department of the
Interior, Minerals Management Service, MMS 87-0008, from Tables 2 and
3; "Outer Continental Shelf Statistical Summary," U.S. Department of
the Interior, Minerals Management Service, MMS 86-0122; Pat Bryars,
Minerals Management Service, telephone communication, September,
1987.
2-31
-------
received bids. In 1986, only 155 tracts received bids -- this is only 1.4
percent of the tracts offered and is the lowest number seen during this
period. As fewer tracts are leased, the area likely to be explored will
decline. In time, production and reserves also will fall due to a lower
number of discoveries.
Two leasing sales have been held in 1987, both in the Gulf of Mexico.
More than 300 tracts received bids in each of the April and August sales; that
is, each sale had double the number of tracts bid upon than in all of 1986.
Part of the increase in activity may be due to the Minerals Management Service
decision to reduce minimum bid requirements from $150/acre to $25/acre. More
than 77 percent of the high bids in the August sale amounted to less than
$150/acre. An industry journal, however, has stated that the revived interest
in Gulf leasing is due more to the stabilization of crude oil prices at levels
exceeding $18/bbl (Oil and Gas Journal. 17 August 1987, 24-25). With oil
prices double what they were in 1986, companies are now generating more
capital for new investments.
Lease Sales - Future
The final 5-year Leasing Plan for 1988 to 1992 was announced in April 1987
(see Table 2-17). The plan provides insight on future levels of offshore
leasing and exploration activity. The plan projects that annual sales will
continue in the Central and Western Gulf of Mexico. As the 1987 sales
indicate, interest in this productive and well-studied area is reviving.
Sales in other OCS areas will occur only every three years. Prior to the
new plan, lease sales in these areas were held every two years. Of the 37
sales planned for 1988-1992, nearly one-third are frontier sales to be held
only if there is sufficient industry interest (Oil and Gas Journal. 4 May
1987, 26). Lack of interest and other factors have led to several sale
cancellations in recent years (Federal Offshore Statistics: 1985. Mineral
Management Service, MMS 87-0008, Table 1). Six sales scheduled for the
Atlantic have been canceled since 1983. The absence of commercially
productive discoveries in that region after eight exploratory wells were
drilled reduces the incentive to explore further, particularly in a period of
low oil prices (Boston Globe. 28 April 1987). Five sales in Alaska have been
canceled and one sale enjoined since 1984. The 5-year plan also defers about
70 percent of all the acreage off California. Given the intense resistance to
further development off California, the step was taken to end the uncertainty
2-32
-------
TABLE 2-17
FIVE-YEAR PCS LEASING PLAN
SALE NO.
97
113
109
115
107
116
91
96
118
122
95
SU1
121*
120*
101*
123
117
125
114*
SU2
108*
119
124
131
126
135
130*
SU3
137
129*
134*
128
139
132*
133*
138
140*
AREA
Beaufort Sea
Central Gulf of Mexico
Chukchi Sea
Western Gulf of Mexico
Navarin Basin
Eastern Gulf of Mexico
Northern California
North Atlantic
Central Gulf of Mexico
Western Gulf of Mexico
Southern California
Supplemental
Mid-Atlantic
Norton Basin
St. George Basin
Central Gulf of Mexico
North Aleutian Basin
Western Gulf of Mexico
Gulf Alaska-Cook Inlet
Supplemental
South Atlantic
Central California
Beaufort Sea
Central Gulf of Mexico
Chukchi Sea
Western Gulf of Mexico
Navarin Basin
Supplemental
Eastern Gulf of Mexico
Shumagin
North Atlantic
Northern California
Central Gulf of Mexico
Washington- Oregon
Hope Basin
Southern California
Straits of Florida
YEAR MONTH
1988 January
March
May
August
October
November
1989 February
February
March
Augus t
September
September
October
December
1990 February
March
May
August
September
September
October
November
1991 February
March
May
Augus t
September
September
November
1992 January
February
February
March
April
May
June
June
*Frontier sale to be held only if enough industry interest is indicated
in the calls for information and nominations.
Source: Oil and Gas Journal. May 4, 1987, 26.
2-33
-------
associated with California lease sales (Oil and Gas Journal. 4 May 1987, 26).
Leasing activity in the non-Gulf areas, then, will be far less than in the
Gulf.
2.5.2 Exploration
The average number of active rigs is one measure of exploration activity
(see Table 2-18 and Figure 2-1). In 1986, the industry slumped to less than
half its 1985 levels and the decline continued to worsen in the first half of
1987. The West Coast had no more than two mobile rigs active at any time
throughout all of 1986 (Offshore Yearbook. 1987 edition, Pennwell Publishing
Company, 86-97).
This severe slump led to "stacking" or placing in storage dozens of
offshore drilling rigs. This may prove a problem in future Gulf exploration.
Table 2-19 summarizes the number of leases in the Gulf of Mexico that will
expire in 1988 and 1989. Over 1,000 undrilled leases will expire during this
two-year period. OCS leases are issued for an initial 5-year term and are
extended for as long as there is production from that lease. If no drilling
is done by the lessee during the initial 5-year period, the lessee loses the
lease unless an approved "suspension of operations or production" is obtained
(Managing Oil and Gas Operations on the Outer Continental Shelf. Minerals
Management Service, September 1986). Many companies may chose to drill rather
than lose the lease. If this occurs, a logistical problem may develop in
reactivating a sufficient number of rigs to complete drilling on all these
leases. The Minerals Management Service has issued a warning that a shortage
of drilling rigs will not be considered as a valid reason to extend the terms
of any offshore lease (Wall Street Journal. 4 August 1987, 6).
An upturn in drilling activity in the Gulf began in the second half of
1987 (see Figure 2-1). During February and March, 1988, the number of rigs
under contract ranged from 146 to 154 for a utilization rate between 61 and 66
percent. (Offshore Data Services, weekly newsletters). The number of rigs
working, then, has recovered to levels just prior to the 1986 slump. Given
the number of undrilled leases that will expire in the next two years, the
demand for offshore drilling services looks likely to continue.
2-34
-------
TABLE 2-18
ANNUAL AVERAGE NUMBER OF
ACTIVE OFFSHORE DRILLING RIGS
AVERAGE NUMBER
YEAR OF RIGS DRILLING
1979 122
1980 138
1981 151
1982 169
1983 139
1984 200
1985 190
1986 94
1987 (Jan-June) 76
Source: Telephone communication between Maureen F. Kaplan, Eastern Research
Group, Inc., and T. Cornetius, Electronic Rig Stats, Houston, Texas,
27 July 1987.
2-35
-------
1
f"H
Source: Offshore Rig Newsletter, Offshore D«U Services, Inc., Houston, TX.
Figure 2-1. Offshore Mobile Rig Utilization Data, Gulf of Mexico, 1983-1988.
Source: Drilling Contractor. December 1987/January 1988.
2-36
-------
TABLE 2-19
GULF OF MEXICO LEASES DUE TO EXPIRE
1988.1989
Year of Exploration
1988
Water Depth
(feet)
up to 150
151 to 300
301 to 1,300
1,301 to 3,000
over 3,000
TOTAL
Drilled
219
101
74
29
0
423
Undrilled
228
81
129
51
0
489
1989
Drilled
61
30
42
24
0
157
Undrilled
173
105
151
132
0
561
Source: Drilling Contractor, 1988.
2-37
-------
2.53 Production
Offshore projects that were begun in 1981-1985, when oil sold for $24-
$32/bbl, would only be in the early years of production during 1986 when oil
prices fell to less than $10/bbl. It is not surprising, then, that offshore
production actually rose by a small amount in 1986 (see Table 2-12). The
decline in drilling activity in 1986 will be reflected as a production decline
in 1987 and beyond. Onshore oil production in 1986 fell 4 percent as stripper
wells were shut-in rather than reworked. Since offshore production remained
stable while onshore production declined, offshore production formed a larger
proportion (14.4 percent) of total U.S. production than in previous years.
Revenues from offshore production, on the other hand, were nearly half of 1985
values due to declining prices.
Offshore petroleum production may continue to increase as a proportion of
national production. An article in the Wall Street Journal indicates that oil
industry executives believe that only Alaska and the offshore region hold
promise of potential giant fields within the U.S. ("Major Oil Firms Intend to
Boost Spending in '88," WSJ. November 10, 1987, 4).
2-38
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SECTION THREE
FINANCIAL PROFILE
The expenditures required to comply with the effluent limitations
guidelines and new source performance standards described in Section One will
be financed by offshore developers and their investors. Before estimating the
impact of the effluent limitation guidelines and standards on the developers,
it is useful to evaluate their past and current financial condition. Sections
3.1 through 3.5 provide information on the financial performance of the oil
and gas industry.
Section 3.1 identifies and describes the characteristics of companies
participating in different phases of offshore development. Section 3.2
reviews the market and financial trends that affect these companies. Section
3.3 presents a ratio analysis of industry segments to identify how key
financial ratios have changed over the last 6 years and what this indicates
for the future financial condition of those segments. Section 3.4 reviews the
principal financial statements of "typical" companies involved in offshore
production. Section 3.5 analyzes the industry's future financial prospects.
The industry financial ratios (Section 3.3) and representative financial
statements (Sections 3.4 and 3.5) are used as the basis for the economic
impact analysis presented in Section Seven.
3.1 CORPORATE PARTICIPANTS IN OFFSHORE DEVELOPMENT
3.1.1 Categorization of Participants
Offshore petroleum producers can be divided into two basic categories.
The first consists of the major integrated oil companies. These companies are
characterized by a high degree of vertical integration, i.e., their activities
encompass both "upstream" activities -- oil exploration, development, and
production -- and "downstream" activities -- transportation, refining, and
marketing. The second category of offshore producers are the large
independents. The independents are engaged primarily in exploration,
development, and production of oil and gas and are not heavily involved in
"downstream" activities. Some independents are strictly producers of oil and
3-1
-------
gas, while others maintain some service operations, such as contract drilling
and pipeline operation. Table 3-1 provides a list of the major domestic
integrated and independent oil and gas producing companies.
Producing companies vary in their range of products. In the early 1980's,
due to cash surpluses and diminishing oil reserves, many oil companies, and
particularly the majors, have diversified into other areas such as mining and
development of alternative (nonpetroleum) energy sources. The major oil
companies are more oriented toward oil production, while the independents, by
contrast, are more oriented toward the production of natural gas.
The major integrated oil companies are generally larger than the
independents. Due to the number of mergers and acquisitions in recent years,
independents do not appear at all in the top ten companies ranked by domestic
oil production, domestic gas production, or net income.1 As a group, the
majors generally produce more oil and gas, earn significantly more revenue and
income, have considerably larger assets, and have greater financial resources
than the independents.
In addition to the majors and independents, a third group of companies
provides a variety of specialized services to the offshore oil and gas
developers. These firms construct, own, and operate offshore mobile drilling
rigs; fabricate specialized hardware for offshore projects; design, construct,
and install offshore platforms; provide geophysical, drilling mud, and well
logging services; build and install pipelines to transport oil and gas from -
platforms to onshore terminals; and own and operate boat and helicopter fleets
which provide support services to offshore drilling rigs and platforms. Table
3-2 lists some of the larger participants involved in these support
activities.
While all of the companies involved in offshore oil and gas development
could be affected by BAT and NSPS regulations, it is the production companies
that are directly responsible for having BAT and NSPS systems in operation and
they therefore will bear the costs of the regulation. For this reason, the
production companies will be the focus of the industry characterization and
economic impact assessment. If the costs of BAT or NSPS regulation cause
development companies to curtail operations, the companies providing
specialized services will experience secondary effects (i.e., a decrease in
demand for their services).
'Oil and Gas Journal. 8 September 1986, 55-95,
3-2
-------
TABLE 3-1
U.S. OIL COMPANIES ENGAGED IN OFFSHORE
EXPLORATION. DEVELOPMENT AND PRODUCTION
MAJOR U.S. INTEGRATED
OIL COMPANIES
INDEPENDENT U.S. OIL COMPANIES"
Amerada Hess
American Petrofina
Atlantic Richfield
Conoco (subsidiary of DuPont)
Diamond Shamrock
Exxon
Kerr-McGee
Marathon Oil (subsidiary of
U.S. Steel)
Mobil Oil
Murphy Oil
Occidental Petroleum (acquired
Cities Service Co.)
Phillips Petroleum
Shell Oil (subsidiary of
Royal Dutch Petroleum)
Standard Oil of California
Standard Oil of Indiana
Standard Oil of Ohio
Sun Company
Tenneco
Texaco, Inc.
Union Oil Company
Apache Corp.
Crystal
Felmont Oil Co.
Inexco Oil Co. (acquired
by Louisiana Land
and Exploration)
Louisiana Land and
Exploration
Mesa Petroleum
Noble Affiliates, Inc.
Patrick Petroleum
Pogo Producing
Sabine Corporation
Southland Royalty Company
Mobil
Wilshire Oil
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys,
November 4, 1982; "OGJ 400," Oil and Gas Journal. September 8, 1986.
'A sample of the independent companies which are active offshore.
3-3
-------
TABLE 3-2
SAMPLE OF COMPANIES PROVIDING
SUPPORT SERVICES TO OFFSHORE DEVELOPERS IN 1986
Contract Drilling Services for Offshore Mobile Rigs
Diamond M (subsidiary of Kaneb Services)
Global Marine
Ocean Drilling and Exploration
Penrod Drilling
Pool Offshore (subsidary of ENSERCH Corp.)
Reading and Bates
Rowan Companies
Sedco-Forex (subsidiary of Schlumberger)
Sonat Offshore
Transworld Drilling (subsidiary of Kerr-McGee)
Western Oceanic (Western Co. of North America)
Zapata Corp.
Construction of Offshore Rigs
Bethlehem Steel
CBI Industries
Levingston Shipbuilding
Marathon Manufacturing (subsidiary of Penn Central)
Speciality Hardware Suppliers
Cameron Iron Works
Canocean Resources (subsidiary of Husky Oil)
The Hydril Company
Hughes Tool Co.
NL Industries
VETCO Inc. (subsidiary of Combustion Engineering)
Design. Construction, and Installation of Offshore Platforms
Brown and Root (a division of Halliburton)
CBI Industries
McDermott Inc.
Raymond International
(Cont.)
3-4
-------
TABLE 3-2 (CONT.)
Drilling Mud Contractors
Baker International
Dresser
Halliburton
Hughes Tool
Unichem
Well Coring Services
Core Laboratories Inc.
Dowd Co.
Well Logging Services
Gearhart Industries Inc.
Schlumberger
Offshore Pipeline Installation
Brown and Root (a division of Halliburton)
HcDennott Inc.
Service Vessel Suppliers
Jackson Marine (subsidiary of Halliburton)
Newpark Resources
Offshore Logistics
Tidewater Marine, Inc.
Zapata Corp.
Contract Diving Services
Oceaneering International
Source: "Oil-Gas Drilling and Services," Basic Analysis, Standard and Poor's
Industry Surveys, March 20, 1986; "Offshore 1986: Worldwide Offshore
Contractors and Equipment Directory," Pennwell Directories, April,
1986.
3-5
-------
3.1.2 Industrial Concentration in Offshore Activities
Company concentration ratios were calculated to determine the degree to
which the major integrated companies dominate offshore activities. Table 3-3
presents concentration percentages for offshore domestic operations. The data
show that (a) there is a greater degree of concentration for petroleum
production offshore than for offshore gas production; (b) the industry
concentration ratios for both offshore oil and gas have decreased since 1973
for the 8 and 16 largest company segments; (c) concentration of offshore
exploration and development expenditures have tended to vary over the same
period; and (d) until 1980, there was a greater concentration in offshore
production of oil and gas for the 8 and 16 largest companies than for the
country as a whole. These trends indicate that more companies have entered
into the oil business since 1973 and particularly into offshore development
starting in 1980.
There are four principal areas of offshore oil activity in the United
States: Alaska, California, the Gulf of Mexico, and the Atlantic Ocean. The
majors dominate operations in all four areas, although much less so in the
Gulf. This pattern occurs because the average water depth off the coasts of
Alaska and California and in the Atlantic is greater, the areas are less
defined geologically, and the operating climates are generally harsher. As a
result, development risks are high and few independents have the resources to
put at stake in these areas. In contrast, much of the area off the Gulf
Coast, especially the state waters, is shallow and has been well explored.
A review of offshore leases announced by the MMS indicates that over 90
percent of all Federal offshore tracts in Alaska and California, 100 percent
of the lease tracts in the Atlantic, 85 percent of state lease tracts off the
coast of Alaska, and approximately 90 percent of the state tracts off the
California coast have been leased by the majors. In contrast, only 75 percent
of the Federal leases off the less risky Gulf coasts of Louisiana and Texas
are owned by the majors.
3-6
-------
Ul
I
-J
TABLE 3-3
OIL INDUSTRY CONCENTRATION RATIOS; OFFSHORE ACTIVITIES AND U.S. ACTIVITIES
8
LARGEST1
COMPANIES
1973 1976
Sales Volume
Crude Petroleum & Condensate
Offshore (%) 68.9 57. 4
Total Donestic (« 53.5 50.9
Natural Ca«
Offshore («) 50.9 48.0
Total Domestic (%) 48.9 44.5
Lease Revenues
Crude Petroleum & Condensate
Offshore () 68.9 54.2
Total Domestic (%) 54.4 47.1
Natural Gas
Offshore (%) 49.7 46.1
Total Domestic («) 47.9 44.0
1978
52.1
47.6
52.9
44.8
55.2
47.1
46.8
41.8
1980
48.4
53.5
42.0
36.9
46.8
50.5
34.5
34.9
1981
46.8
53.2
41.5
36.3
49.4
51.9
35.8
32.8
1973
86.0
72.8
72.6
65.5
85. 4
73.2
71.8
64.5'
16 LARGEST*
COMPANIES
1976
83.3
70.7
76.2
63.6
77.7
64.6
72.1
60.4
1978
72.6
70.6
73.8
60.5
73.2
66.2
67.1
56.0
1980
69.0
72.2
69.3
58.5
66.8
69.3
62.0
53.5
1981
68.5
71.8
66.9
56.3
71.2
71.4
61.8
50.8
1973
96.3
83.7
93.9
81.8
96.3
84.2
93.8
81.4
50
LARGEST*
COMPANIES
1976
96.3
82.1
89.6
79.2
92.2
78.4
88.3
77.0
1978
94.6
84.3
92.2
78.6
93.9
78.5
90.5
75.6
1980
93.7
85.1
90.1
79.4
93.7
83.4
88.3
77.4
1981
94.5
84.3
90.2
77.9
95.0
84.6
88.6
74.6
1973
99.2
89.9
99.0
90.2
99.3
90.5
99.1
90.4
200 LARGEST*
COMPANIES
1976
99.4
89.8
99.2
89.2
98.9
87.8
98.7
87.8
1978
98.8
90.1
98.9
89.5
98.4
88.7
98.3
88.3
1980
99.2
91.2
98.9
91.8
99.4
90.6
99.0
91.8
1981
98.9
90.9
99.1
90.7
99.6
91.5
99.1
89.8
Expenditures (Capitalized and Expensed)
Exploration
Offshore (%) 46.3 54.7
Total Domestic (%) 40.1 39.3
Development
Offshore (%) 46.9 49.6
Total Domestic (%) 40.8 41.0
45.1
34.3
43.2
36.8
41.4
37.0
33.6
30.3
48.7
35.6
44.8
33.7
66.0
56.2
62.7
54.8
70.7
52.9
70.1
54.5
63.3
46.6
59.8
52.9
66.7
56.4
60.9
59.4
72.0
51.5
62.4
48.3
91.7
78.1
91.3
73.1
89.2
71.1
88.3
77.4
83.7
65.9
85.8
73.9
89.2
75.6
87.1
76.4
90.1
70.2
89.5
66.1
93.9
88.4
97.1
85.0
96.3
83.9
97.1
68.7
97.0
84.1
97.2
88.3
99.4
90.5
99.3
90.3
99.4
87.3
98.7
82.0
Source: Annual surveys of Oil and Gas, Bureau of the Census. The data describe the percentage of Industry totals represented by each
designated group of the largest firms. These surveys did not continue past 1982. The API Survey on Oil and Gas Expenditures does not
contain Information categorized by both onshore/offshore operations and company size.
'Companies are ranked by total lease revenues.
-------
3.2 MARKET AND FINANCIAL TRENDS
3.2.1 Market Environment 1975-1986
The environment in which oil companies operate and upon which they base
their future plans has changed radically over the last several years.
Throughout the 1970's, the world price of oil climbed steadily, beginning with
the Arab oil embargo of 1973-1974 and culminating with a large rise in prices
in 1979 and 1980. The prevailing industry view in the late 1970's was that oil
was relatively price inelastic, i.e., continually rising oil prices would
result in little decline in demand and thus generate incrementally higher oil
revenues. The industry therefore invested heavily during the 1970's,
committing record amounts of capital for exploration and development.
Demand stayed strong throughout most of the 1970's despite rising prices.
Demand turned down in 1979, however, and dropped sharply over the next 4
years. Demand rebounded slightly in 1984 and remained level in 1985.
Domestic demand for oil fell 19 percent between 1978 and 1981 (Table 3-4),
while the average oil wellhead price rose 120 percent in real terms over the
same period. Prices peaked in constant dollars in 1981 at an increase of 172
percent over 1978 prices. In 1982, as demand continued to fall, prices also
began to slip. The pace of the decline has increased in 1985 and 1986. In
1986, prices fell to levels as low as $12 per barrel before rebounding to
approximately $19 at year end. As shown in Table 3-5, demand for natural gas
fluctuated during the mid-1970's to the mid-1980's, although the overall trend
showed a reduction in demand. During this period, natural gas prices have
generally increased, with large jumps in the 1979-1982 period.
There were a number of reasons for the decline in oil prices that began in
1982; a global recession, new supplies brought on-stream in response to higher
price expectations, user conservation, and fuel switching all served to
slacken demand. The net effect was that the average wellhead price fell 15
percent in real terms from 1981 to 1982. During this time the OPEC oil cartel
implemented a variety of supply control strategies to keep the price from
falling further. A price war in 1986, engineered by Saudi Arabia in a sharp
change in strategy, has driven prices lower still. The falling demand and
falling prices quickly affected the industry's spending plans, and had a
significant impact on the financial performance and cash flow projections of
oil and gas companies. These effects are discussed in more detail below.
3-8
-------
TABLE 3-4
TOTAL U.S. PETROLEUM DEMAND.
U.S. AVERAGE CRUDE OIL WELLHEAD PRICE. 1975-1986
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
DOMESTIC
CONSUMPTION
(MILLIONS
BARRELS/DAY)
16.32
17.46
18.43
18.85
18.52
17.06
16.06
15.30
15.23
15.73
15.73
16.28
AVERAGE
CURRENT.
DOLLARS'3
7.67
8.19
8.57
9.00
12.64
21.59
31.77
28.52
26.19
25.88
24.09
12.51
WELLHEAD PRICE
CONSTANT.
DOLLARS* >b
12.63
12.82
12.68
12.39
16.02
25.03
33.66
28.52
27.19
27.98
26.91
14.27
Source: Petroleum Marketing Annual 1986. U.S. Department of Energy, Energy
Information Administration, DOE/EIA-0487(86)/1; Basic Petroleum Data
Book. Vol. VIII, No. 1, January 1988, Section VII, Table 2; Economic
Report of the President 1988. Table B3.
"Constant 1982 prices calculated using GNP implicit price deflators,
1982 - 100.
fy.S. wellhead prices in the 1970's reflect domestic price controls.
3-9
-------
TABLE 3-5
TOTAL U.S. NATURAL GAS DEMAND.
U.S. AVERAGE NATURAL GAS WELLHEAD PRICE. 1975-1986
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
DOMESTIC
CONSUMPTION
(TRILLION
CUBIC FEET)
20.4
20.8
19.52
19.63
20.24
19.88
19.40
18.00
16.83
17.95
17.28
16.22
AVERAGE
CURRENT
DOLLARS
0.45
0.58
0.79
0.91
1.18
1.59
1.98
2.46
2.59
2.66
2.51
1.94
WELLHEAD PRICE
CONSTANT
DOLLARS3
0.74
0.91
1.17
1.25
1.50
1.84
2.10
2.46
2.69
2.88
2.80
2.21
Source: Basic Petroleum Data Book. Vol. VIII, No. 1, January 1988, Section
XIII, Table 5; Natural Gas Annual 1985. U.S. Department of Energy
Information Administration, DOE/EIA-0131(85), Tables 6 and 26;
Economic Report of the President. 1986. Table B3; Natural Gas Annual
1986. Table 1.
aConstant 1982 prices calculated using GNP implicit price deflators,
1982 - 100.
3-10
-------
3.2.2 Trends in Capital and Exploration Expenditures
Capital and exploration expenditures in the oil and gas industry have
quintupled over the last decade (in nominal dollars). Adjusted for inflation,
the real level of expenditures has more than doubled.
Table 3-6 shows capital and exploration expenditures by the domestic oil
and gas industry for the period 1974-1984. Changes in spending patterns
evident in Table 3-6 are closely correlated with oil price movements (see
Table 3-4). Capital and exploration spending rose when prices rose sharply
between 1979 and 1981. Capital and exploration expenditures in real terms
peaked in 1982. The rate of spending fell thereafter as decreased demand and
lower prices forced oil companies to cut back on investment programs. In
1986, exploration and development activities fell still further due to the
precipitous price decline.
Data on offshore wells drilled, offshore success rates, and offshore
drilling costs are shown in Table 3-7. From 1975 to 1986 the average cost per
well and per foot increased by a factor of three. Drilling costs tend to
correlate with oil price movements with a one-year lag. Drilling costs per
foot peaked in 1982 (oil prices in 1981) at a factor of 3.5 from 1975 cost.
Drilling costs in 1986 declined measurably from 1985 costs, reflecting the
continuing rapid decline in oil prices.
3.23 Trends in Offshore Production Reserves
The percentage of U.S. oil production from offshore wells compared to
total domestic oil production has generally declined over the last decade,
while offshore natural gas production has increased in relative importance.
Table 3-8 presents data on the relative importance of offshore oil and gas to
total domestic production in terms of revenue. In the ten years ending in
1984, total offshore revenues (in current dollars) grew by a factor of 4.6, to
$26.1 billion. These revenues represent approximately one-sixth of total
domestic revenues from oil and gas production over that period. The 1984
dollar value of offshore gas production was approximately 29 percent of the
value of total gas production, up from 21 percent in 1975. Offshore oil
production in 1985 constituted approximately 14 percent of the value of total
domestic oil production, down from 16 percent in 1975.
3-11
-------
TABLE 3-6
TRENDS IN CAPITAL AND EXPLORATION EXPENDITURES
(UNITED STATES, 1974-1984)
1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984
LJ
I
Total Capital
and Exploration
Expenditures
($ billion)
Increase Over
Previous Year
17.755 18.920 23.460 24.045 26.450 34.800 46.750 68.700 68.050 49.850 49.925
Implicit Price 54.0
Deflator for GNP
(1982-100)
Total Capital
Exploration
Expenditures in
Constant 1982
Dollars
($ billion)
6.6 24.0 2.5 10.0 31.6 34.3 47.0 -0.9 -26.7
0.2
59.3 63.1 67.3 72.2 78.6 85.7 94.0 100.0 103.8 108.1
9.588 11.220 14.803 16.182 19.097 27.353 40.065 64.578 68.050 51.744 53.969
Source: "1984 Capital Investments of the World Petroleum Industry," Chase Manhattan Bank, September 1985;
Economic Report of the President. Council of Economic Advisors, February 1986, Table B-3.
-------
TABLE 3-7
OFFSHORE WELLS DRILLED AND DRILLING COSTS 1975-1985*
1975
1976
1977
1978
1979
1980
u, 1981
S 1982
1983
1984
1985
1986
# OF
OIL
WELLS
DRILLED
283
275
288
298
349
317
415
486
459
486
369
333
*Current
Source
: Basic
1985
# OF
GAS
WELLS
DRILLED
271
273
393
419
453
444
515
442
293
372
307
207
dollars .
# OF
DRY
HOLES
474
480
536
480
458
511
546
536
518
563
571
358
DRY HOLES
AS % OF
TOTAL
46%
47%
44%
40%
36%
40%
37%
37%
41%
40%
46%
40%
TOTAL
WELLS
DRILLED
1
1
1
1
1
1
1
1
1
1
1
,028
,028
,217
,197
,260
,272
,476
,464
,270
,421
,247
898
Petroleum Data Book. Vol. VII, No. 1
Joint Association Survey on Drilling
AVG. DEPTH
PER WELL
(FT.)
9
9
9
9
9
9
9
9
10
10
10
10
,517
.550
,466
,821
,835
,829
,771
,930
,104
,035
,277
,476
AVG. COST
PER WELL
($000)
1,142
1,435
1,689
2,153
2,545
3,024
3,761
4,203
3,906
3,536
4,073
4,005
AVG.
PER
($)
119.
150.
178.
219.
258.
307.
384.
423.
386.
352.
396.
382.
COST
FT.
99
26
43
22
77
66
87
31
59
33
33
28
, January 1988, Section III, Table H
Costs. American Petroleum Institute.
1986, Table 3.
-------
TABLE 3-8
DOLLAR VALUE OF ANNUAL OIL AND GAS PRODUCTION 1975-1986
(IN BILLIONS OF CURRENT DOLLARS)
OFFSHORE PRODUCTION
NAT- OIL AND
URAL CON-
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
Source
GAS DENSATE TOTAL
1.9 3.8
2.5 3.8
3.6 3.8
4.6 3.7
6.4 5.0
8.5 7.9
11.0 12.2
13.2 11.8
11.7 11.2
14.0 12.1
11.5 11.0
8.0 5.8
5.7
6.3
7.4
8.3
11.4
16.4
23.2
25.0
22.9
26.1
22.5
13.8
: Basic Petroleum Data
Section I ,
Tables 3
NAT-
URAL
GAS
7.1
9.1
12.2
13.4
17.7
23.6
29.0
32.3
31.9
33.9
31.6
24.6
Book,
and 6;
ONSHORE PRODUCTION
OIL AND
CON-
DENSATE
19.4
20.4
22.0
24.7
34.0
57.8
87.2
78.3
71.9
72.0
67.9
34.3
Vol. VIII
OFFSHORE
PRODUCTION
REVENUES .
AS A % OF
TOTAL
26.5
29.5
34.2
38.1
51.7
81.4
116.2
110.6
103.8
105.9
99.5
58.9
. No. 1.
Natural Gas Annual
TOTAL
17.7
17.5
17.6
17.9
18.1
16.8
16.6
17.3
18.1
19.8
18.4
19.0
January 198
1986. U.S.
Department of Energy, Energy Information Administration,
DOE/EIA-13K86), October 1987, Tables 1, 3, and 4.
3-14
-------
3.2.4 Financial Trends
During the 1970's to mid-1980's, the oil industry experienced dramatic
market changes which affected company revenues and net income.
Table 3-9 presents the data on the oil industry's working capital and
capital expenditure levels for the period 1973-1986 from a study of the
performance of 25 large domestic and international oil companies (Energy
Economics Division, Chase Manhattan Bank, 1981, 1982, 1983, 1985, and 1986
editions). Host of the firms included are major domestic integrated
companies; two are large domestic independent companies; also included are
several refiners and several foreign companies. Table 3-9 shows aggregate
financial measures for the sample companies.
The year-to-year revenue and net income changes for this group of
companies is positively correlated with crude oil price increases and
worldwide economic cycles. The companies experienced large, increases in
revenues and net income following the runup in prices resulting from the 1973
Arab oil embargo. In 1975, as the United States and other Western economies
were in a recession, net income declined by almost 30 percent, and rates of
return fell dramatically. In the following three years, annual increases in
net income ranged between 4 and 14 percent, and rates of return improved
slightly.
In 1979, another international crisis, the Iranian revolution,
precipitated a considerable rise in oil prices. Net income for the group of
25 companies more than doubled in 1979, and rose another 11.7 percent in 1980.
Returns on equity and assets peaked in 1979 and 1980 for the 1973-1985 period.
During the 1973-1986 period, internal funds from operations were typically
in excess of required capital and exploration expenditures. The exceptions
were 1975 and 1981 when net income fell. Net income also fell in 1984 through
1986, but the companies had already begun to reduce capital and exploration
expenditures in light of falling oil prices. This excess of funds from
operations over expenditures minimizes the need for companies to enter the
capital markets to fund their capital programs. Internal cash flow supplied
approximately 73 percent of funds used in 1980 by the petroleum industry
(Ocean Industry. October 1981). The pattern of financial performance that
emerges from a review of financial data from 1973 through 1985 closely tracks
3-15
-------
TABLE 3-9
FINANCIAL TRENDS FOR 25 MAJOR PETROLEUM COMPANIES-
(1973-1985)
1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984" 1985" 1986"
Total Revenues
($ billion)
Net Income
($ billion)
% Increase in
Net Income
134 245 245 276 317 347 463 603 646 557 514 530 556 397
11.7 16.4 11.5 13.1 14.4 15.0 31.5 35.2 29.4 21.3 22.7 20.1 20.0 15.2
40.2 -29.9 13.9 9.9 4.2 110.0 11.7 -16.5 -27.6 6.6 -11.5 -0.5 -24.0
Total Funds
from Operations
($ billion)
Capital and
w Exploration
i Expenditures
£ ($ billion)
Capital and
Exploration
Expenditures
as % of Funds
From Operations
Return on
Equity (%)
Return on
Assets (%)
21.2 28.8 23.6 26.8 30.0 34.3 57.5 66.8 65.4 60.9 60.3 57.2 70.2
14.6 22.9 25.0 26.8 28.0 29.9 43.8 55.6 66.4 71.2 54.9 44.3 49.8
69 80 106 100 93 87 76 83 102 117 91 77 71
15:5 19.2 12.8 13.8 13.8 13.2 24.0 22.4 16.8 12.2 12.6 11.6 11.8
8.6 10.0 6.1 6.6 6.4 6.1 11.0 10.2 7.6 5.6 5.9 5.1 4.8
54.1
35.0
65
8.9
3.5
'Companies include Amerada Hess, Ashland Oil, ARCO (Atlantic Richfield Company), British Petroleum, Champlin
Petroleum, Cities Service, Compagnie Francaise des Petroles, Conoco, Exxon, Getty, Gulf, Louisiana Land and Exploration,
Marathon Oil, Mobil Oil, Murphy Oil, Petrofina, Phillips Petroleum, Royal Dutch Shell, Standard Oil of California
(Chevron), Standard Oil of Indiana (Amoco), Sun Company, Superior Oil, Texaco, Tosco, and Union Oil Company (Unocal).
""Revised definitions for "Statements of Income" entries means that 1984, 1985, and 1986 values are not strictly
comparable with historical estimates.
Source :
dollars.
Manhattan Bank, 1985.
-------
the oil price path. A large increase in the price of oil results in large and
rapid increases in profitability and funds from operations. Once the rate of
price increase moderates, industry profitability returns to more "normal"
levels.
To assess the U.S. industry's financial performance for the 1980-1985
period, data are presented for a group of 26 large domestic oil companies (23
are major integrated companies) in Table 3-10. The data in Table 3-10 are
based on a study of a slightly different group of 26 companies prepared by the
Oil and Gas Journal. Of the 26 companies in the latter sample, 19 were
included in the Chase study, and therefore the two groups are readily
comparable. The financial data in these tables are calculated by aggregating
the appropriate financial measures for each of the companies in the sample and
are, therefore, generally representative of major domestic and international
oil firms.
Falling demand and prices have affected the major domestic oil companies
negatively in this recent period (Oil and Gas Journal. May 25, 1987). Table
3-10 shows the effect of these changes on principal financial variables. Net
income fell by $18.4 billion from 1980 through 1986, a decline of 63 percent.
Gross revenues also decreased 27 percent.
Capital and exploration expenditures for this group of firms closely track
those reported in the Chase study. These expenditures peaked in 1981-82,
declined by approximately 25 percent through 1985, and then dropped steeply in
1986 as oil prices plunged.
The profitability measures for the period 1980-86 in Table 3-10 illustrate
dramatically the impact of declining oil prices over this period: return on
equity fell from 21.0 percent to 7.4 percent, while return on assets fell from
9.3 percent to 2.9 percent.
3.2.5 Increases in Industry Debt
The expansion of capital and exploration expenditures over the period
1979- 1981 was financed primarily through internally generated funds and
through an increase in the level of industry debt. Anticipation of an
increase in the value of in-ground reserves through rising prices, and an
increase in the expected volume of reserves through greater expenditures on
exploration, together provided the financial rationale for acquiring this
3-17
-------
TABLE 3-10
FINANCIAL STATISTICS FOR 26 LARGE U.S. OIL COMPANIES 1980-1986
CJ
I
(In Billions of Current Dollars)
1980 1981 1982 1983
Gross Operating Revenues 493.0 546.4 507.5 500.0
Net Income 29.3 28.2 21.9 22.3
Funds from Operations 54.9 56.0 52.8 53.1
Capital and Exploration 52.1 66.9 60.5 48.6
Expenditures
Return on Equity (%) 21.0 17.9 12.9 12.3
Return on Assets (%) 9.3 7.9 5.9 5.8
PER-
CENT
CHANGE
(1980-
1984 1985 1986 1986)
463.8 464.6 358.3 -27.3
20.1 15.8 10.9 -62.8
52.9 56.4 41.2 -25.0
46.6 50.9 33.6 -35.5
12.4 10.1 7.4 -64.8
5.1 3.8 2.9 -68.8
Companies included in the survey are Amerada Hess*, American Petrofina, ARCO
(Atlantic Richfield)*, Ashland Oil*, Cities Service*, Diamond Shamrock, Exxon*, Getty*,
Gulf*, Kerr-McGee, Louisiana Land and Exploration*, Marathon*, Mobil*, Murphy*,
Occidental, Pennzoil, Phillips*, Shell*, Standard Oil of California (Chevron)*, Standard
Oil of Indiana (Amoco)*, Standard Oil of Ohio, Sun*, Superior*, Tenneco, Texaco*, and
Union*.
*Companies included in the Chase study.
Source: Oil and Gas Journal. 31 May 1982, 21 March 1983, 11 June 1984, 20 May 1985, 26
May 1986, and May 25, 1987.
-------
additional debt. Independents as a whole increased their use of debt
financing at a faster rate than the majors. As prices fell, almost all
companies suffered a decline in profits, and those companies that had taken on
large amounts of debt also faced increases in interest obligations. In
addition, as the value of proven reserves against which much of the debt was
secured fell with the decline in prices, pressure mounted for some companies
to pay back a portion of their loans. Lenders wanted them to bring the value
of their borrowing back into line with the recalculated collateral value of
the reserves. This need to provide additional collateral or reduce
outstanding debt had a direct and immediate negative impact on the companies'
cash position.
A good index measuring a company's debt financing burden is the debt-to-
total -capital ratio. As the ratio rises, a company has less flexibility to
make further capital expenditures. Table 3-11 presents the debt-to-total-
capital ratios for a sample of major integrated companies and independent
companies during the 1981-1985 period. The ratios shown were calculated by
averaging the ratios of all companies in the sample. The ratios are thus a
straightforward company-based average, unaffected by the relative size of
companies in the sample. The table shows that major integrated companies
experienced an upward trend in their debt-to-capital ratio from 1981 to 1985.
For the sample of independent companies, the ratio fluctuated through the
1981-1985 period, with a relatively large seven-percentage-point jump in 1982,
a year after capital and exploration expenditures reached their peak. As
shown in Table 3-11, the debt-to-capital ratio is significantly higher for the
sample of independent companies than for the sample of integrated companies
for each year in the 1981-1985 period.
33 FINANCIAL CONDITION OF INDUSTRY SEGMENTS
The reduction in demand for oil and natural gas at a time when petroleum
companies were expanding their long-term investments had an adverse impact on
the companies' financial positions and spending patterns. Profits for the
majors generally declined from 1981 to 1985, and spending plans were reduced.
The majors retain substantial resources and as a group, have borrowed more
conservatively than the independents. The market changes have had a serious
impact on certain highly leveraged independents. A review of key financial
ratios of the majors and independents highlights these recent trends.
3-19
-------
TABLE 3-11
DEBT/CAPITAL RATIOS (%) FOR MAJOR
INTEGRATED AND INDEPENDENT COMPANIES
SAMPLE OF SAMPLE OF
MAJOR INTEGRATED INDEPENDENT
YEAR OIL COMPANIES3 OIL COMPANIES13
1981
1982
1983
1984
1985
22.7
23.9
23.8
28.2
33.1
34.8
42.1
37.3
39.9
39.6
aSample consists of Amerada Hess, American Petrofina, ARCO, Diamond
Shamrock, Exxon, Getty Oil, Gulf Oil, Kerr-McGee, Mobil Oil, Murphy Oil,
Occidental Petroleum, Phillips Petroleum, Shell Oil, Standard Oil of
California (Chevron), Standard Oil of Indiana (Amoco), Standard Oil of Ohio,
Sun Company, Texaco, Union Oil Company.
Sample consists of Apache Corporation, Cabot Corporation, Conquest
Exploration, Damson Oil, Hamilton Oil Corp., Helmerich & Payne, Howell
Corporation, Lear Petroleum Corp., LA Land & Exploration, Mitchell Energy &
Development, Noble Affiliates, Inc., Pauley Petroleum, Plains Resources, Inc.,
Pogo Producing, Sabine Corporation, Triton Energy Corporation, Wainco Oil
Corporation.
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys,
November 4, 1982 and November 27, 1986.
3-20
-------
33.1 Ratios Used to Analyze Industry Segments
The following sections apply ratio analysis methodology to the two basic
industry segments under study: major integrated companies and independents.
The financial ratios used to analyze the different segments are Return on
Equity, Return on Assets, Current Ratio, and Debt/Capital Ratio (already
presented in summary form in 3.2, above). The ratios are all calculated using
book values. These ratios are important because they are used both by the
investment community to evaluate the health and value of the companies and by
company executives to formulate exploration, capital expenditure, and
production strategies. The expected change in these financial ratios that
would occur under each alternative regulatory approach is estimated in Section
Seven of this report. Thus, the ratios presented here provide the basis for
part of the economic impact assessment which follows.
Return on Equity and Return on Assets are key profitability indicators,
measuring the relative earnings performance of a firm. They indicate the
overall worth and profitability of the business. Financial lenders,
investors, and analysts look for these indices to fall within an acceptable
range. Return on Equity is defined as net income divided by shareholders'
equity and measures how effective the company's operations are in creating
value for the equity holders. Return on Assets is defined as net income
divided by the value of assets and measures company efficiency in using assets
to make profits. Firms have a certain degree of discretion (within acceptable
accounting guidelines) in both stating the value of their assets and in timing
and recognizing net income. For this reason, year-to-year comparisons for an
individual firm may be misleading. However, the level of these indicators
provides a good guide to the earnings performance of a firm if viewed over a
number of years.
Current and Debt/Capital Ratios provide measures of a firm's financial
health and flexibility. The Current Ratio, which is defined as current assets
divided by current liabilities, is used as a measure of a firm's liquidity.
It indicates the availability of liquid assets to meet current liabilities. A
relatively low ratio (under 1.0) or a falling ratio are danger signals,
indicating that a firm may be unable to meet its short-term cash obligations
and possibly go into default. If a firm is forced to fall back on non-current
assets to meet its current obligations, it may be forced to liquidate these
assets at a loss.
3-21
-------
The Debt/Capital Ratio1 measures a company's level of debt or leverage.
While some debt is always beneficial for a company's shareholders, too much
debt can impose severe constraints on a company's ability to operate and its
periodic cash flows. The higher the level of debt, the larger are the regular
interest payments the company has to make. These obligations, though tax
deductible, reduce net income and use up cash, thus leaving less for
reinvestment or for shareholder payments as dividends. In addition, companies
with high levels of debt may be unable to acquire additional short-term
financing for operations because of constraints placed upon them by existing
lenders, or they may only be able to acquire new debt at a very high cost. In
general, the higher the level of debt, the greater the possibility that a
company may default on its interest payments in the event of an unexpected or
severe downturn in revenues.
33.2 Ratio Analysis of Major Integrated Companies
Discussion of Financial Ratios
The four financial ratios are presented for 14 domestic integrated
companies and five of the international integrated companies who are major
U.S. operators, as reported by the Standard and Poor Industrial Surveys. The
ratio values for the sample of 19 major integrated companies calculated for
1977 through 1985 or 1986 is presented in Tables 3-12 through 3-18. Also
shown are the average value of the ratios for the firms in the sample. The
seven tables cover the Return on Equity, Return on Assets, Current and
Debt/Capital Ratios. (Table 3-18 provides detailed data on Debt/Capital that
were presented in summary form in Table 3-11.) These tables reflect the
overall financial performance of the companies covered, not solely their
petroleum operations.
The first table (Table 3-12) covering Return on Equity for the ERG sample
shows that the average reached a peak in 1980 (23.7 percent) and then
declined. The decline in profitability from 1980 is clear. In 1985, 12 of
'The Debt/Capital Ratio is defined for this study as the book value of
long-term debt as a percent of the book value of invested capital (sum of
current liabilities and stockholder equity). This S&P industry survey defines
debt/capital ratio as long-term debt as a percentage of total invested capital
(sum of stockholder's equity, long-term debt, capital lease obligations,
deffered income taxes, investment credits and minority interest). The values
on Tables 3-19 and 3-23 are therefore not directly comparable to those on
Tables 3-26, 3-22, and 3-32. Values within a given table are calculated on a
consistent basis.
3-22
-------
TABLE 3-12
RETURN ON EQUITY (%)
CJ
I
to
u>
MAJOR INTEGRATED OIL C OMPANIES: 19 COMPANY GROUP
(1977-1985)
RETURN ON EQUITY
COMPANY
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-McGee
Mobil Oil
Murphy Oil
Occidental Petroleum
Phillips Petroleum
YEAR 1977
25
10
17
22
12
12
10
12
12
11
IS
17
.5
.2
.9
.0
.8
.9
.5
.4
.6
.9
.3
.8
1978
14.0
8.2
16.8
15.6
14.0
11.6
10.5
11.3
13.1
10.7
0.5
21.1
1979
35.1
20.7
21.2
16.4
20.2
19.0
16.1
13.9
20.7
21.0
52.9
22.6
1980
26.0
22.3
25.2
17.4
23.7
23.1
14.3
14.3
23.8
24.9
41.4
23.4
1981
8.9
14.2
21.3
16.8
20.6
19.2
12.9
14.8
17.5
22.2
26.7
16.9
1982
6.7
9.2
18.3
10.8
14.7
14.2
9.4
13.1
9.6
18.7
2.6
11.4
1983
8.1
9.6
15.0
NM
17.2
--
7.0
10.5
14.0
4.2
12.1
1984
6.7
7.2
10.9
8.2
19.0
--
--
3.7
9.2
11.8
11.9
12.7
1985
NM
NM
4.3
NM
16.8
--
--
7.9
7.5
7.9
8.3
14.1
1986
NM
NM
11.7
NM
16.7
NM
9.2
NM
4.2
11.4
(Cont'd)
-------
TABLE 3-12 (CONT.)
CJ
I
to
RETURN ON
COMPANY YEAR
Shell Oil (Royal Dutch Petroleum)
Standard Oil of California (Chevron)
Standard Oil of Indiana (Amoco)
Standard Oil of Ohio
Sun Company
Texaco
Unocal
Unweighted
Company Average*
1977 1978
14.
13.
15.
10.
14.
10.
14.
14.
NM - Not meaningful, negative net income
NC - Not calculated. The large number
meaningless .
of
Source: "Oil, Basic Analysis," Standard
1986; 1986 data from Oil and Gas
7 14.1
9 13.9
7 15.5
1 21.8
8 13.7
1 9.0
6 15^2
7 13.9
for that
1979
17.0
20.4
19.2
45.9
20.7
17.5
18.0
23.1
year.
firms reporting
and Poor'
Journal .
1980
20.4
23.6
21.8
47.3
18.1
19.4
20.1
23.7
a net
1981
19.6
20.0
19.1
37.0
23.8
17.9
20^8
19.5
loss for
EQUITY
1982
10.6
10.6
16.6
28.5
10.7
9.2
18.1
13.1
1986
1983
14
11
15
19
8
8
12
11
make
.9
.6
.7
.7
.6
.5
J>
.1
this
1984
16.8
10.6
17.5
18.1
10.2
1.8
12.9
11.1
1985 1986
12.
10.
16.
3.
9.
9.
JL.
. 8.
2 6.2
2 4.6
2 6.6
8 NM
9 7.3
1 5.3
1 10.5
1 NC
average
s Industry Surveys, November 4, 1982, and November 17,
May 25, 1987. May not be strictly comparable to
1977-1985 data.
'Simple average of the ratios for the sample.
-------
TABLE 3-13
RETURN ON EQUITY (%)
OJ
I
KJ
Ul
GROUP
Chase Manhattan
Group*
S&P's Domestic
Integrated Oil"
ERG 19 -Company
Group'
COMPARISON OF AVERAGE YIELDS
FOR THREE SAMPLES OF MAJOR INTEGRATED OIL COMPANIES
(1977-1986)
RETURN ON EQUITY
1977 1978 1979 1980 1981 1982 1983 1984 1985 1986
13.8 13.2 24.0 22.4 16.8 12.2 12.6 11. 6d 11.3d 8.9
14.5 14.3 18.5 20.3 19.8 15.2 13.4 13.9 10.5 4.7
14.7 13.9 23.1 23.7 19.5 13.1 11.1 11.1 8.1 NC
10 -YEAR
AVERAGE
14.7
14.5
NC
Source: As noted below.
'"Financial Analysis of a Group of Petroleum Companies," Energy Economics Division, Chase
Manhattan Bank, 1981, 1983, 1985, and 1986 Editions. See Table 3-9 for company list.
bAnalvst Handbook. Standard & Poor's, Official Series, 1982, 1986, and 1987 Editions.
'Table 3-12.
dRevised definitions for "Statement of Income" entries means that 1984 and 1985 values are not
strictly comparable with historical estimates.
NC - Not calculated.
-------
TABLE 3-14
RETURN ON ASSETS (%)
u>
I
to
or\
MAJOR INTEGRATED OIL COMPANIES: 19-COMPANY ERG GROUP
(1977-1985)
RETURN ON ASSETS
COMPANY YEAR: 1977
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-McGee
Mobil Oil
Murphy Oil
6
4
6
9
6
8
5
6
5
3
.0
.6
.8
.4
.5
.0
.4
.9
.1
.7
1978
4.2
3.5
6.7
6.7
6.9
7.4
5.4
6.1
5.2
3.2
1979
11.3
8.0
8.9
7.0
9.5
11.2
8.2
7.3
8.0
6.1
1980
9.6
9.2
10.7
7.5
10.7
12.2
7.8
7.1
9.3
7.2
1981
3.5
6.4
9.1
7.5
9.4
9.6
6.5
6.8
7.2
6.4
1982
2.7
4.7
8.0
4.8
6.7
7.2
4.6
5.8
4.0
5.5
1983
3.3
4.3
6.9
NM
7.9
--
3.1
4.2
4.6
1984
2.7
2.9
5.0
4.2
8.8
--
--
1.7
3.3
4.3
1985
NM
NM
1.6
NM
7.4
--
--
3.7
2.5
3.0
1986
NM
NM
2.8
NM
7.7
-- .
--
NM
3.6
NM
(Cont.)
-------
TABLE 3-14 (CONT.)
Ul
I
ro
RETURN ON ASSETS
COMPANY YEAR:
Occidental Petroleum
Phillips Petroleum
Shell Oil (Royal Dutch
1977
5.0
9.5
8.3
1978
0.2
11.1
8.4
1979
10.9
11.5
9.1
1980
11.1
11.7
8.8
1981
9.0
8.3
9.0
1982
1
5
7
.3
.5
.7
1983
3.5
5.7
5.9
1984
4.7
5.4
7.0
1985
3.8
3.8
5.4
1986
1.0
1.8
3.4
Petroleum)
Standard Oil of California 7.1
(Chevron)
Standard Oil of Indiana 8.4
(Amoco)
7.0 10.2 11.9 10.4
8.0
9.6 10.4
8.9
5.8 6.7
7.8 7.5
5.1
8.5
4.1
7.7
2.1
3.2
Standard Oil of Ohio
Sun Company
Texaco
Unocal
Unweighted
Company Average"
2.3
6.6
5.0
5.0
6.8
4.4
7.3
6.4
13.4
10.2
8.1
8.7
6.0
17.0
7.8
9.1
10.1
9.3
14.0
9.5
8.7
11.0
10.0
11.8
4.5
4.7
10.0
8.5
9.3
3.7
4.5
7.1
6.0
8.
4.
0.
7.
5.2
8
3
9
2
1
4
3
3
5.
.7 NM
.1 3.3
.3 2.1
.1 1.7
0 3.2
(Cont.)
NC
-------
to
00
TABLE 3-14 (CONT.)
NM - not meaningful.
NC Not calculated. The large number of firms reporting a net loss for 1986 render this
average meaningless.
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys, November 4, 1982 and
November 27, 1986; 1986 data from Oil and Gas Journal. May 25, 1987. May not be
strictly comparable to 1977-1985 data.
'Simple average of the ratios for the sample.
-------
TABLE 3-15
RETURN ON ASSETS (%)
COMPARISON OF AVERAGE YIELD FOR 4 SAMPLES OF MAJOR COMPANIES
Ul
1
KJ
VO
GROUP 1977
ERG 19 -Company Group0 6.4
Chase Manhattan Group* 6.4
S&P's Domestic Integrated 7.2
Oil"
S&P's 400 Industrials" 6.5
(1977-1986)
RETURN ON ASSETS
10 -YEAR
1978 1979 1980 1981 1982 1983 1984 1985 1986 AVERAGE
6.0 9.3 10.0 8.5 6.0 5.2 5.0 3.2 NC NC
6.1 11.0 10.2 7.6 5.6 5.9 5.1d 4.7d 3.5 6.6
7.1 8.6 9.3 8.9 6.9 6.2 6.2 3.4 1.5 6.5
6.6 7.2 6.5 6.2 4.6 5.1 5.8 4.4 4.0 5.7
'"A Financial Analysis of a Group of Petroleum Companies," Energy Economics Division, Chase Manhattan
Bank. Includes large domestic and international petroleum companies. See Table 5-10.
"Analyst Handbook. Standard & Poor's, Official Series, 1982 and 1986 Editions.
'Table 3-14.
dRevised definitions for "Statements of Income" entries means that 1984 and 1985 values are not
strictly comparable to historical estimates.
NC - Not calculated.
-------
TABLE 3-16
CURRENT RATIO
MAJOR INTEGRATED OIL COMPANIES: I9-COMPANY ERG GROUP
(1977-1985)
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-McGee
Mobil Oil
Murphy Oil
Occidental Petroleum
Phillips Petroleum
Shell Oil (Royal
Dutch Petroleum)
Standard Oil of
California (Chevron)
Standard Oil of
Indiana (Amoco)
Standard Oil of Ohio
Sun Company
Texaco
Union Oil Company
Unweighted
Company Average*
1977
1.4
1.4
1.6
2.0
1.4
1.6
1.2
1.8
1.2
1.1
1.4
1.3
1.6
1.3
1.5
1.6
1.4
1.4
L2
1.5
1978
1.3
1.6
1.6
2.0
1.4
1.5
1.2
1.5
1.1
1.1
1.0
1.4
1.4
1.3
1.5
1.4
1.2
1.4
L2
1.4
1979
1.3
1.5
1.6
1.9
1.3
1.2
1.3
1.7
1.1
1.1
1.1
1.3
1.0
1.4
1.3
2.0
1.3
1.5
LJ.
1.4
1980
1.4
1.5
1.2
2.2
1.4
0.9
1.3
1.4
1.1
1.2
1.1
1.2
1.0
1.5
1.1
1.2
0.9
1.7
J^l
1.3
1981
1.3
1.4
1.2
2.0
1.3
0.9
1.1
1.7
1.1
1.1
1.1
0.9
1.0
1.4
1.0
0.7
1.1
1.7
LJ,
1.2
1982
1
1
1
1
1
1
1
1
.1
1
1
1
1
1
1
0
1
1
.4
.4
.2
.7
.2
.0
.1
.5
.0
.1
.1
.1
.0
.3
.1
.8
.1
.5
1983
1
1
1
1
1
-
-
1
1
1
1
1
1
1
1
1
1
1
.5
.2
.3
.4
.2
-
-
.3
.1
.2
.0
.0
.6
.4
.2
.0
.2
.5
1.2 1.3
1.2
1,
,3
1984
1.4
.1.2
0.9
1.2
1.1
1.3
1.0
1.2
1.4
0.9
1.4
1.0
1.1
0.8
1.0
1.2
±2
1.1
1985
1.3
1.1
0.6
1.1
0.9
1.2
1.0
1.2
1.2
1.0
1.4
1.1
0.9
1.1
1.2
1.0
LJi
1.1
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys, November 4,
1982 and November 27, 1986.
'Simple average calculated from the ratios for all companies in the sample..
3-30
-------
TABLE 3-17
CURRENT RATIO
COMPARISON OF AVERAGE YIELDS FOR
4 SAMPLES OF MAJOR INTEGRATED OIL COMPANIES
(1977-1985)
Ul
OJ
CURRENT RATIO
GROUP
10-YEAR
1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 AVERAGE
ERG 19-Company Group"
Chase Manhattan Group6
S&P's Domestic
Integrated Oilc
S&P's 400 Industrials'
1.5 1.4 1.4 1.3
1.4 1.3 1.4 1.4
1.5 1.5 1.3 1.1
1.2 1.2 1.3 1.1 1.1 NA
1.3 1.2 1.3 1.2" l.ld 1.3
1.0 1.1 1.1 1.0 1.0 1.2
1.8 1.7 1.6 1.6 1.5 1.5 1.5
1.5
NA
NA
1.3
1.3
1.2
1.6
NA - not available
Source: As noted below.
'Table 5-17.
b"A Financial Analysis of a Group of Petroleum Companies," Energy Economics Division, Chase
Manhattan Bank, 1981, 1983 and 1985 editions.
'Analyst Handbook. Standard & Poor's, Official Series, 1982, 1985, 1986, and 1987 Editions.
dRevised definitions for "Statements of Income" entries means that 1984 and 1985 values are not
strictly comparable to historical estimates.
-------
TABLE 3-18
DEBT/CAPITAL RATIO (%)
MAJOR INTEGRATED OIL COMPANIES IN 19-COMPANY ERG GROUP
' (1977-1985)
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-McGee
Mobil Oil
Murphy Oil
Occidental Petroleum
Phillips Petroleum
Shell Oil (Royal
Dutch Petroleum)
Standard Oil of
California (Chevron)
Standard Oil of
Indiana (Amoco)
Standard Oil of Ohio
Sun Company
Texaco
Union Oil Company
Unweighted
Company Average1
1977
36.7
26.4
34.2
38.1
14.4
5.8
13.5
20.9
25.2
35.5
26.8
21.0
20.6
16.2
25.2
71.9
18.9
19.1
26.8
26.2
1978
36.0
45.8
34.6
38.4
13.3
4.7
14.1
16.6
25.6
40.5
39.4
16.3
18.4
19.7
23.5
65.4
19.4
24.8
28.6
27.6
1979
30.0
40.4
29.4
38.1
13.3
4.0
13.0
20.4
21.3
32.3
39.0
13.6
30.6
17.2
21.1
50.3
16.8
21.8
26.0
25.2
1980
29.5
33.5
27.1
36.0
12.5
10.8
10.7
24.1
19.0
19.1
25.6
12.4
33.0
13.0
18.8
39.8
34.5
18.0
21.9
23.1
1981
35.2
28.1
28.9
34.0
12.0
9.8
13.0
33.1
17.3
21.1
20.1
15.0
31.3
12.4
21.4
36.1
28.6
15.1
18^3.
22.7
1982
38.9
26.0
28.7
34.3
10.6
16.6
14.6
29.7
21.1
16.9
43.5
22.7
27.8
11.3
22.0
33.8
24.7
12.8
18.6
23.9
1983
40
31
26
37
10
-
-
27
24
15
34
23
19
10
20
29
24
14
iZ
23
.3
.4
.2
.0
.5
-
-
.1
.4
.1
.0
.3
.1
.6
.1
.2
.8
.1
^6
.8
1984
40.
39.
26.
28.
11.
--
23.
40.
14.
43.
26.
17.
43.
17.
26.
25.
41.
il.
28.
1
1
9
1
6
5
9
3
3
0
3
4
3
4
3
0
1
2
1985
40.6
40.8
43.9
40.7
10.4
23.4
35.8
13.7
47.6
64.3
14.6
28.9
16.9
25.4
20.7
31.6
64J,
33.1
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys, November 4,
1982 and November 27, 1986.
'Simple average calculated from the ratios for all companies in the sample.
3-32
-------
the 19 companies reported returns below 10 percent, two reported returns
between 0 and 5 percent, and three recorded a net loss for the year. In 1986,
16 of the 19 firms recorded returns on equity of less than 10 percent, two
recorded returns between 0 and 5 percent, and 6 reported negative net income
for the year.
The second table (Table 3-13) compares the performance of three sample
groups. A time series on the Return on Equity was examined to determine
whether the recent data are characteristic of the industry. Industry averages
for the years 1977 through 1986 are 14.7 for the Chase Manhattan Group and
14.5 for the Standard & Poor Domestic integrated oil group. Thus industry
returns in 1979 and 1980 are far above the industry average, and oil industry
Return on Equity is returning to levels closer to historical averages from
peaks established in 1980 and 1981.
The Return on Assets data (Table 3-14) show a pattern similar to the
Return on Equity data. The Return on Assets for ERG's sample peaked in 1980.
Note that the Return on Asset data for the sample track closely with the
return on assets values for the Chase Manhattan Group and the S&P Domestic
Integrated Oil Samples as shown in Table 3-15. Over'the period 1977-1986, the
oil industry, as measured by the three samples, generally outperformed the
wider market index of 400 industrials.
In conclusion, profitability for the major integrated oil companies in
1979-1981 was high relative to typical oil industry performance since 1973.
In 1982 through 1986, profitability fell to levels below the industry's
historical averages. Profitability for the oil industry (as measured by
Return on Assets) significantly exceeded profitability for a broader sample of
industrial firms for the years 1979 to 1981.
The trend of Current Ratios for the ERG sample, as shown in Table 3-16,
reflects the cash outflow caused by the rapid growth in capital and
exploration expenditures between 1979 and 1981. The current ratio declined
from 1.5 in 1977 to 1.1 in 1984 and 1985 as major integrated producers reduced
their working capital levels to help finance their expenditure programs.
The industry's Current Ratios were also measured by other sources of
financial data. The Current Ratios for the Chase Manhattan and Standard &
Poor surveys are shown in Table 3-17. For S&P's sample of Domestic Integrated
Oil Companies, the Current Ratio declined from 1.5 in 1977 to 1.0 in 1981,
1984 and 1985. The Chase Manhattan sample shows less of a downward trend,
which may be due to the inclusion of foreign multinationals, whose currency
3-33
-------
translation effects and sources of foreign capital can offset domestic
conditions to some degree. On balance, however, it appears that the average
Current Ratio for the industry has declined. For both the Chase Manhattan and
the S&P Groups, 1986 current ratios were higher than those recorded in 1985,
as firms drastically reduced current liabilities to solidify their financial
position in the face of an uncertain and hostile business climate.
The oil industry segment data compares adversely to S&P 400 Industrial
data which show an average Current Ratio of 1.6 for the period 1977 to 1984.
(Standard and Poor's ceased tabulating current ratio data for the 400
Industrials after 1984.) Although the industrial sample shows a declining
pattern similar to that for the several oil industry samples, the S&P 400
Industrial's current ratio was consistently higher. This may result from the
fact that the major integrated oil companies were better capitalized; produce
products with solid, established, worldwide markets; and are generally more
profitable than S&P's general industrial sample. Thus they do not require as
large a reserve of working capital because they can rely on expected earnings
and can borrow funds more readily.
Table 3-18 shows the Debt/Capital Ratios for the major integrated oil
companies in ERG's sample for 1977-1985. Despite the large growth in
exploration and capital expenditures, the debt-to-capital ratio actually
reached a low in 1981, indicating the major integrated companies were not
relying heavily on debt financing. In fact, debt as a percent of capital fell
steadily from 1978 to 1981. It did rise in 1982, primarily attributable to
the results from Getty and Occidental Petroleum. Occidental purchased Cities
Service Company in 1982 and its Debt/Capital Ratio increased from 20.1 percent
to 43.5 percent. The effects of the numerous mergers, takeovers, and
acquisitions, as well as deteriorating market conditions in recent years, can
be seen in the steady increase in the Debt/Capital ratio from 1982 through
1985.
Discussion of Real Corporate Wealth
An outstanding feature of the accounting data filed by oil companies is
that reported assets and net worth may bear little relation to actual
corporate wealth. This is true because the value of a firm's resource
reserves is not recorded as an asset; the value of these reserves is
recognized only when they enter the production process and revenues and
expenses associated with their production and sale are generated. Instead,
oil companies' asset accounts reflect the capitalized cost of exploration and
3-34
-------
development expenses. (That is, the value of a firm's reserves is set equal
to the cost of procuring the reserves and making them ready for production.)
These exploration and development costs are subsequently amortized; again, the
amortization of these "assets" bears no relation to the size or value of the
firm's reserves or to the timing of their consumption.
Since 1978 oil companies have been required to publish supplementary
financial information relating to the size and value of their oil, gas, and
other mineral reserves. This information makes it possible to estimate the
total value of each firm's reserves, and to make a more realistic estimate of
a firm's actual net wealth than that reflected in the balance sheet. This
estimate will be flawed (for example, because firms are not required to report
reserves of minerals other than oil and gas, because of uncertainties in
estimates of proven reserves, and because of uncertainties in estimates of
future development and production costs), but will nonetheless facilitate a
much more realistic assessment of a firm's real wealth than that provided by
the standard financial statements.
ERG performed a rough asset valuation for six major integrated U.S. oil
companies (Amoco, ARCO, Exxon, Mobil, Shell, and Texaco), based on the
supplementary reserve data published in each firm's 1986 annual report. We
calculated total gross assets as the sum of the value of all reported mineral
reserves (oil and gas, plus coal, sulfur, phosphate rock, and carbon dioxide,
if these reserves were reported), at prices approximating year-end 1986
values, plus current assets recorded in the balance sheet. From these assets
were subtracted: (1) total balance sheet liabilities; (2) the outlay required
to liquidate outstanding preferred stock; (3) future oil and gas development
and production costs, as estimated by each firm; and (4) estimated costs to
produce other reported mineral resources (calculated as 75 percent of the
estimated resource value). The result of this calculation is an estimate of
the net asset value of each firm; this value is an approximation of the
"liquidation value" of each firm, the net proceeds to stockholders if the firm
were to be dismantled and its assets sold at current market prices.
Table 3-19 shows the results of this asset valuation process for the six
American integrated oil companies specified above. The estimated gross value
of the firms' mineral reserves is nearly $700 billion; with the addition of
current assets, the total gross asset value of the six firms equals $749
billion. Total reported liabilities plus liquidation value of preferred stock
equal $120 billion; development and production costs of reported mineral
reserves are estimated to be $280 billion. Subtracting these totals from
3-35
-------
TABLE 3-19
ESTIMATED VERSUS REPORTED NET ASSET VALUE
OF SIX MAJOR U.S. INTEGRATED OIL COMPANIES, 1986
Quant. Uni ts
' Price Units
Conversion Units
Value
GROSS ASSETS
RESOURCE RESERVES
Oil
Nat Gas Liquids
Nat Gas
Coal
Sulfur
Carbon Dioxide
Phosphate
20,146 MNBbl
876 MMBbl
103,9999 Bcf
5,400 MHtons
8,293 Mtons
7,673 Bcf
132,000 Mtons
S15.00
S9.83
$2.50
$22.50
$100.00
SO. 45
S21.50
TOTAL GROSS VALUE OF RESOURCES
CURRENT ASSETS
TOTAL GROSS VALUE OF ASSETS
/Bbl Gross
/Mcf Gross
/ton Gross
/ton Gross
/Mcf Gross
/ton Gross
1
1
1
1
1
,000,
,000,
,000,
,000,
1,
,000,
1,
000
000
000
000
000
000
000
bBL/mmbBL
Bbl/MMBbt
Mcf/Bcf
tons/MMtons
tons/Mtons
Mcf/Bcf
tons/Mton
$302,
8,
259.
121,
3,
2,
$699,
50,
190,
608,
997,
500,
829,
452,
838,
416,
022,
000
965
500
000
300
850
000
615
000
,000
,517
,000
,000
,000
,000
,000
,517
,000
$749,438,615,517
COSTS AND LIABILITIES
Total Liabilities
Liquidation of Preferred Stock
Future Oil/Gas Production and Development
Costs
Future Production/Development Costs, Other Commodities
(75X of Gross Value)
TOTAL COSTS AND LIABILITIES
($119,952,000,000)
(128,751,000)
(183,905,000,000)
(96,465,112,500)
($400,450,863,500
NET ASSET VALUE
$348,987,752,017
GROSS BOOK VALUE OF ASSETS (PER 1986 BALANCE SHEET)
SHAREHOLDER'S EQUITY (PER 1986 BALANCE SHEET)
$215,360,000,000
$91,975,000,000
1986 dollars.
Source: ERG estimates based on values reported in the 1986 Annual Reports of six oil companies specified in
the text.
3-36
-------
estimated gross assets yields an estimated net asset value for the six firms
of $349 billion.
Table 3-19 also tabulates the total book asset value and the total book
value of owner's equity reported by the six oil companies in 1986. Gross
reported assets were $216 billion -- less than 30 percent of the gross asset
value calculated on the basis of reserves in place, and only 62 percent of the
net asset value calculated on this basis. Total common shareholder's equity
reported by the six firms was $92 billion. This total -- which equals the net
book asset value of the firm --is approximately one-fourth of the firms' net
asset value calculated on the basis of their mineral reserves.
This alternative valuation process demonstrates that the real wealth of
major American oil companies is significantly greater than that reported in
their common financial disclosures. Coupled with the fact that even during
periods of relative economic hardship oil companies tend to generate large
cash earnings1, this finding supports a conclusion that the financial
condition of the major oil companies may be significantly stronger than a
simple analysis of their published financial data indicates.
333 Ratio Analysis of Independent Companies
The decline in profits from 1980 seen for the large integrated
corporations is magnified for the sample of independent producers. Of the 16
companies listed in the 1982 edition of Standard and Poor's Industry Survey
for Oil, only 4 appear on the list of companies in the 1986 edition. The
tenuous position of some of the latter companies is shown by the various "NM"
entries in Table 3-20 through 3-23, indicating that the company was either not
in existence or had a negative net income for that year. This is not to imply
that the absence of a company from the 1986 list is due solely to bankruptcy;
mergers and acquisitions account for most of the removals.
The return on equity for independents (Table 3-20) slides from 13 percent
in 1980 to 3.9 percent in 1985. The increase seen in 1982 is due solely to
the entry of Pauley Petroleum. The other measure of profitability, return on
assets, shows the same downward trend, from 5.8 percent in 1981 to 1.6 percent
'Standard and Poor's Industry Survey, "Oil, Basic Analysis," November
1986, p. 0-38.
3-37
-------
TABLE 3-20
RETURN ON EQUITY (%)
INDEPENDENT OIL COMPANIES IN ERG 17-COMPANY SAMPLE
Apache Corp .
Cabot Corp.
Conquest Exploration
Damson Oil
Hamilton Oil Corp.
Helmerich & Payne
Howell Corp.
Lear Petroleum Corp.
LA Land & Exploration
Mitchell Energy & Dev.
Noble Affiliates, Inc.
Pauley Petroleum
Plains Resources, Inc.
Pogo Producing
Sabine Corp.
Triton Energy Corp.
Uainco Oil Corp.
Unweighted Company Average*
1981
14.0
19.6
NM
12.2
9.3
27.7
NM
6.8
18.5
34.2
28.3
NM
NM
26.8
16.5
7.6
NM
13.0
1982
13.2
14.1
NM
7.4
3.6
22.5
3.1
7.3
9.2
19.0
19.7
NM
NM
18.0
12.5
2.1
NM
8.9
1983
9.4
9.7
6.2
5.9
5.8
12.4
2.1
11.3
12.8
14.9
5.8
54.1
NM
7.7
18.5
19.8
7.1
12.0
1984
9.5
13.9
4.7
13.0
6.5
5.2
4.5
8.5
18.6
6.7
4.3
2.1
10.9
5.6
4.1
10.1
0.9
7.6
1985
4.1
10.6
4.1
NM
9.1
4.4
5.6
NM
1.8
8.6
3.3
9.6
2.5
NM
2.4
NM
NM
3.9
NM - Not meaningful, negative net income for those years, or company not yet
formed.
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys,
November 27, 1986.
"Simple average calculated from the ratios of the sample.
3-38
-------
TABLE 3-21
RETURN ON ASSETS (%)
INDEPENDENT OIL COMPANIES IN ERG 17-COMPANY SAMPLE
Apache Corp .
Cabot Corp .
Conquest Exploration
Damson Oil
Hamilton Oil Corp.
Helmerich & Payne
Howe 11 Corp.
Lear Petroleum Corp.
LA Land & Exploration
Mitchell Energy & Dev.
Noble Affiliates, Inc.
Pauley Petroleum
Plains Resources, Inc.
Pogo Producing
Sabine Corp.
Triton Energy Corp.
Wainco Oil Corp.
Unweighted Company Average1
1981
6.1
9.1
MM
3.4
5.4
16.4
NM
2.1
10.8
8.0
14.9
NM
NM
10.2
9.6
2.9
NM
5.8
1982
5.0
6.8
NM
2.7
2.5
13.0
1.3
1.6
4.7
4.5
10.5
NM
NM
5.9
6.3
0.7
NM
3.9
1983
3.7
4.9
3.4
3.0
3.0
7.9
0.8
3.5
5.6
3.8
3.3
9.2
NM
2.7
11.1
7.4
0.9
4.4
1984
4.2
6.3
3.4
4.7
2.5
3.5
1.7
3.4
7.1
1.8
2.4
0.5
2.4
2.2
2.9
5.4
0.2
3.2
1985
1.8
4.3
2.7
NM
2.9
3.0
2.3
NM
0.7
2.3
1.8
2.5
1.6
NM
1.6
NM
NM
1.6
NM - Not meaningful, negative net income, or company not yet
formed.
Source: "Oil, Basic Analysis," Standard and Poor's Industry
Surveys, November 27, 1986.
'Simple average calculated from the ratios of the sample.
3-39
-------
TABLE 3-22
CURRENT RATIO
INDEPENDENT OIL COMPANIES IN ERG 17-COMPANY SAMPLE
Apache Corp.
Cabot Corp.
Conquest Exploration
Damson Oil
Hamilton Oil Corp.
Helmerich & Payne
Howe 11 Corp.
Lear Petroleum Corp.
LA Land & Exploration
Mitchell Energy & Dev.
Noble Affiliates, Inc.
Pauley Petroleum
Plains Resources , Inc .
Pogo Producing
Sabine Corp.
Triton Energy Corp.
Wainco Oil Corp.
Unweighted Company Average*
1981
3.4
2.2
NA
1.1
1.9
1.4
1.3
1.5
1.4
1.2
1.0
1.4
1.9
1.1
0.9
1.8
1^3
1.5
1982
1.7
2.2
1.1
1.3
1.7
1.7
1.1
1.3
1.1
1.0
1.2
1.3
0.8
1.2
1.6
1.4
0^8
1.3
1983
1.5
2.6
1.4
1.4
1.4
3.5
1.2
1.2
1.1
1.0
1.5
1.3
1.0
0.9
1.7
1.0
1^1
1.5
1984
1.2
1.8
1.0
1.3
1.4
3.3
1.1
1.1
1.1
1.0
1.2
1.1
0.9
1.0
1.2
2.4
i.1
1.4
1985
1.1
1.9
0.7
1.0
1.2
4.6
1.0
0.8
1.1
1.1
1.3
1.2
0.7
1.2
2.3
2.1
1*2
1.4
NA - Not available.
Source: "Oil, Basic Analysis," Standard and Poor's Industry
Surveys, November 27, 1986.
'Simple average calculated from the ratios of the sample.
3-40
-------
TABLE 3-23
DEBT/CAPITAL RATIO (%)
INDEPENDENT OIL COMPANIES IN ERG 17-COMPANY SAMPLE
Apache Corp .
Cabot Corp .
Conquest Exploration
Damson Oil
Hamilton Oil Corp.
Helmerich & Payne
Howell Corp.
Lear Petroleum Corp.
LA Land & Exploration
Mitchell Energy & Dev.
Noble Affiliates, Inc.
Pauley Petroleum
Plains Resources ,. Inc .
Pogo Producing
Sabine Corp.
Triton Energy Corp.
Wainco Oil Corp.
Unweighted Company Average*
1981
42.6
26.3
NA
55.7
23.2
22.6
7.7
67.2
27.1
54.4
22.1
69.1
1.0
43.7
30.6
36.2
61.3
34.8
1982
42.4
24.6
57.1
54.2
21.1
20.1
6.0
74.1
25.6
52.4
19.8
82.9
29.3
48.1
31.9
46.9
78.6
42.1
1983
32.6
23.1
4.2
56.3
29.2
16.7
14.3
63.9
36.6
49.6
17.4
66.3
69.3
47.9
5.8
25.8
21.1
37.3
1984
19.6
27.3
15.8
53.3
49.3
15.4
39.8
59.1
34.8
50.0
15.8
58.7
72.2
46.0
11.5
42.7
67J,
39.9
1985
25.3
33.5
22.4
49.2
47.9
14.9
30.9
66.7
31.7
48.1
19.3
51.9
46.3
63.0
12.2
42.3
68.1
39.6
NA - Not available.
Source: "Oil, Basic Analysis," Standard and Poor's Industry
Surveys, November 27, 1986.
'Simple average calculated from the ratios of the sample.
3-41
-------
in 1985 (Table 3-21). The impact of falling oil prices is clearly evident
from these tables.
The Current Ratio data for ERG's sample of independents shown in Table 3-
22 exhibits no clear overall trend. It has hovered at approximately 1.4 for
the period shown. From 1981 to 1985, the Current Ratio for independents was
higher than that for the majors. This indicates that the independents are
financing exploration and capital expenditures with debt rather than working
capital.
One reason the independents need greater liquidity is their increasing
reliance on debt financing since debt covenants usually include minimum
Current Ratio values. The Debt/Capital ratio hovers around 39 percent for
independents (Table 3-23) compared to 26 percent for the majors (Table 3-18).
3.4 FINANCIAL PROFILES OF "TYPICAL" COMPANIES
This section reviews in more detail the performance trends and financial
conditions of the two primary groups engaged in offshore petroleum development
by presenting financial profiles of a "typical" major integrated company and a
"typical" independent company. The financial profiles for majors are
presented for selected years from 1973 to 1986. For independents, a time
period of 1980- 1985 is used. To provide a basis for this analysis, financial
data for six randomly selected major integrated companies1 and three
independent oil companies2 (chosen on the basis of an examination of Fennwell
Maps of offshore producers) were averaged to produce financial statements for
"typical" companies. Thus, these averages reflect the relative size of the
companies in the two samples. The "typical" profiles will be used in Section
Seven to illustrate the potential impacts of the NSPS regulations on the two
major categories of industry participants.
JARCO (Atlantic Richfield), Exxon, Mobil, Shell (Royal Dutch Petroleum),
Standard Oil of Indiana (Amoco), and Texaco.
2Inexco Oil, Sabine Corporation and Pogo Producing.
3-42
-------
3.4.1 Financial Profile of "Typical" Majors
Balance sheets and income statements of a "typical" major integrated oil
company were prepared from the sample data. These statements are shown in
Tables 3-24 and 3-25. These financial statements were then used to develop
the series of performance indicators shown in Table 3-26. The more important
points concerning the financial performance and condition of the "typical"
maj or are:
1. Profitability peaked in 1980 and has declined slowly thereafter as
shown by the return on assets and return on equity values.
2. Working capital declined after 1980, with a negative net working
capital shown in 1985; The current ratio (the ratio of current assets
to current liabilities) fell from 1.53 in 1973 to 0.93 in 1985 before
recovering somewhat in 1986.
3. Despite the ambitious capital spending program of the "typical" major,
both the long-term debt-to-equity and debt-to-capital ratios actually
declined from 1976 to 1982, indicating that the "typical" major was not
acquiring debt to finance its capital spending program. Apparently,
the effect of large increases in exploration and capital expenditures
fell more heavily on the major's working capital or equity financing
than it did on the level of debt financing.
This situation changed markedly in 1984 and 1985 when both the long-term
debt-to-equity and debt-to-capital ratios jumped 9 percent and 54 percent from
1983 levels respectively. The majors are becoming increasingly leveraged in
response to or as a result of recent corporate takeover actions.
3.4.2 Financial Profile of "Typical" Independents
Financial Performance of a "Typical" Independent
A balance sheet and income statement of a "typical" independent oil
company for the years 1980-1985 are provided in Tables 3-27 and 3-28. These
financial statements were then used to develop the series of performance
indicators in Table 3-29. Data for 1986 were not developed because one of the
three independents analyzed (Inexco) was acquired by the Louisiana Land and
Exploration Company during 1986, and ceased publishing financial data. The
"disappearance" of Inexco is emblematic of the financial difficulties which
have beset independents since oil and natural gas prices started to slide in
the early 1980s. Firms have been trapped by the need to finance aggressive
exploration and development programs while their annual revenues have
3-43
-------
TABLE 3-24
BALANCE SHEET FOR A TYPICAL" MAJOR INTEGRATED OIL COMPANY
(IN MILLIONS OF CURRENT DOLLARS)
Assets
Current Assets
Property, Plant and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
u Long -Term Debt
I
* Other Liabilities*
Total Liabilities
Shareholder's Equity
Total Liabilities
and Net Worth
1973
3,841
6,499
80S
11,145
2,506
1.463
883
4,852
6.293
11.145
1976
6.435
9.135
1.296
16.866
4.706
2.377
1.457
8.540
8.326
16.866
1978
7,330
11,428
1.411
20,169
5.495
2.620
2.494
10.609
9.560
20,169
1980
10.609
16,013
1.728
28,350
8,229
3.064
4.402
15.695
12.655
28.350
1981
10.610
18.450
2.049
31.109
8.488
3.385
5.115
16.988
14.121
31.109
1982
9.332
20,445
2.412
32.189
7.717
3.414
6.228
17.359
14,830
32,189
1983
8.931
21.377
2.440
32.748
7,335
3.972
5.974
17.280
15.468
32.748
1984
8.665
24,323
2.727
35.715
8.001
6.180
6.437
20.619
15.096
35.715 .
1985
8.903
25,145
2.722
36.770
9.529
5.652
6.916
22,097
14.673
36.770
1986
8.337
24,799
2.758
35.893
7.536
5.443
7.600
20.579
15.314
35.893
"Other liabilities Include: deferred Federal and foreign income taxes, deferred revenue, production payments, and other
medium-term commitments.
Source: Annual Reports for ARCO, Exxon, Mobil. Shell. Standard Oil of Indiana (Amoco), Texaco. Component Items may not add to
totals due to rounding. Balance sheet items for "typical* company are calculated by single averaging of balance sheet
items for the six major integrated oil companies in the sample.
-------
TABLE 3-25
INCOME STATEMENT FOR A TYPICAL" MAJOR INTEGRATED OIL COMPANY
(IN MILLIONS OF CURRENT DOLLARS)
Revenues
^ Expenses
1
*| Depletion,
Depreciation, and
Amortization
Income Before
Income Taxes
Income Taxes
Net Income
1973
11.624
9,438
554
2,186
1.236
950
1976
23
20
2
1
1
.134
.139
735
,995
,893
.102
1978
28,633
25,334
951
3.299
2,060
1.239
1980*
49,795
44,672
1,328
5,123
2,537
2,586
1981
54,170
49.502
1.592
4.668
2.191
2.477
1982
48,861
45.093
1.774
3.768
1.776
1,992
1983
44,902
37.824
1.958
7.078
4,951
2.127
1984
46,802
39,701
2,440
7.101
5.164
1.937
1985
45.570
38.741
2.541
6.829
5.072
1.757
1986
35,395
29,430
2,630
5,965
4,343
1.623
'Excludes extraordinary Income related to sale of an oil company.
Source: Annual Reports for ARCO, Exxon, Mobil, Shell, Standard Oil of Indiana, Texaco. Component Items may not add to
totals due to rounding. Income statement items for "typical" company are calculated by averaging Income statement
Items for the six major integrated oil companies in the sample.
-------
TABLE 3-26
FINANCIAL RATIO AND PERFORMANCE INDICATORS FOR A "TYPICAL" MAJOR INTEGRATED OIL COMPANY
1
4k
01
RATIOS AND PERFORMANCE INDICATORS
Net Working Capital ($M)
Current Ratio
Long -Term Debt to Equity Ratio (%)
Debt to Capital Ratio («)
Return on Year -End Assets (%)
Return on Year-End Equity (%)
Return on Revenues(%)
1973
1.335
1.53
23.2
16.6
8.5
15.1
8.2
1976
1.729
1.37
28.5
18.2
6.5
13.2
4.8
1978
1.835
1.33
27.4
17.4
6.1
13.0
4.3
1980
2,380
1.29
24.2
14.7
9.1
20.4
5.2
1981
2.122
1.25
24.0
15.0
8.0
17.5
4.6
1982
1.615
1.21
23.0
15.1
6.2
13.4
4.1
1983
1.597
1.22
25.7
17.4
6.5
13.8
4.7
1984
664
1.08
40.9
26.8
5.4
12.8
4.1
1985
(626)
0.93
38.5
23.4
4.8
12.0
3.9
1986
801
1.11
35.5
23.8
4.5
11.1
3.6
Source: ERG estimates.
-------
TABLE 3-27
BALANCE SHEET FOR A "TYPICAL" INDEPENDENT OIL COMPANY
(Millions of Current Dollars)
Assets
Current Assets
Property, Plant and
Equipment (net)
Other Assets
TOTAL ASSETS
Liabilities
Current Liabilities
Long-term Debt
Other Liabilities
TOTAL LIABILITIES
Shareholder's Equity
TOTAL LIABILITIES AND
NET WORTH
1980
55
387
5
447
52
148
46
247
200
447
1981
87
543
5
635
82
246
73
401
233
635
1982
71
647
4
722
64
311
102
477
245
722
1983
55
613
4
671
51
269
139
459
212
671
1984
55
626
4
686
47
280
152
479
207
686
1985
53
528
3
583
49
268
108
424
159
583
Source: Annual reports for Inexco, Pogo Producing, and Sabine. Component
items may not add to totals due to independent rounding. Balance
sheets for "typical" company are calculated by simple averaging of
balance sheet items for three independent oil companies.
3-47
-------
TABLE 3-28
INCOME STATEMENT FOR A "TYPICAL" INDEPENDENT OIL COMPANY
(Millions of Current Dollars)
Revenue
Expenses
Depletion, Depreciation,
and Amortization
Income Before Taxes
Net Income
Domestic Exploration and
Development Expenditures'
1980
164
106
51
58
34
193
1981
236
163
65
73
42
187
1982
231
181
75
50
31
173
1983
172
133
71
39
24
101
1984
179
176
71
3
3
105
1985
161
239
69
(78)
(41)
69
Source: Annual reports for Inexco, Fogo Producing, and Sabine. Component
items may not add to totals due to independent rounding. Balance
sheets for "typical" company are calculated by simple averaging of
balance sheet items for three independent oil companies.
'Defined as sum of property acquisition, exploration, and development
expenditures.
3-48
-------
u>
I
TABLE 3-29
FINANCIAL RATIOS AND PERFORMANCE INDICATORS FORA
TYPICAL" INDEPENDENT OIL COMPANY
RATIOS AND
PERFORMANCE INDICATORS
Net Working Capital ($M)
Current Ratio
Long-Term Debt to Equity
Ratio (%)
Debt to Capital Ratio (%)
Return on Year-End Assets (%)
Return on Year -End Equity (%)
Return on Revenues (%)
1980
3
1.05
74.2
58.8
7.6
17.0
20.7
1981
5
1.06
105.4
77.9
6.6
18.0
17.8
1982
7
1.12
127.2
101.0
4.3
4.3
9.1
1983
3
1.06
126.9
102.2
3.6
11.3
14.0
1984
9
1.19
135.3
110.4
0.4
1.4
1.7
1985
4
1.08
168.3
128.7
NM
NM
NM
NM - Not meaningful, negative net income for 1985.
Source: ERG estimates.
-------
declined; an unprecedented volume of merger and takeover activity has been the
direct result.
The most important points about the financial performance and condition of
the "typical" independent are:
1. Profitability results were mixed over the period. From 1976 through
1981, net income and return on equity increased. In 1982, net income,
return on equity, and return on assets began to decrease until they
reached 1985 levels with a negative net income.
2. The current ratio, which greatly declined in the early eighties from
the seventies, rose slightly in 1982 and 1984. Working capital
fluctuates during 1980-1985 period.
3. Both the long-term debt-to-equity and debt-to-capital ratios in the
mid- 1980's climbed substantially from 1980 values. The amount of
long-term debt increased 80 percent from 1980 to 1985. Clearly, the
"typical" independent used a large amount of debt financing to fund its
exploration and development programs, leaving it in a much more highly
leveraged position in 1985 than in 1980, and substantially higher than
the maj ors.
3.43 Financial Comparisons Among "Typical" Oil Companies
This section uses the data developed in the previous sections as the basis
for comparing the financial performance and condition of "typical" majors and
independents. These comparisons will provide insight into the potential
financial problems the different types of oil companies have faced or may face
in the future.
Profitability
From 1980 through 1985, the typical major performed consistently better
than the typical independent with respect to higher returns on equity and
assets, yet the independent made more on each dollar of revenue than did the
major as shown by the Profitability index (returns or revenues, see Table 3-
30). From 1980 to 1984, return on assets declined 7.2 percentage points for
the independent versus 3.7 percentage points for the major. For the same
period, return on equity fell 15.6 percentage points for the independent as
opposed to only a 7.6-point drop for the major.
The effects of reduced demand and lower wellhead prices can be clearly
seen in drop in profitability for both major and independent companies.
Majors reduced capital and exploration expenditures after 1982, due to
3-50
-------
TABLE 3-30
PROFITABILITY COMPARISONS BETWEEN "TYPICAL" OFFSHORE OIL COMPANIES
Ul
1
Ul
I-"
Return on Year-End Assets (%)
Major Integrated Company
Independent Company
Return on Year-End Equity (%)
Major Integrated Company
Independent Company
Return on Revenues (%)
Major Integrated Company
Independent Company
1980
9.1
7.6
20.4
17.0
5.2
20.7
1981
8.0
6.6
17.5
18.0
4.6
17.8
1982
6.2
4.3
13.4
4.3
4.1
9.1
1983
6.5
3.6
13.8
11.3
4.7
14.0
1984
5.4
0.4
12.8
1.4
4.1
1.7 .
1985
4.8
NM
12.0
NM
3.9
NM
NM - Not meaningful, negative net income in 1985.
Source: ERG estimates.
-------
dropping demand and price (see Sections 3.2.1 and 3.2.2). The lower crude
prices in 1985 cut refining and chemical feedstock costs for the downstream
operation of the majors. Lower crude prices lead to losses on upstream
operations. For the majors, downstream savings offset upstream losses.
Independents have no downstream operations to mitigate the financial detriment
caused by lower crude prices on upstream operations. In addition,
independents are more highly leveraged than the majors, and the drop in oil
prices devalues their proven reserves, thereby creating pressure to pay back a
portion of their long-term debt.
Liquidity
The typical major relied more heavily on working capital rather than
outside borrowings to finance its capital and exploration expenditures from
1980 to 1985. The level of working capital fell during this period and the
current ratio dropped from 1.29 in 1980 to 0.93 in 1985 (Table 3-31). The
"typical" independent saw its current ratio fluctuate between 1.05 and 1.19
during 1980- 1985. The overall financial strength of the majors relative to
the independents is evident by the way they have maintained higher levels of
profitability than independents in a declining oil-price market. The major
can usually borrow in the short term and raise funds with relative ease.
Therefore, the majors' current ratios can be less than the independents' and
still be considered healthy. Yet the current ratio for independents tends to
be lower than that for the majors during the 1980-1985 period.
Leverage
The independent companies are more highly leveraged than the major
companies especially in the 1980's. Data relating to past and existing
capital structures are summarized in Table 3-32.
As most oil companies embarked on ambitious exploration and capital
spending programs in the early 1980's, the independents financed these
programs primarily through the issue of long-term debt. As can be seen for
the period 1980 to 1982, the long-term debt-to-equity ratio had actually
declined for the typical major, in contrast to an increase of almost 50
percent for the typical independent. In 1985, the Debt/Equity Ratio was 5.5
times as high for the typical independent as for the major. The Debt/Capital
Ratio parallels the long- term Debt/Equity Ratio.
3-52
-------
TABLE 3-31
1980 1981 1982 1983
Current Ratio
Major Integrated Company 1.29 1.25 1.21 1.22
Independent Company 1.05 1.06 1.12 1.06
Change in Working Capital
Capital (%)
Major Integrated Company -- -0.1 -0.2 0.0
Independent Company -- 0.7 0.4 -0.6
1984 1985
1.08 0.93
1.19 1.08
-0.6 NM
2.0 -0.6
NM - not meaningful, negative net working capital in 1985.
Source: ERG estimates.
3-53
-------
OFFSHORE OIL COMPANIES
1980
1981
1982
1983
1984
1985
Lone-Term Debt to Eauity Ratio (%)
Major Integrated Company
Independent Company
24.2
74.2
24.0
105.4
23.0
12.7 . 2
25.7
126.9
40.9
135.3
38.5
168.3
Debt to Capital Ratio (%)
Major Integrated Company
Independent Company
Equity to Total Assets (%)
Major Integrated Company
Independent Company
14.7
58.8
44.6
44.7
15.0
77.9
45.4
36.7
15.1
101.0
46.1
33.9
17.4
102.2
47.2
31.6
26.8
110.4
42.3
30.2
23.4
128.7
39.9
27.3
Source: ERG estimates.
3-54
-------
The other data in Table 3-32 serve to amplify this observation. Equity to
total assets is a measure of how soundly capitalized is the company. The
higher the proportion of equity, the greater is its buffer against short-term
losses, and the greater is its ability to take on more debt to finance future
expenditures. The data show that this ratio improved somewhat for the
"typical" major from 1980 to 1983, in spite of large exploration and capital
expenditure programs. In contrast, the ratio has declined steadily for the
typical independent from 1980 to 1985.
Growth and Spending
The major and independent companies were also compared in terms of revenue
growth and expenditure programs. Table 3-33 displays these comparisons.
The recent spending programs of the majors were less sensitive to price
and demand fluctuations than the independents' programs since the majors need
to keep the product pipeline filled. The majors, as part of their long-range
production and reserve acquisition plans, attempt to maintain relative
stability in their exploration spending goals and have more financial
flexibility to vary their sources of funds. The relative volatility of the
independents' plans is increased by their more highly leveraged positions. In
a downturn, the independents must reduce expenditures more sharply in order to
limit further new debt-financing costs.
Another comparison is the difference in exploration and development
expenditures as a percent of total revenues. Independents are more focused on
domestic exploration and development (although a few have diversified into
overseas development, refining, pipelines, and other minerals). This fact is
apparent in the data shown. Domestic exploration and production expenditures
as a percent of revenues for the "typical" major between 1980 and 1982 ranged
between 8.5 and 11 percent. In contrast, the percentage for the "typical"
independent ranged between 42.9 and 118 percent.
3-55
-------
I
Ul
o\
TABLE 3-33
GROWTH AND SPENDING COMPARISONS
BETWEEN "TYPICAL" OFFSHORE OIL COMPANIES
1980 1981 1982 1983
Growth in Domestic Oil and Gas
Exploration and Development
Expenditures (Capitalized and
Expensed) (%)
Major Integrated Company -- 8.0 3.3 -22.1
Independent Company -- 3.11 -7.49 -41.62
Change in Total Revenues (%)
Major Integrated Company -- 8.8 -9.8 -8.1
Independent Company -- 43.9 -2.1 -25.5
Domestic Oil and Gas Exploration
and Development Expenditures as
a Percent of Total Revenues (%)
Major Integrated Company 8.5 9.8 11.0 9.8
Independent Company 117.7 79.2 74.9 58.7
1984 1985
9.2 3.5
3.96 -34.29
4.2 -2.6
4.1 -10.1
10.3 11.0
58.7 42.9
Source: ERG estimates.
Note: All values calculated from current dollar data.
-------
3.5 FINANCIAL CONDITION IN 1986 AND FUTURE OUTLOOK
3.5.1 1986 Financial Performance
The analysis can be updated further using recent financial reports. Net
income for 25 large U.S. oil companies during 1986 was down 33.4 percent from
1985. The continued fall of oil and gas prices caused a 23.9 percent decline
in group revenues in 1986. Capital and exploration outlays were down 33.4
percent from the 1985 levels. The main reasons are lower oil prices, write
downs of assets and continued restructuring for these companies. The drop in
revenues occurred mainly in upstream operations, while downstream earnings
were up for most companies in the group. Lower crude prices reduce refining
and chemical feedstock costs, thereby increasing earnings from downstream
operations.1
Prospects for the future are mixed. On the plus side, 1986 saw an
increase in demand for petroleum products, and demand increased again in
1987.2 The uncertainty about tax reform is over, and the industry did not
fare as poorly as it had feared.3 Oil and natural gas prices stabilized
during 1987. Uorld production continues to exceed demand, however, so prices
are unlikely to rise significantly in the short term." Continued low prices
should foster additional demand growth, which in turn should pull prices
higher, but this effect may not occur for several years. For companies with
downstream operations, continued lower oil prices will benefit earnings from
those operations, particularly if demand goes up. For independents, with no
downstream operations, the short-term outlook is not very positive.
3.5.2 Future Strategy for the Majors
The realization that they are faced with a declining demand trend has led
the major oil companies to make major adjustments to spending strategies since
1981. Companies have redirected their focus from long-term plans designed to
'Oil and Gas Journal. May 25, 1987.
foil and Gas Journal. January 25, 1988.
3"0il, Basic Analysis," Standard and Poor's Industry Survey, November 27,
1986.
40il and Gas Journal. January 25, 1988.
3-57
-------
maximize asset values to concentrating more on increasing short-run cash
flows. An Oil and Gas Journal article reports that since 1981, companies have
streamlined operations by cutting payrolls, reducing surplus refining
capacity, and halting marketing operations in areas of marginal value. Many
companies have reduced debt and sold assets with little short-term potential
for revenue.1 Following an average 44.6 percent drop from 1985 to 1986,
capital and exploration expenditures declined an additional 5.6 percent in
1987. With stabilizing oil and gas prices, however, most producers plan to
expand development and exploration activity in 1988.2
A number of factors have combined to create a mixed environment for major,
integrated firms. Many firms diversified in the late 1970's and early 1980's.
By the mid 1980's, many of these diversifications have been either shut down,
spun off to shareholders, or written down (e.g., synfuels). The takeover
activity of recent years has also led to the majors becoming increasingly
financially leveraged.3 Low oil prices have resulted in drastic cutbacks in
exploration and development activity, essentially since it has been less
expensive for the majors to increase oil imports than to locate and develop
new resources. The curtailment of exploration programs has been reflected
graphically in the lack of interest in recent DCS lease sales, and in the very
low bids offered for Federal OCS lease tracts (see Table 2-2).
With rising demand, rising oil imports, and a severely depressed domestic
exploration program, the U.S. may have prepared the ground for another "oil
crisis" in coming years. The financially strong companies are in a position
to obtain productive properties from financially distressed companies and to
be in an excellent position when the seller's market returns; weaker companies
may need to sell off assets or merge with financially stronger companies.
3.53 Future of the Independents
The financial outlook for the independent oil companies is less optimistic
than that for the majors. Many independents borrowed heavily in recent years
in order to finance new operations. In doing so they essentially mortgaged
'Oil and Gas Journal. February 28, 1983.
20il and Gas Journal. March 28, 1988.
J"0il, Basic Analysis," Standard and Poor's Industry Surveys, November
27, 1986.
3-58
-------
their future against crude oil and natural gas reserves, expecting that the
value of these reserves would steadily increase. Until late in 1981, it was
common practice for companies and commercial lenders to assume that the price
of crude would increase significantly faster than inflation during the term of
any loan. This meant that the value of oil and gas reserves used to secure
debt was set at a higher amount for loan purposes than their actual market
values. Borrowing was done on the assumption that higher crude prices in the
future would cover the debt accrued in the present.
When the price of crude oil fell and demand for natural gas slumped, the
calculated market value of the reserves fell. Lenders found themselves with
loans that were not completely secured by reserve values, and asked for
partial loan repayments or increased collateral. This put the independents in
the position of having to pay back both principal and interest on their loans
at a time of reduced earnings and cash flow, resulting in the failure of some
small independents.
In addition to financing troubles, the independents have other problems.
In general, independents have traditionally concentrated much more on natural
gas production than oil, and the prospects for recovery in the oil segment are
brighter than for gas. Those independents which have provided contract
drilling services are also suffering from a low rig utilization rate. The
utilization rate, which peaked at 98 percent in 1981, had fallen to under 40
percent in March of 1983.' The number of active rigs peaked at 3,974 in 1981;
1986 saw an average of 965 active rigs per week.2 For many independents, idle
rigs represent a significant amount of depreciating capital tied up with no
economic use and little collateral value.
The impact of these conditions on the growth and survival of firms within
the industry has been mixed. Many small firms have gone bankrupt or have been
purchased by stronger companies in the past year. Other producers are
attempting to restructure debts, sell assets, or merge with other companies.
Independents who are financially secure are in a good position to grow
stronger by acquiring acreage from other independents at bargain prices.
Onshore production costs have also declined sharply due to the slack in demand
for oil field services and equipment.
'Oil and Gas Journal. April 4, 1983; "Oil, Basic Analysis," Standard and
Poor's Industry Survey, November 27, 1986.
'Oil and Gas Database, Hughes Rig Count, 1970-1986, requested March 1987.
3-59
-------
In summary, the financial position of most independents will prohibit them
from participating at the same level in exploration and development programs
as they did in 1979-1981. If the independent is in the position to consider
development at all, it will more likely focus on development onshore rather
than offshore. Most independents are in a financially weaker condition than
the maj ors.l
'"Oil, Basic Analysis," Standard and Poor's Industry Surveys, November
27, 1986.
3-60
-------
SECTION FOUR
WELL AND PLATFORM PROJECTIONS
This section presents projections of offshore oil and gas activity for the
1986-2000 time period. These projections are used in later sections to
calculate total costs of the alternative regulatory approaches for BAT and
NSPS. The projections presented below begin with the Minerals Management
Service (MMS) production projections (Section 4.1) which serve as a basis for
the well projections (Section 4.2). The MMS projections are presented for
three oil price variations: $15/bbl, $21/bbl, and $32/bbl. From these
forecasts, ERG developed two different platform projections: an unrestricted
development scenario (Section 4.3) and a restricted development scenario
(Section 4.4).1 Finally the projections are summarized in Section 4.5. In
Sections 4.1 and 4.2, tables labeled "a" (i.e., 4-la) refer to the $32/bbl,
tables labeled "b" refer to the $21/bbl scenario, and tables labeled "c" refer
to the $15/bbl scenario. The oil prices are in 1986 dollars.
The forecasts of Federal water activity are based on MMS production
projections. The State water forecasts are based on an analysis of State
water activity from 1980-1985 for the Pacific and Alaskan regions and 1967-
1985 for the Gulf region. Together these forecasts make up the unrestricted
development scenario which represents the high end of expected offshore
activity during the 1986-2000 time period (i.e., all resources that are
economically feasible to be developed will be.) A restricted development
scenario has been created based upon the same MMS projections, but altered to
account for recent moratoria on offshore oil and gas leasing and development
in the Pacific and Atlantic regions. This projection represents the lowest
case scenario of the amount of offshore activity that will be occurring from
1986-2000.
Based upon the two patterns of development and three alternative oil
prices, ERG analyzed four alternative scenarios:
'The terms "unrestricted" and "restricted" as used throughout this report
correspond to "unconstrained" and "constrained" as used in the preamble to the
proposed rulemaking.
4-1
-------
Unrestricted development:
- $21/bbl
- $32/bbl (This represents the high.end of development.)
Restricted development:
- $21/bbl
- $15/bbl (This represents the low end of development.)
This approach assures that the entire range of potential regulatory costs have
been addressed.
4.1 PROJECTED OCS OIL AND GAS PRODUCTION, 1986-2000
4.1.1 MMS Projections
The OCS forecast was developed using the MMS 30-year projections of oil
and gas production (MMS, 1985a). MMS developed this forecast from data in its
Environmental Impact Statement for the Proposed 5-Year Outer Continental Shelf
Oil and Gas Leasing Program Mid-1987 to Mid-1992 (MMS, 1986). In that report,
MMS estimated "conditional resources" for 21 OCS regions, assuming a market
value of $32 per barrel of oil. These conditional resources represent the
mean amount of oil and gas reserves that are economically recoverable from the
leased areas, given that exploration confirms the presence of hydrocarbon
reserves. The probability of finding reserves varies from region to region.
An estimate of the resources expected to be developed in each leased area can
be obtained by multiplying the probability of finding reserves (estimated by
MMS) by the conditional resource estimates. Using this risked resource
estimate, and rules of thumb regarding the amount of time it takes to develop
the resources in each area, MMS has developed a schedule of resource
production for the mid-1987 to mid-1992 lease sale.
To develop the full 30-year projections at $32 per barrel, MMS utilized
its estimates of the percentage of undeveloped resources to be leased during
each of its subsequent leasing periods. For example, if 25 percent of
Alaska's resources are expected to be leased in 1987-1991, and 25 percent of
Alaska's resources are to be leased in 1992-1996, then the resource
projections for the 1992-1996 period would replicate the resource projections
from the 1987-1991 period, with a 5-year lag. If 50 percent of Alaska's
resources were to be leased in 1992-1996, then the projections would be double
those for the 1987-1991 period.
4-2
-------
Based on this methodology, MMS has published 30-year projections of DCS
oil and gas production for four major regions: the Atlantic, Gulf of Mexico,
Pacific, and Alaska. These projections were selected for this analysis for
the following reasons. First, the MMS forecast is based on a disaggregated
analysis of risked resource potential and lease sale activity in each of the
four regions. Second, the forecast extends to 2015; many forecasts do not
extend beyond 1995. This report is concerned with the period 1986-2000; the
use of actual projections for 1995-2000 increases their accuracy. Finally,
the MMS forecast is easily amenable to different price scenarios. In its
Secretarial Issue Document (SID), MMS developed alternative leasable resource
estimates for various prices.2 Based on these resource estimates, the ratio
of resources at $21 to $32 per barrel, and $15 to $32 per barrel are as
follows:
Ratio of Ratio of
$21/bbl to $15/bbl to
$32/bbl $32/bbl
Region Resources Resources
Gulf 0.965 0.858
Pacific 0.790 0.541
Atlantic 0.514 0.327
Alaska 0.098 0.0
These ratios mean, for example, that using the MMS resource estimates for the
Pacific OCS at $32 per barrel (i.e., MMS projections at $32 per barrel equal
100 percent), the Agency estimates that 79 percent of these Pacific resources
would be developed if the price of oil fell to $21 per barrel. Similarly, if
the price fell from $32 to $15 per barrel, the Agency projects that it would
make economic sense for the oil and gas industry to develop 54.1 percent of
these Pacific resources. These ratios were used to develop alternative
forecasts from the $32 per barrel forecast.
Table 4-1 presents the MMS production projections. Table 4-la, the $32
scenario, was derived from the 30-year forecast developed by MMS. OCS oil
production for 1990 is estimated at 1.2 million barrels per day. Gas
production for 1990 is estimated at 3.5 trillion cubic feet. Table 4-lb was
developed by ERG based upon Table 4-la and the ratios developed from MMS's
Secretarial Issue Document. As shown in Table 4-lb, oil production in 1990 is
approximately 10 percent lower under the $21 scenario than the $32 scenario.
Gas production is approximately 4 percent lower under the $21 scenario than
2See MMS 1987, Appendix F, p. F-75. The oil prices in the SID are in
$1984 and are listed as $14, $19, and $29 scenarios. ERG estimated 1986
prices based on world oil prices, a 5 percent inflation rate, and a 1 percent
real growth rate to obtain the $15, $21, and $32 scenarios, respectively.
4-3
-------
TABLE 4-la
MMS FEDERAL PCS MODEL OUTPUTS;
TOTAL 1990. 1993. 1995. AND 2000 PRODUCTION
($32/bbl of oil - 1986 dollars)
GAS PRODUCTION
OIL PRODUCTION (TRILLIONS OF CUBIC
( BARRELS PER DAY) FEET PER YEAR)
REGION 1990
Gulf of Mexico 822,000
Pacific 356,000
Atlantic 0
Alaska 0
Total 1,178,000
1993 1995 2000 1990 1993 1995 2000
836,000 882,000 877,000 3.36 3.15 3.22 3.2
411,000 425,000 370,000 0.14 0.21 0.24 0.31
68,000 55.000 41,000 0 0.41 0.31 0.24
0 96,000 384,000 0 0 0.07 0.21
1,315,000 1,458,000 1,672,000 3.5 3.77 3.84 3.96
Source: 30-Year Projections of Oil and Gas Production from the United States Outer Continental Shelf Areas,
as transmitted by Chief, Offshore Resource Evaluation Division, MMS, to Associate Director for
Offshore Minerals Management, December 2, 1985. The MMS data were provided in a graphic format.
The numeric amounts were then estimated by ERG.
-------
TABLE 4-lb
MMS FEDERAL PCS MODEL OUTPUTS;
4*
I
01
TOTAL 1990. 1993. 1995. AND 2000 PRODUCTION
($21/bbl of oil - 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY)
REGION 1990 1993 1995 2000
Gulf of Mexico 793,000 807,000 851,000 846,000
Pacific 281,000 325,000 336,000 292,000
Atlantic 0 35,000 28,000 21,000
Alaska 0 000
Total 1,074,000 1,167,000 1,224,000 1,197,000
Source: ERG estimates based upon the MMS Secretarial Issue Document,
GAS PRODUCTION
(TRILLIONS OF CUBIC
FEET PER YEAR)
1990 1993 1995
3.24 3.04 3.11
0.11 0.17 0.19
0 0.21 0.16
0 0 0.01
3.35 3.42 3.47
Final Draft, Appendix F, p.
2000
3.09
0.24
0.12
0.02
3.47
F-75, 1986
and the 30-Year Projections of Oil and Gas Production from the United States Outer Continental
Shelf Areas, as transmitted by Chief, Offshore Resource Evaluation Division, MMS, to Associate
Director for Offshore Minerals Management, December 2, 1985.
-------
TABLE 4-lc
MMS FEDERAL PCS MODEL OUTPUTS:
TOTAL 1990. 1993. 1995. AND 2000 PRODUCTION
($15/bbl of oil - 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY)
GAS PRODUCTION
(TRILLIONS OF CUBIC
FEET PER YEAR)
u
1
<3\
REGION 1990
Gulf of Mexico 705,000
Pacific 193,000
Atlantic 0
Alaska 0
Total 898,000
1993
717,000
222.000
22,000
0
961,000
1995
757,000
230,000
18,000
0
1,005,000
2000
752,000
200,000
13,000
0
965,000
1990 1993
2.88 2.70
0.08 0.11
0 0.13
0 0
2.96 2.94
1995
2.76
0.13
0.10
0
2.99
2000
2.75
0.17
0.08
0
3.00
Source: ERG estimates based upon the MMS Secretarial Issue Document. Final Draft, Appendix F, p. F-75, 1986
and the 30-Year Projections of Oil and Gas Production from the United States Outer Continental
Shelf Areas, as transmitted by Chief, Offshore Resource Evaluation Division, MMS, to Associate
Director for Offshore Minerals Management, December 2, 1985.
-------
the $32 scenario. Table 4-lc, the $15 scenario, shows that in 1990 oil
production is 31 percent lower and gas production is 18 percent lower than
under the $32 scenario.
4.1.2 Pre-1986 Production
Pre-1986 production is defined as all production from wells drilled prior
to 1986. Oil and gas wells typically produce at an initial peak level, and
production gradually declines with time. Therefore, in order to calculate
production in years following 1986, the initial rate of production, years at
peak production, and the production decline rate must be specified. To
estimate the production from pre-1986 sources, the following values were
assumed:
Initial Years
Rate of at Peak Decline
Production Production Rate
Oil Production Barrels/Day Years Percent
Gulf 500 2 15
Pacific 900 2 33
Atlantic 1,000 2 ' 15
Alaska 1,960 2 10
Gas Production MMCFD Years Percent
Gulf 4.0 4 15
Pacific 54 22
Atlantic 7.5 8 15
Alaska 15 16 15
The initial rates of production and the number of years at peak production are
based primarily on data presented in a previous report (EPA, 1985). However,
the initial rates of oil production in the Pacific and gas production in the
Gulf are based on data provided by MMS. The decline rates were developed from
several information sources. For example, the MMS projections use a 40
percent decline rate for oil and a 25 percent decline rate for gas in southern
and central California (MMS, 1985b). Field data provided by the Department of
Energy indicated these rates may be high (DOE, 1989). ERG, therefore, lowered
the decline rates to 33 percent and 22 percent for oil and gas, respectively.
In the case of Alaska, MMS used unique decline rates for each year of
4-7
-------
production; the ERG analysis uses 10 percent and 15 percent for oil and gas,
respectively, which are the averages of the MMS decline rates (MMS, 1985b).
Table 4-2 shows the DCS production from pre-1986 sources over time. There
is currently no DCS production in the Atlantic or Alaska regions. In Table
4-2a, pre-1986 oil production declines from 491,000 barrels per day in 1990 to
94,000 barrels per day in 2000. Pre-1986 gas production declines from 2.48
trillion cubic feet in 1990 to 0.49 trillion cubic feet in 2000. Tables 4-2b
and 4-2c show similar decline patterns for the other two scenarios.
4.13 Future OCS Production from 1986 and Later Sources
Production levels in 1986 and after were developed by subtracting the
pre-1986 sources of production (Table 4-2) from total projected production
(Table 4-1). Table 4-3 illustrates this calculation for total production.
Under the $32 scenario, oil production from wells drilled in 1986 and later
will rise from 687,000 barrels per day in 1990 to 1,578,000 barrels per day in
2000. Gas production will rise from 1.02 trillion cubic feet in 1990 to 3.47
trillion cubic feet in 2000. Tables 4-3b and 4-3c document similar, though
lower, production figures for the $21 and $15 scenarios for 1986 and later.
Table 4-4 shows the 1986 and later sources of production for each of the
four regions. These production amounts were developed in the same manner as
the total 1986 and later production levels shown in Table 4-3.
4.2 FORECAST OF OFFSHORE OIL AND GAS WELLS, 1986-2000
Alternative regulatory approaches for drilling fluids and drill cuttings
affect both productive and unproductive drilling efforts. In order to
distinguish between the two, the number of productive wells in Federal and
State waters are forecast and then the proportion of dry holes is estimated
based on historical data of offshore drilling efforts. The combination of
these forecasts provides the average number of offshore wells drilled for the
1986-2000 time period.
4-8
-------
TABLE 4-2a
PCS PRODUCTION FROM PRE-1986 SOURCES
($32/bbl of oil - 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY}
YEAR
1990
1993
1995
2000
GULF*
480,000
295,000
213,000
94,000
PACIFIC"
11,000
3,000
1,000
0
TOTAL
491,000
298,000
214,000
94,000
GAS PRODUCTION
(TCF/YEAR)
GULF*
2.47
1.52
1.1
0.49
PACIFIC'
0.01
0
0
0
TOTAL
2.48
1.52
1.1
0.49
Source: ERG estimates based upon pre-1986 production levels in the MMS
forecast.
'Calculated using a 15 percent annual decline rate.
"Calculated using a 33 percent annual decline rate.
'Calculated using a 22 percent annual decline rate.
4-9
-------
TABLE 4-2b
PCS PRODUCTION FROM PRE-1986 SOURCES
($21/bbl of oil - 1986 dollars)
OIL PRODUCTION
("BARRELS PER DAY}
YEAR
1990
1993
1995
2000
GULF*
463,000
285,000
206,000
91,000
PACIFIC6
9,000
2,000
1,000
0
TOTAL
472,000
287,000
207,000
91,000
GAS PRODUCTION
CTCF/YEAR)
GULF*
2.38
1.47
1.06
0.47
PACIFIC'
0.01
0
0
0
TOTAL
2.39
1.47
1.06
0.47
Source: ERG estimates based upon pre-1986 production levels in the MMS
forecast.
'Calculated using a 15 percent annual decline rate.
Calculated using a 33 percent annual decline rate.
'Calculated using a 22 percent annual decline rate.
4-10
-------
TABLE 4-2c
PCS PRODUCTION FROM PRE-1986 SOURCES
($15/bbl of oil 1986 dollars)
OIL PRODUCTION
^BARRELS PER DAY}
YEAR
1990
1993
1995
2000
GULF"
412,000
253,000
183,000
81,000
PACIFIC"
6,000
2,000
1,000
0
TOTAL
418,000
255,000
184,000
81,000
GAS PRODUCTION
fTCF/YEAR}
GULF*
2.12
1.30
0.94
0.42
PACIFIC*
0.01
0
0
0
TOTAL
2.13
1.3
0.94
0.42
Source: ERG estimates based upon pre-1986 production levels in the MMS forecast.
'Calculated using a 15 percent annual decline rate.
Calculated using a 33 percent annual decline rate.
'Calculated using a 22 percent annual decline rate.
4-11
-------
TABLE 4-3a
PCS PRODUCTION FROM 1986 AND LATER SOURCES
($32/bbl of oil - 1986 dollars)
OIL PRODUCTION
( BARRELS PER DAY1)
YEAR
1990
1993
1995
2000
TOTAL*
1,178,000
1,315,000
1,458,000
1,672,000
PRE-
1986
SOURCES"
491,000
298,000
214,000
94,000
1986 AND
LATER
SOURCES'
687,000
1,017,000
1,244,000
1,578,000
TOTAL1
3.5
3.77
3.84
3.96
GAS PRODUCTION
CTCF/YEAR)
PRE-
1986
SOURCES"
2.48
1.52
1.1
0.49
1986 AND
LATER
SOURCES'
1.02
2.25
2.74
3.47
Source: ERG estimates.
*MMS projections, see Table 4-1.
"See Table 4-2.
Total production minus pre-1986 production.
4-12
-------
TABLE 4-3b
PCS PRODUCTION FROM 1986 AND LATER SOURCES
($21/bbl of oil - 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY)
YEAR
1990
1993
1995
2000
TOTAL'
1,074,000
1,167,000
1,224,000
1,197,000
PRE-
1986
SOURCES"
472,000
287,000
207,000
91,000
1986 AND
LATER
SOURCES'
602,000
880,000
1,017,000
1,106,000
TOTAL*
3.35
3.42
3.47
3.47
GAS PRODUCTION
(TCP/YEAR)
PRE-
1986
SOURCES'"
2.39
1.47
1.06
0.47
1986 AND
LATER
SOURCES'
0.96
1.95
2.41
3.00
Source: ERG estimates.
MMS projections, see Table 4-1.
"See Table 4-2.
Total production minus pre-1986 production.
4-13
-------
TABLE 4-3c
PCS PRODUCTION FROM 1986 AND LATER SOURCES
($15/bbl of oil - 1986 dollars)
OIL PRODUCTION GAS PRODUCTION
CBARRELS PER DAY) (TCP/YEAR)
PRE- 1986 AND
1986 LATER
YEAR TOTAL1 SOURCES" SOURCES' TOTAL1
1990 898,000 418,000 480,000 2.96
1993 961,000 255,000 706,000 2.94
1995 1,005,000 184,000 821,000 2.99
2000 965,000 81,000 884,000 3.00
PRE- 1986 AND
1986 LATER
SOURCES" SOURCES'
2.13 0.83
1.3 1.64
0.94 2.05
0.42 2.58
Source: ERG estimates.
*MMS projections, see Table 4-1.
"See Table 4-2.
Total production minus pre-1986 production.
4-14
-------
TABLE 4-4a
1986 AND LATER NSPS PRODUCTION
($32/bbl of oil - 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY)
REGION
Gulf of Mexico
Pacific
Atlantic
Alaska
Total
1990
342,000
345,000
0
0
687,000
1993
541,000
408,000
68,000
0
1,017,000
1995
669,000
424,000
55,000
96,000
1,244,000
2000
783,000
370,000
41,000
384,000
1,578,000
GAS PRODUCTION
(TCF/YEAR)
1990
0.89
0.13
0
0
1.02
1993
2.12
0.21
0.41
0
2.74
1995
2.71
0.24
0.31
0.07
3.47
2000
2.33
0.31
0.24
0.21
2.58
Source: ERG estimates developed using Table 4-1 and Table 4-2.
4-15
-------
TABLE 4-4b
1986 AND LATER NSPS PRODUCTION
($21/bbl of oil - 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY)
GAS PRODUCTION
(TCF/YEAR)
REGION
Gulf of Mexico
Pacific
Atlantic
Alaska
Total
1990
330,
272,
602,
000
000
0
0
000
1993
522,000
323,000
35,000
0
880,000
1995
645,
335,
28,
1,017,
2000
000
000
000
0
000
755
292
21
1,106
,000
,000
,000
0
,000
1990
0.86
0.10
0
0
0.96
1993
1.57
0.17
0.21
0
1.95
1995
2.05
0.19
0.16
0.01
2.41
2000
2.62
0.24
0.12
0.02
3.00
Source: ERG estimates developed using Table 4-1 and Table 4-2.
4-16
-------
TABLE 4-4c
1986 AND LATER NSPS PRODUCTION
($15/bbl of oil . 1986 dollars)
OIL PRODUCTION
(BARRELS PER DAY)
GAS PRODUCTION
(TCP/YEAR)
REGION
Gulf of Mexico
Pacific
Atlantic
Alaska
Total
1990
293,
187,
480,
000
000
0
0
000
1993
464,
220,
22,
706,
000
000
000
0
000
1995
574,
229,
18,
821,
000
000
000
0
000
2000
671,000
200,000
13,000
0
884,000
1990
0.76
0.07
0
0
0.83
1993
1.40
0.11
0.13
0
1.64
1995
1.82
0.13
0.10
0
2.05
2000
2.33
0.17
0.08
0
2.58
Source: ERG estimates developed using Table 4-1 and Table 4-2.
4-17
-------
4.2.1 Productive Wells
Federal PCS Well Projections
Once 1986 and later production levels are established, the number of wells
likely to be installed to account for this production can be estimated. ERG
estimated new wells for each region using the initial rates of production,
years at peak production, and decline rates shown above. Tables 4-5a, b, and
c show total new OCS development wells for 1986-2000. At $32 per barrel, OCS
development wells for 1986-2000 total 8,588, of which 5,173 are oil wells. At
$21 per barrel, well projections total 7,601; at $15 per barrel, they total
6,384. The majority (70 to 80 percent) of the wells are located in the Gulf
of Mexico.
State Water Well Projections
State water activity in Alaska between 1980 and 1985 was quantified
relative to OCS activity in that region. During that period, the ratio of
State-to-Federal oil development was found to be 3:1 for Alaska. For the
Pacific region, Table 2-11 lists 1,656 wells on State leases and 341 wells on
Federal leases. The State well counts, however, include Huntington,
Wilmington, and Belmont fields which may be considered coastal rather than
offshore (i.e., they are beyond the natural coastline but may not be seaward
of the inner boundary of the territorial seas). Not including the wells from
these fields results in 225 wells on State leases, or about two-thirds of the
number of wells on Federal leases. Since future activity may be less due to
the extensive exploration already performed in State waters, an estimated
State-to-Federal ratio of 1:2 is used for the Pacific.3 The 1:2 and 3:1
ratios for the Pacific and Alaska, respectively, are assumed to be valid for
the 1986-2000 period. Since no Atlantic State water activity is expected to
occur in the projected future, this region was not included in State waters'
projections.
In the Gulf, the State-to-Federal ratio is based on data from 1967 to
1985. American Petroleum Institute (API) data for all offshore wells were
used to obtain total well counts, while MMS data were used for well counts in
3In light of the recent moratorium on activity in California State waters
(Meier, 1990) this assumption may create an overestimate of the number of
projected wells and thus an overestimate of the regulatory costs. This issue
is addressed under the restricted activity scenario explained in Section 4.4.
4-18
-------
TABLE 4-5a
FEDERAL DCS WELL PROJECTIONS BY REGION. 1986-2000
($32/bbl of oil 1986 dollars)
REGION
Gulf
Pacific
Atlantic
Alaska
Total
Federal
Waters
OIL WELLS GAS WELLS TOTAL WELLS
3,213 2,912 6,125
1,617 302 1,919
109 165 274
234 36 270
5,173 3,415 8,588
Source: ERG estimates.
4-19
-------
TABLE 4-5b
REGION
Gulf
Pacific
Atlantic
Alaska
Total
Federal
Waters
($21/bbl of oil -
OIL WELLS
3,103
1,277
56
23
4,459
1986 dollars)
GAS WELLS
2,812
239
85
6
3,142
TOTAL WELLS
5,915
1,516
141
29
7,601
Source: ERG estimates.
4-20
-------
TABLE 4-5c
FEDERAL UCS
REGION
Gulf
Pacific
Atlantic
Alaska
Total
Federal
Waters
WELL PROJECTION
($15/bbl of oil - 1986
S BY REGION,
dollars)
1986-2000
OIL WELLS GAS WELLS TOTAL WELLS
2,757
874
36
0
3,667
2,501 5
162 1
54
0
2,717 6
,258
,036
90
0
,384
Source: ERG estimates.
4-21
-------
Federal waters. State well counts were estimated as the difference between
total offshore activity and Federal activity. During this period, the
State-to-Federal ratio dropped approximately 30 percent every 7 years. Based
on this data, the Gulf ratios for oil and gas were calculated as follows: 11
percent for 1986-1992, 8 percent for 1993-2000, 6 percent for 2001-2008, and
4 percent for 2009-2015. Only in the Gulf will State water gas activity be
significant.
Table 4-6 presents estimates of State water wells for 1986-2000. In the
$32 scenario, a total of 2,075 State water wells are projected. Oil wells in
that scenario total 1,810. In the $21 and $15 scenarios, State water wells
total 1,250 and 920 wells, respectively.
Inasmuch as the API offshore well counts include coastal as well as
offshore wells, projected activity in State waters in the Gulf of Mexico may
be overestimated. The number of projected wells, however, does not affect the
per-well costs (see Section Five) used in the economic impact analysis of
model projects (discussed in Section Six). If no or minimal impacts are seen
on representative projects or companies that bear these costs (Section Seven),
then the inclusion of coastal wells in projected State water activity does not
affect the conclusions drawn from the analysis.
The inclusion of some coastal wells may, however, lead to overestimation
of total annual regulatory costs. State water activity in the Gulf ranges
from 5.3 to 6.7 percent of all activity under the various scenarios (see
Tables 4-5 and 4-6). Even if all future activity in State waters in the Gulf
occurs in the coastal regions, the total projections would decrease by no more
than 6.7 percent. While more precise estimates are not available at the time
of this report, any revisions in State activity estimates are not expected to
decrease by more than this.
4.2.2 Unproductive Drilling Efforts
The API Basic Petroleum Data Book (API, 1988, Section XI, Table 7a) lists
an all-time total of 29,954 offshore wells drilled in Federal and State waters
as of January 1, 1985. Of these, 12,049 were dry holes; therefore, the
discovery efficiency was 60 percent. This value was used to forecast the
number of dry holes in our projections. At $32 per barrel, dry well
4-22
-------
TABLE 4-6a
WELL PROJECTIONS IN STATE WATERS BY REGION. 1986-2000
($32/bbl of oil - 1986 dollars)
REGION
OIL WELLS
GAS WELLS TOTAL WELLS
Gulf State
Waters
(Texas,
Louisiana,
Mississippi,
Alabama)
297
265
562
Pacific
State Waters
Atlantic
State Waters
Alaska
State Waters
Total State
Waters
811
0
702
1,810
0
0
0
265
811
0
702
2,075
Source: ERG estimates based on the historic ratio of
Federal-to-State water activity.
4-23
-------
TABLE 4-6b
WELL PROJECTIONS IN STATE WATERS BY REGION. 1986-2000
($21/bbl of oil - 1986 dollars)
REGION OIL WELLS GAS WELLS TOTAL WELLS
Gulf State 283 255 538
Waters
(Texas,
Louisiana,
Mississippi,
Alabama)
Pacific
State Waters
Atlantic
State Waters
Alaska
State Waters
Total State
Waters
643
0
69
955
0
0
0
255
643
0
69
1,250
Source: ERG estimates based on the historic ratio of
Federal-to-State water activity.
4-24
-------
TABLE 4-6c
WELL PROJECTIONS IN STATE WATERS BY REGION. 1986-2000
($15/bbl of oil - 1986 dollars)
REGION OIL WELLS GAS WELLS TOTAL WELLS
Gulf State 253 227 480
Waters
(Texas,
Louisiana,
Mississippi,
Alabama)
Pacific
State Waters
Atlantic
State Waters
Alaska
State Waters
Total State
Waters
440
0
0
693
0
0
0
227
440
0
0
920
Source: ERG estimates based on the historic ratio of
Federal-to-State water activity.
4-25
-------
projections total 7,005. Dry well projections for the $21 per barrel and $15
per barrel scenarios are 5,820 and 4,800 wells, respectively, and represent
unrestricted development for these oil prime scenarios. See Section 4.4 for a
discussion of the restricted development scenario.
4.23 Total Well Projections
Table 4-7 presents total productive development wells by region, by
combining the data shown in Tables 4-5 and 4-6. At $32 per barrel, productive
wells total 10,663. For the $21 and $15 forecasts, productive wells total
8,851 and 7,304, respectively.
Combining productive and dry wells, ERG obtains 17,668 wells drilled for
the $32/bbl scenario, 14,671 wells drilled for the $21/bbl scenario, and
12,104 wells drilled for the $15/bbl scenario. Table 4-8 presents the average
number of total wells drilled per year during the 15-year period. These
figures are 1,178, 978, and 807 for the $32/bbl, $21/bbl, and $15/bbl
scenarios, respectively, and represent unrestricted development for these oil
price scenarios. See Section 4.4 for a discussion of the restricted
development scenario.
43 PLATFORM PROJECTIONS, 1986-2000 - UNRESTRICTED DEVELOPMENT
43.1 Total Platforms
To convert projections of well drilling in each region into projections of
platform installations, ERG used selected model project sizes. Table 4-9
summarizes the methodology for allocating wells to platforms. Platform sizes
vary from single well structures in the Gulf platforms to 48 well slots on
Alaskan gravel islands. Six different platform sizes were modeled in the
Gulf, two in the Pacific, three in Alaska, and one in the Atlantic region.
The distribution of platforms was based upon platform configuration data
provided in a previous report (EPA, 1985), 1988 platform configurations in the
Gulf, and the well projections discussed above.
The unrestricted platform projections for the four regions are shown in
Tables 4-10 and 4-11. For 1986-2000, the total number of platforms is
expected to be 931 under the $32 scenario (Table 4-10). Of these, 778
4-26
-------
TABLE 4-7a
ZRAL AND STATE POST-NSPS OFFSHORE WELLS. 1986-2000
($32/bbl of oil -1986 dollars)
REGION
Gulf
State
OCS
Pacific
State
OCS
Atlantic
State
OCS
Alaska
State
OCS
Total
OIL WELLS
297
3,213
811
1,617
0
109
702
234
6,983
GAS WELLS
265
2,912
0
302
0
165
0
36
3,680
TOTAL WELLS
562
6,125
811
1,919
0
274
702
270
10,663
Source: ERG estimates; see Tables 4-5a and 4-6a.
4-27
-------
TABLE 4-7b
FEDERAL AND STATE POST-NSPS OFFSHORE WELLS. 1986-2000
($21/bbl of oil - 1986 dollars)
REGION
Gulf
State
DCS
Pacific
State
OCS
Atlantic
State
OCS
Alaska
State
OCS
Total
OIL WELLS
283
3,103
643
1,277
0
56
69
23
5,454
GAS WELLS TOTAL
255
2,812
0
239
0
85
0
6
3,397
WELLS
538
5,915
643
1,516
0
141
69
29
8,851
Source: ERG estimates; see Tables 4-5b and 4-6b.
4-28
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TABLE 4-7c
FEDERAL AJVD
REGION
Gulf
State
OCS
Pacific
State
OCS
Atlantic
State
OCS
Alaska
State
OCS
Total
STATE POST-NSPS OFFSHORE
($15/bbl of oil .
OIL WELLS GAS
253
2,757
440
874
0
36
0
0
4,360
1986 dollars)
WELLS. 1986-2000
WELLS TOTAL WELLS
227
2,501
0
162
0
54
0
0
2,944
480
5,258
440
1,036
0
90
0
0
7,304
Source: ERG estimates; see Tables 4-5c and 4-6c.
4-29
-------
TABLE 4-8
TOTAL OFFSHORE PRODUCING WELLS AND DRY HOLES
AVERAGE NUMBER OF WELLS PER YEAR
UNRESTRICTED DEVELOPMENT
PRICE
ASSUMPTION
$/BARREL'
$15
$21
$32
AVERAGE NO.
OF PRODUCING
WELLS PER YEAR
487
590
711
AVERAGE NO.
OF DRY HOLES
PER YEAR
320
388
467
AVERAGE NO.
OF TOTAL WELLS
PER YEAR
807
978
1,178
'1986 dollars.
Source: ERG estimates based upon pre-1986 production levels in the MMS
forecast.
4-30
-------
TABLE 4-9
PLATFORM CONFIGURATION SUMMARY
UNRESTRICTED ACTIVITY
i
Ul
PERCENT ALLOCATION
OF REGIONAL PLATFORMS
FEDERAL WATERS STATE WATERS
PERCENT ALLOCATION
OF REGIONAL WELLS
FEDERAL WATERS STATE WATERS
REGION
GULF
Pacific
Alaska
Atlantic
WELL
SLOTS
1
4
6
12
24
40
16
40
24
12 '
48(a)
24
ACTIVE
WELLS
1
4
6
10
18
32
14
32
18
10
40
18
OIL
5%
32%
8%
25%
20%
10%
30%
70%
15%
0%
85%
100%
GAS
15%
35%
17%
22%
11%
0%
100%
0%
0%
100%
0%
100%
OIL
5%
32%
38%
25%
0%
0%
0%
100%
0%
0%
100%
0%
GAS
15%
53%
50%
0%
0%
0%
0%
0%
0%
0%
0%
0%
OIL
0.4%
9%
4%
22%
35%
29%
15%
85%
15%
0%
85%
100%
GAS
2%
18%
13%
34%
34%
0%
100%
0%
0%
100%
0%
100%
OIL
1%
19%
35%
45%
0%
0%
0%
100%
0%
0%
100%
0%
GAS
3%
31%
66%
0%
0%
0%
0%
0%
0%
0%
0%
0%
(a) For platforms within 4 miles, a gravel island was utilized.
Source: ERG estimates based on MMS data.
-------
TABLE 4-10
<$32/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - TOTAL
UNRESTRICTED ACTIVITY
I
u>
IVJ
ALL PROJECTS
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
62
64
14
35
48
54
76
73
78
71
72
76
73
67
68
50
59
53
53
40
38
33
34
29
13
24
17
11
12
11
1408
931
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
0
0
0
0
1
0
0
0
0
1
0
0
0
1
7
4
0
0
0
0
0
0
0
0
0
2
3
3
4
3
3
6
2
4
2
3
3
0
2
2
0
1
1
2
0
0
0
46
24
GULF
PACIFIC ATLANTIC
1 4 6 12 24 40 16 40
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
6
6
0
2
4
5
7
6
7
5
7
6
7
6
6
4
4
5
4
3
3
2
2
2
I
55 114
30 80
0
IB
19
2
9
11
15
19
18
22
18
19
18
20
17
16
13
14
12
14
11
11
8
9
8
4
5
3
2
2
3
360
241
0
9
10
1
5
7
8
10
10
11
10
10
10
9
9
8
6
7
6
7
5
5
3
4
4
2
3
1
0
1
2
183
127
0
12
13
2
7
9
11
14
15
16
14
15
14
14
14
13
10
11
9
11
8
8
7
5
7
2
5
3
2
2
2
275
183
0
9
10
1
5
5
7
9
9
10
9
10
9
9
8
8
7
7
6
6
5
5
4
4
4
1
3
2
2
1
2
177
118
0
2
3
1
1
1
2
2
3
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
43 1152
29 778
0
3
1
3
1
4
2
2
3
2
4
2
3
3
4
3
1
1
3
2
2
2
1
2
0
60
40
0
3
2
4
5
7
4
5
5
5
6
3
8
4
4
3
4
4
4
2
2
2
3
2
2
1
2
2
1
2
0
101 161
68 108
24
WELLS
0
0
0
0
0
0
0
8
4
0
0
0
2
1
0
0
1
5
5
2
0
0
2
3
0
0
1
2
2
2
0
40 40
15 15
-------
TABLE 4-11
((21/bbl of oil 1986 dollars)
PLATFORM PROJECTIONS - TOTAL
UNRESTRICTED ACTIVITY
ALL PROJECTS
I
CJ
LJ
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
57
64
16
32
39
54
71
67
74
61
66
68
65
60
57
42
53
47
44
36
32
32
28
23
12
22
13
7
13
7
1262
851
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
1
0
0
0
1
0
0
0
1
0
0
0
0
0
0
0
4
2
1
WELL
0
6
6
0
2
2
5
7
6
7
5
6
6
6
6
6
4
4
4
4
3
3
2
2
2
6 109
4 76
GULF
PACIFIC ATLANTIC
4 6 12 24 40 16 40
WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
17
18
3
9
11
15
19
18
21
17
19
18
17
17
16
12
14
12
13
11
8
8
7
6
3
6
3
2
3
2
345
235
0
8
10
2
5
6
8
10
9
12
8
9
10
9
9
8
5
7
6
6
5
5
5
5
3
2
3
2
0
1
1
179
123
0
12
15
3
7
7
11
14
15
16
14
14
14
14
12
12
9
11
9
10
7
7
6
5
5
2
5
3
1
2
2
264
180
0
8
9
2
4
5
6
9
9
10
9
9
9
9
8
8
6
7
6
6
5
5
4
4
4
1
3
2
1
2
1
171
114
0
2
2
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
41 1109
27 755
0
2
1
2
1
2
3
1
3
2
2
2
2
3
3
1
1
1
3
1
2
1
1
1
1
1
1
0
0
1
0
45
30
0
2
3
3
3
5
4
4
4
4
4
4
5
4
3
2
3
4
3
1
2
2
3
1
0
2
2
1
2
1
0
81 126
54 84
24
WELLS
0
0
0
0
0
0
0
5
1
0
0
0
2
0
0
0
0
3
3
0
0
0
2
1
1
0
0
1
0
2
0
21 21
8 8
-------
platforms are located in the Gulf. This projection represents the high end of
the projections and thus would create the highest cost scenario. For the $21
scenario, the total number of platforms is projected to be 851 (see Table
4-11).
43.2 Platforms in 4-Mile Category
Certain regulatory options require different pollution controls depending
on whether the platform is within 4 miles of shore. It is, therefore,
necessary to subcategorize the platforms according to their distance from
shore. The 4-mile category includes all activity in State waters plus
platforms that may occur in the 1-mile band in Federal waters between 3 and 4
miles from shore.4 For the Gulf, the MMS data base was. used to determine the
percentages of wells and structures that occur in the 1-mile band in Federal
waters between 3 and 4 miles from shore. The percentages were done on a model
basis:
Gulf Ib 20.9%5
Gulf 4 12.7%
Gulf 6 1.4%
Gulf 12 0.7%
Gulf 24 2.7%
Gulf 40 0.0%
See Kaplan 1990.
For Alaska and the Pacific, only platforms in State waters are considered.
This is not to presume that no activity will occur in that 1-mile band in
Federal waters that adjoin State waters. In the platform projections, wells
*The offshore authority of Texas and Florida (on its Gulf Coast side
only) extends to 3 marine leagues (about 10.35 statute miles) for historical
reasons. Within these areas, all offshore activity within 4 miles of shore
would be in State waters. The well and platform projections for State water
activity in the Gulf of Mexico are not subcategorized by State. No attempt
has been made to subtract projected activity that may occur between the 4 mile
and 3 league lines in Texas and Florida. As mentioned earlier in this
section, State water activity in the Gulf ranges from 5.3 to 6.3 percent of
all projected activity (see Tables 4-5 and 4-6). Historically, most
development has been off Louisiana (see Table 2-10). The approach taken in
this analysis, then, would lead to only a small overestimate of regulatory
costs.
5This is not to say that no single well structures without production
equipment will be set in the Gulf. Since four Gulf la structures are assumed
to share production equipment, they have been included in the Gulf 4
projections since the per-project impacts are so similar. This approach does
not change the total estimated cost of an option.
4-34
-------
are allocated to whole platforms only (i.e., there are no fractional platforms
in the projections). Two gravel islands are included in the projections for
Alaska State waters for the $21/bbl scenario, which more than accounts for the
wells projected in Table 4-6. These islands remain as shallow water, or
within 4 miles, structures under this definition.
In the Pacific, the number of projected wells in State waters is derived
by estimating activity in State waters as a percentage of activity in Federal
waters. As mentioned in Section 4.2.1, this estimate may be high in light of
the current moratorium on activity in California waters. The amount of
estimated activity in State waters is sufficiently high to address any
activity that might occur in the 1-mile band adjacent to the Federal/State
boundary.
Tables 4-12 and 4-13 present the distribution of projected platforms based
on the 4-mile cutoff under the $32 and $21 scenarios, respectively. Tables
4-14 and 4-15 show the oil-producing platform projections under the $32 and
$21 scenarios, respectively.
4.4 PLATFORM PROJECTIONS, 1986-2000 - RESTRICTED DEVELOPMENT
4.4.1 Total Platforms
The number of platforms projected in Section 4.3.1 assumes that all oil
and gas development which is economically feasible will take place. In this
section these projections have been adjusted for the Pacific and Atlantic
regions to account for recent governmental decisions.
California State Waters
A combination of State legislation and declarations by the California
State Lands Commission has essentially banned further leasing of California
State waters from development for oil and gas. Under article 4, Section 6871
of the California Public Resources Code, discretion over whether to lease
submerged lands for oil and gas development is given to the State Lands
4-35
-------
TABLE 4-12
($32/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - WITHIN 4-MILES
UNRESTRICTED ACTIVITY
I
1*1
a\
ALL PROJECTS
ALASKA
24 12 GRAVEL
YEAR TOTAL WELLS WELLS ISLAND
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
13
14
2
8
12
12
14
12
16
13
13
16
15
14
15
9
12
8
11
6
8
4
5
5
3
3
2
0
1
1
267
189
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
2
3
2
3
4
2
3
2
2
2
0
2
1
0
1
1
1
0
0
0
35
18
GULF
PACIFIC ATLANTIC
1 4 6 12 24 40 16 40 24
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
2
2
0
0
2
2
2
2
2
1
2
2
2
2
2
1
0
0
0
0
0
0
0
0
0
35 31
18 25
0
5
6
0
3
3
5
5
4
5
4
4
4
5
4
4
3
4
2
4
2
3
1
2
2
1
1
0
0
0
0
86
61
000
4
4
1
2
3
3
4
3
4
^
3
t
»
*
3
0
0
) 0
0
0
0
0
0
0
0
0
0
0
0
0
1 0 0
2 1 0
1 0 0
2 1 0
1 0 0
2 1 0
000
1 0 0
1 1 0
1 0 0
000
000
000
000
1 0 0
59 18 0
46 14 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 194
0 146
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
2
3
1
2
2
2
2
1
3
2
1
1
2
1
2
1
0
1
1
1
1
0
1
1
0
1
0
38 38
25 25
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-12 (Cont.)
($32/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - BEYOND 4-MILES
UNRESTRICTED ACTIVITY
A
Ul
ALL PROJECTS
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
49
50
12
27
36
42
62
61
62
58
59
60
58
53
53
41
47
45
42
34
30
29
29
24
10
21
15
11
11
10
1141
742
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
0
0
0
0
1
0
0
0
0
1
0
0
0
1
7
4
0
0
0
0
0
0
0
0
0
0
1
1
1
1
0
2
0
1
0
1
1
0
0
1
0
0
0
1
0
0
0
11
6
1
WELL
0
4
4
0
2
2
3
5
4
5
4
5
4
5
4
4
3
3
4
3
2
2
2
2
2
1
1
1
0
1
1
20 83
12 55
4
WELLS
0
13
13
2
6
8
10
14
14
17
14
15
14
15
13
12
10
10
10
10
9
8
7
7
6
3
4
3
2
2
3
274
180
GULF
PACIFIC ATLANTIC
6 12 24 40 16 40
WELLS WELLS WELLS WELLS WELLS WELLS
0
5
6
0
3
4
5
6
7
7
7
7
7
6
6
5
5
5
5
5
4
3
3
3
3
1
3
1
0
1
1
124
81
0
11
12
2
6
8
10
13
14
15
13
14
13
13
13
12
10
10
9
10
8
7
7
5
6
2
5
3
2
2
2
257
169
0
9
10
1
5
5
7
9
9
10
9
10
9
9
8
8
7
7
6
6
5
5
4
4
4
1
3
2
2
1
2
177
118
0
2
3
1
1
1
2
2
3
2
2
2
2
2
2
2
2
2
1
2
1
1
1
1
1
0
1
0
1
0
0
43 958
29 632
0
3
1
3
1
4
2
2
3
2
4
2
3
3
4
3
1
1
3
2
2
2
1
2
1
0
60
40
0
2
1
3
3
4
3
3
3
3
4
2
5
2
3
2
2
3
2
1
2
1
2
0
63 123
43 83
24
WELLS
0
0
0
0
0
0
0
8
4
0
0
0
2
1
0
0
1
5
5
2
0
0
2
3
0
0
1
2
2
2
0
40 40
15 15
-------
TABLE 4-13
($21/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - WITHIN 4-MILES
UNRESTRICTED ACTIVITY
I
u>
do
ALL PROJECTS
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
12
14
2
7
7
12
14
11
14
9
14
12
11
11
12
5
10
5
8
5
5
4
3
1
2
4
1
1
0
0
216
162
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
1
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
3
2
GULF
PACIFIC ATLANTIC
1 4 6 12 24 40 16 40
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
2
2
0
0
0
2
2
2
2
1
2
2
2
2
2
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
3 29
2 23
0
5
5
0
3
3
5
5
4
5
4
5
4
4
4
4
2
4
2
3
2
1
1
1
1
0
2
0
0
0
0
79
60
0
3
4
1
2
2
3
4
3
4
2
3
3
3
3
3
1
2
1
2
1
2
2
2
0
1
1
1
0
0
0
59
43
0
1
2
0
1
0
1
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
16
14
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 183
0 140
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
2
1
2
1
2
1
2
2
1
1
1
1
2
1
0
1
1
1
0
0
1
1
0
1
0
0
30 30
20 20
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-13 (Cent.)
(S21/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS- BEYOND 4-NILES
UNRESTRICTED ACTIVITY
I
CJ
vo
ALL PROJECTS
ALASKA
YEAR TOTAL 24 12 48
WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
45
50
14
25
32
42
57
56
60
52
52
56
54
49
45
37
43
42
36
31
27
28
25
22
10
18
12
6
13
7
1046
689
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
0
1
WELL
0
4
4
0
2
2
3
5
4
5
4
4
4
4
4
4
3
3
3
3
2
2
2
2
2
1
1
1
0
1
1
3 80
2 53
4
WELLS
0
12
13
3
6
8
10
14
14
16
13
14
14
13
13
12
10
10
10
10
9
7
7
6
5
3
4
3
2
3
2
266
175
GULF
6 12
WELLS WELLS
0
5
6
1
3
4
5
6
6
8
6
6
7
6
6
5
4
5
5
4
4
3
3
3
3
1
2
1
0
1
1
120
80
0
11
13
3
6
7
10
13
14
15
13
13
13
13
11
11
9
10
9
9
7
7
6
5
5
2
5
3
1
2
2
248
166
PACIFIC ATLANTIC
24 40 16 40
WELLS WELLS WELLS WELLS
0
8
9
2
4
5
6
9
9
10
9
9
9
9
8
8
6
7
6
6
5
5
4
4
4
1
3
2
1
2
1
171
114
0
2
2
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
41 926
27 615
0
2
1
2
1
2
3
1
3
2
2
2
2
3
3
1
1
1
3
1
2
1
1
1
1
1
1
0
0
1
0
45
30
0
1
2
2
2
3
3
2
3
2
3
2
3
3
2
1
2
2
2
1
1
1
2
1
0
1
1
1
1
1
0
51 96
34 64
24
WELLS
0
0
0
0
0
0
0
5
1
0
0
0
2
0
0
0
0
3
3
0
0
0
2
1
1
0
0
1
0
2
0
21 21
8 8
-------
TABLE 4-14
<$32/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - WITHIN 4-MILES
UNRESTRICTED ACTIVITY
OIL PRODUCING PROJECTS
I
i*k
o
ALASKA
GULF
PACIFIC ATLANTIC
24 12 48 146 12 24 40 16 40
YEAR TOTAL WELLS WELLS WELLS WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
6
7
2
5
6
5
6
6
8
8
7
10
8
8
9
5
8
4
7
2
5
3
2
4
1
2
2
0
1
0
147
101
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
2
3
2
3
4
2
3
2
2
2
0
2
1
0
1
1
1
0
0
0
35 35
18 18
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
000
2 2 1
3 2 1
0
1
1
2
2
2
2
2
2
2
2
2
2
0
1
1
1
1
1
1
1
1
1
1
1
1
1 0 0
2
1
000
2
1
000
2
1
000
000
1
1
000
000
000
000
000
000
35 21 18
27 17 14
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 74
0 58
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
2
3
1
2
2
2
2
1
3
2
1
1
2
1
2
1
0
1
1
1
1
0
1
1
0
1
0
38 38
25 25
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-14 (Cont.)
($32/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - BEYOND 4-MILES
UNRESTRICTED ACTIVITY
OIL PRODUCING PROJECTS
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
TOTAL
0
22
26
8
15
16
19
24
27
24
28
25
30
24
21
24
18
21
17
18
14
13
14
13
9
2
10
7
8
2
3
502
333
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
ALASKA
12
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
48
WELLS
0
0
0
0
0
0
0
0
0
0
1
1
1
1
0
2
0
1
0
1
1
0
0
1
0
0
0
1
0
0
0
11
6
1 4
WELL WELLS
0 0
1 5
1 6
0 1
0 3
0 3
3
4
5
5
5
5
5
5
4
4
3
3
3
3
0 3
1 3
0 3
0 3
0 2
0 0
0 2
0 1
0 2
0 0
0 1
13 17 95
8 12 63
6
WELLS
0
1
2
0
1
1
1
1
2
1
2
2
2
1
0
1
0
0
0
0
29
19
GULF
12
WELLS
0
5
6
1
3
3
4
5
6
6
6
6
6
5
5
5
4
4
3
4
3
3
3
2
2
0
2
1
2
0
1
106
72
24
WELLS
0
5
6
1
3
2
4
4
5
5
5
5
5
5
4
4
4
4
3
3
2
3
2
2
2
0
2
1
2
0
1
94
63
40
WELLS
0
2
3
1
1
1
2
2
3
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
43
29
PACIFIC
16 40
WELLS WELLS
0 0
2
1
3
3
4
3
3
3
3
4
2
5
2
3
2
2
3
2
1
2
1
2
0
1
0
1
0
0
0 0
384 27 63
258 18 43
ATLANTIC
24
WELLS
0
0
0
0
0
0
0
3
1
0
0
0
1
1
0
0
0
1
2
1
0
0
1
1
0
0
1
1
0
1
0
90 15 15
61 66
-------
TABLE 4-15
($21/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - WITHIN 4-MILES
UNRESTRICTED ACTIVITY
OIL PRODUCING PROJECTS
.u
.b.
K>
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
5
8
1
4
4
5
6
5
6
5
7
6
5
5
6
2
6
1
5
1
2
2
1
0
1
3
0
1
0
0
103
78
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
1
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
3 3
2 2
GULF
PACIFIC ATLANTIC
1 4 6 12 24 40 16 40
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
3
0
1
1
2
2
2
2
2
2
2
2
2
2
1
2
0
2
0
0
0
0
0
0
1
0
0
0
0
33
27
0
1
2
0
0
1
0
1
0
1
1
1
0
0
1
0
0
0
0
21
15
0
1
2
0
1
0
1
1
1
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
16
14
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 70
0 56
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
2
1
2
1
2
1
2
2
1
1
1
1
2
1
0
1
1
1
0
0
1
1
0
1
0
0
30 30
20 20
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-15 (Cont.)
(S21/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - BEYOND 4-HILES
UNRESTRICTED ACTIVITY
OIL PRODUCING PROJECTS
I
4».
U>
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
TOTAL
0
20
24
11
13
15
18
22
24
24
25
22
26
22
19
18
17
19
16
15
11
13
13
11
9
2
8
4
6
5
0
452
303
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
ALASKA
12
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
48
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
0
1
WELL
0
1
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
0
0
0
0
0
0
0
0
2 17
1 12
4
WELLS
0
5
5
2
3
3
3
4
5
5
5
5
5
4
4
4
3
3
3
3
3
3
3
3
2
0
2
1
2
1
0
94
62
GULF
6 12
WELLS WELLS
0 0
1 5
2 6
1 2
3
3
4
5
6
6
6
5
6
5
4
4
4
4
3
4
2
3
2
2
2
0 0
0 2
0 1
0 1
0 1
0 0
28 101
19 70
24
WELLS
0
5
5
2
2
3
3
4
5
5
5
5
5
5
4
4
3
4
3
3
2
3
2
2
2
0
2
1
1
1
0
91
62
40
WELLS
0
2
2
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
1
2
1
1
1
1
1
0
1
0
1
0
0
41
27
PACIFIC
16 40
WELLS WELLS
0 0
0 1
1 2
1 2
2
3
3
2
3
2
3
2
3
3
2
0 1
2
2
2
0 1
1 1
0 1
1 2
0 1
0 0
1 1
0 1
0 1
0 1
0 1
0 0
372 19 51
252 13 34
ATLANTIC
24
WELLS
0
0
0
0
0
0
0
2
0
0
0
0
1
0
0
0
0
1
1
0
0
0
1
0
1
0
0
0
0
1
0
70 88
47 33
-------
Commission. Under section 6871.2 of the code, the legislature has prohibited
the Commission from issuing oil and gas leases in certain areas along the
coast (deemed "sanctuary zones"). In addition to these sanctuary zones, the
State Lands Commission has declared that no new oil and gas leasing and
development will take place in certain designated areas (calendar items
adopted 10/26/88 and 12/6/89). These declarations have resulted in the
inclusion of all remaining unleased submerged lands with those that are
currently established as sanctuaries (Meier, 1990).
Recent actions by the State Lands Commission indicate that no further
development will occur even in existing leases in State waters. In 1969,
following a well blow-out in the Santa Barbara Channel, the State Lands
Commission imposed a drilling moratorium on all State oil and gas leases in
submerged lands. The Commission later began lifting the moratorium on a lease
by lease basis; however, it has denied all applications for drilling permits
in recent years. The most recent case was an application by Atlantic
Richfield Co. (ARCO) in 1987 (case # 663 010). The court issued a ruling in
January of this year supporting the Lands Commission's decision to deny the
permit. (The Superior Court's official judgment, expected within the next
several weeks, is expected to be similar to the initial ruling. The decision
will certainly be appealed by ARCO; however, it is believed that the Lands
Commission's decision to deny drilling permits will stand (Meier, 1990).)
Given the recent actions by the State Lands Commission, the restricted
projections include no activity in Pacific State waters.
Federal Waters
On June 26, 1990, President Bush announced his decision to implement a
moratorium on oil and gas leasing and development in Federal waters off of
California until the year 2000 (DOT, 1990). The moratorium eliminates the
proposed leasing in sale areas 91 and 119, and the vast majority of sale area
95. This means that 99 percent of Federal waters off California are off-
limits to leasing for the remainder of the century. The remaining 1 percent
of tracts in the Southern California Planning Area, located in the Santa Maria
Basin and the Santa Barbara Channel, will not be available until at least
1996, and only then if further studies indicate that development appears
viable in relation to the environmental impacts and economic considerations.
This means that the only exploration and development likely will occur on
existing Federal leases.
4-44
-------
The President indicated that, in the event of a national emergency, these
restrictions on leasing could be lifted. Even if such an event occurred, the
oil and gas industry, which was decimated during the oil price collapse of
1986, would be hard pressed to increase production in the short term due to
the shortage of available equipment, personnel, and capital (OGJ, 1990).
Nonetheless, the unrestricted platform projections reflect an upper bound for
activity in the Pacific in the absence of any environmental or materiel
constraints.
The President's decision also cancels lease sale 96, in the George's Bank
region of the North Atlantic, and essentially prohibits any activity i.n this
planning area until after the year 2000 (DOI, 1990). Given the cancellation
of sale 96, the lack of sufficient infrastructure to support production in the
region, and the prevailing attitudes opposing offshore drilling, we have
deleted all Atlantic activity in the restricted projections.
4.4.2 Implications for Platform Projections
The MMS production projections will remain the basis of the restricted
activity projections for the Gulf and Alaska regions. However, ERG has made
several assumptions regarding the Pacific and Atlantic regions to reflect
recent legislative actions:
All future activity in State waters off California will equal zero.
Activity in Federal waters off California will be limited to platforms
installed between 1985 and 1989, since wells in these platforms will be
drilled during the 1986-2000 time period (see Table 4-16.).
All future activity in the Atlantic region will equal zero.
Table 4-16 indicates that a total of seven platforms will be considered as
part of the restricted activity scenario in the Pacific region under the
$21/bbl assumption. All of these platforms fall outside of the 4-mile
regulatory boundary. The average annual number of wells drilled in the
Pacific during the 1986 to 1989 period is 32 (see Table 4-17). ERG believes
this number accurately reflects the number of wells to be drilled under
current restrictions. Assuming this level of activity continues throughout
the 15-year period, it will result in a total of 480 wells. This number is
sufficient to address the needs of the productive and exploratory wells of the
platforms listed in Table 4-16.
4-45
-------
TABLE 4-16
PACIFIC PLATFORMS CONSIDERED IN RESTRICTED DEVELOPMENT ANALYSIS
FEDERAL WATERS
Platform Name
Irene
Gail
Harvest
Hermosa
Hidalgo
Harmony
Heritage
Year
Installed
1985
1987
1985»
1985«
1986»
1989» *
1989» *
Year of
Production*"
1987
1988
1991
1991
1991
1992
1992
Number of
Well Slots
72
36
50
48
56
60
60
ERG Model
Type
Pacific 70
Pacific 40
Pacific 40
Pacific 40
Pacific 70
Pacific 70
Pacific 70
Total Projected Well Slots
382
» These platforms are not yet producing.
* Platforms Harmony and Heritage were not completed as of 10/90.
** ERG estimates.
Sources: CCC, 1988; MMS, 1990a; and Uinham, 1990.
4-46
-------
TABLE 4-17
ACTUAL DRILLING RATES FOR THE PACIFIC 1986-1989
Year
1986 1987 1988 1989 Average
Exploratory '3 4 3 5 4
Development 34 39 29 11 28
Total 37 43 32 16 32
Source: MMS, 1990b.
4-47
-------
Recent events suggest that production in the Atlantic region will not
occur before the turn of the century; thus, activity in this region has been
excluded from the restricted projections as well.
Table 4-18 summarizes the methodology for allocating wells to platforms.
This configuration remains the same as under the unrestricted development
scenario, except that the Atlantic region has been eliminated and activity in
the Pacific is limited to seven platforms, including four 70 well slot
structures.
Using these restricted assumptions, two sets of platform projections were
created as shown in Tables 4-19 and 4-20. The projections under the $21/bbl
scenario are shown in Table 4-19, while those under the $15/bbl scenario are
in Table 4-20. The $15/bbl projections represent the low estimate of the
number of platforms expected to begin production during the 1986-2000 period,
and therefore would produce the lowest total regulatory costs. Note that
under the $15/bbl assumption:
The number of platforms in the Atlantic remains zero.
Activity in the Pacific remains the same as under the $21/bbl scenario.
(This occurs because the platforms from which production is projected
are either completed or near completion. Therefore, these companies
would continue to utilize these platforms to recover the costs already
incurred.)
The only changes occur in the Gulf and Alaska regions, since that is
where the decline in oil prices would negatively affect the viability
of projects.
Table 4-21 shows platform distribution within and beyond 4 miles from shore.
Table 4-22 repeats this information for oil producing platforms only.
4.5 SUMMARY
Tables 4-23 through 4-26 summarize the platform projections under the four
alternative scenarios. Note that, assuming $21/bbl, the total number of
platforms set during the 1986-2000 time period drops from 851 to 766 when
activity is restricted. The platform projections for the high and low case
scenarios are shown in Tables 4-25 and 4-26, respectively. The average annual
number of wells drilled under each of the four scenarios is summarized in
Table 4-27. The number of wells has been back-calculated from the platform
distribution. Since only whole platforms are assigned to a region in any
given year, some rounding differences occur between the numbers in Table 4-27
4-48
-------
TABLE 4-18
PLATFORM CONFIGURATION SUMMARY
RESTRICTED ACTIVITY
PERCENT ALLOCATION
OF REGIONAL PLATFORMS
FEDERAL WATERS
REGION
GULF
Alaska
WELL
SLOTS
1
4
6
12
24
40
24
12
48(a)
ACTIVE
WELLS
1
4
6
10
18
32
18
10
40
OIL
5%
32%
8%
25%
20%
10%
15%
0%
85%
GAS
15%
35%
17%
22%
11%
0%
0%
100%
0%
STATE WATERS
OIL
5%
32%
38%
25%
0%
0%
0%
0%
100%
GAS
15%
53%
50%
0%
0%
0%
0%
0%
0%
PERCENT ALLOCATION
OF REGIONAL WELLS
FEDERAL WATERS
OIL
0.4%
9%
4%
22%
35%
29%
15%
0%
85%
GAS
2%
18%
13%
34%
34%
0%
0%
100%
0%
STATE
OIL
1%
19%
35%
45%
0%
0%
0%
0%
100%
WATERS
GAS
3%
31%
66%
0%
0%
0%
0%
0%
0%
Note: For the Pacific region, projections include only those platforms installed during the 1985-1990 time
period. For the Atlantic, no development was assumed.
(a) For platforms within 4-miles, a gravel island was utilized.
Source: ERG estimates based on MMS data.
-------
TABLE 4-19
<$21/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - TOTAL
RESTRICTED ACTIVITY
I
ui
o
ALL PROJECTS
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
53
61
12
28
32
50
63
59
68
55
60
59
58
54
54
38
45
38
42
32
29
26
25
21
9
19
11
5
9
7
1122
766
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
1
0
0
0
1
0
0
0
1
0
0
0
0
0
0
0
4
2
1
WELL
0
6
6
0
2
2
5
7
6
7
5
6
6
6
6
6
4
4
4
4
3
3
2
2
2
(
6 109
4 76
GULF
PACIFIC
ATLANTIC
4 6 12 24 40 40 70
WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
17
18
3
9
11
15
19
18
21
17
19
18
17
17
16
12
14
12
13
11
8
8
7
6
3
6
3
2
3
2
345
235
0
8
10
2
5
6
8
10
9
12
8
9
10
9
9
8
5
7
6
6
5
5
5
5
3
2
3
2
0
1
1
179
123
0
12
15
3
7
7
11
14
15
16
14
14
14
14
12
12
9
11
9
10
7
7
6
5
5
2
5
3
1
2
2
264
180
0
8
9
2
4
5
6
9
9
10
9
9
9
9
8
8
6
7
6
6
5
5
4
4
4
1
3
2
1
2
1
171
114
0
2
2
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
41 1109
27 755
0
0
0
1
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
3
0
0
1
0
0
0
1
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4 7
4 7
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-20
($15/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - TOTAL
RESTRICTED ACTIVITY
ALL PROJECTS
I
in
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
48
49
13
23
31
45
57
51
59
51
52
49
52
48
41
35
42
33
36
30
27
23
20
21
6
15
8
6
8
9
988
669
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
GULF
PACIFIC
ATLANTIC
1 4 6 12 24 40 40 70 24
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
5
5
1
1
3
5
6
5
6
5
5
5
5
5
4
4
4
3
4
2
2
2
2
2
0 96
0 66
0
14
14
3
8
10
12
17
16
19
16
16
15
16
15
13
11
13
11
11
10
8
6
6
7
2
5
3
2
2
3
304
204
0
8
8
3
4
6
8
9
7
9
8
8
8
9
8
6
5
6
5
6
6
5
5
2
4
1
1
1
0
3
1
160
109
0
12
11
2
6
7
10
13
13
14
12
13
11
12
11
10
8
10
8
8
7
6
5
5
4
1
4
2
2
1
2
230
157
0
7
8
2
3
4
6
8
8
9
8
8
8
8
7
6
6
7
5
6
4
5
4
4
3
1
3
1
1
1
2
153
100
0
2
2
1
1
1
1
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
38 981
26 662
0
0
0
1
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
3
0
0
1
0
0
0
1
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4 7
4 7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-21
<$15/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - WITHIN 4-MILES
RESTRICTED ACTIVITY
I
tn
10
ALL PROJECTS
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
198S
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
10
11
2
6
5
9
12
8
11
9
9
8
9
8
7
4
7
4
5
4
3
3
1
5
0
1
0
0
2
0
163
124
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
GULF
PACIFIC
ATLANTIC
1 4 6 12 24 40 40 70
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
2
2
0
0
1
2
2
1
2
1
1
0
0
0
0
0
0
0
0
0
0
0
0 22
0 18
0
4
4
0
3
2
3
5
4
5
4
4
4
4
4
3
2
3
2
2
2
1
1
1
3
0
1
0
0
0
0
71
53
0
3
4
2
2
2
3
4
2
3
3
3
3
3
3
2
1
2
1
2
2
2
2
0
2
0
0
0
0
2
0
58
42
0
1
1
0
1
0
0
1
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
12
11
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 163
0 124
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
24
WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-21 (Cont.)
($15/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - BEYOND 4-MILES
RESTRICTED ACTIVITY
I
ui
u>
ALL PROJECTS
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
38
38
11
17
26
36
45
43
48
42
43
41
43
40
34
31
35
29
31
26
24
20
19
16
6
14
8
6
6
9
825
545
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
GULF
PACIFIC
ATLANTIC
1 4 6 12 24 40 40 70 24
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
3
3
1
1
2
3
4
4
4
4
4
4
4
4
3
3
3
2
3
2
2
2
2
2
I
0 74
0 48
0
10
10
3
5
8
9
12
12
14
12
12
11
12
11
10
9
10
9
9
8
7
5
5
4
2
4
3
2
2
3
233
151
0
5
4
1
2
4
5
5
5
6
5
5
5
6
5
4
4
4
4
4
4
3
3
2
2
I
102
67
0
11
10
2
5
7
9
12
12
13
11
12
11
11
11
9
8
9
8
8
7
6
5
5
4
1
4
2
2
1
2
218
146
0
7
8
2
3
4
6
8
8
9
8
8
8
8
7
6
6
7
5
6
4
5
4
4
3
1
3
1
1
1
2
153
100
0
2
2
1
1
1
1
2
2
2
2
2
2
2
2
2
1
2
0
1
0
1
0
0
38 818
26 538
0
0
0
1
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
3
0
0
1
0
0
0
1
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4 7
4 7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-22
($15/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - UITHIN 4-HILES
RESTRICTED ACTIVITY
OIL PRODUCING PROJECTS
I
en
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1995
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
4
5
1
3
1
3
4
4
4
4
4
3
4
3
4
0
4
0
2
2
1
1
0
2
0
0
0
0
1
0
64
51
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
GULF
PACIFIC
ATLANTIC
1 4 6 12 24 40 40 70 24
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
000
2 1 1
2 2 1
0 1 0
1 1 1
0
«
2
2
2
2
2
2
p
2
2
0
2
0
1
1
0
o
0
1
1
1
1
1
1
0
1
0
1
0
1
0
0
0
0
0
000
1 1 0
000
000
000
000
0 1 0
000
29 23 12
24 16 11
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 64
0 51
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-22 (Coot.)
<$15/bbl of oil - 1986 dollars)
PLATFORM PROJECTIONS - BEYOND 4-MILES
RESTRICTED ACTIVITY
OIL PRODUCING PROJECTS
en
in
ALASKA
24 12 48
YEAR TOTAL WELLS WELLS WELLS
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
17
19
6
10
10
15
19
17
19
17
17
18
16
14
14
12
15
10
12
10
11
8
7
4
0
7
2
6
0
3
335
228
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
GULF
PACIFIC
ATLANTIC
1 4 6 12 24 40 40 70 24
WELL WELLS WELLS WELLS WELLS WELLS WELLS WELLS WELLS
0
1
1
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0 15
0 12
000
4
4
2
3
3
3
4
4
5
4
4
4
4
3
3
3
3
3
3
3
5
5
1
3
3
3
5
5
5
5
5
5
4
4
4
3
4
3
3
3
3 1 3
2 1 2
202
1 0 1
000
202
1 0 1
202
000
1 0 1
83 21 92
54 14 62
0
4
5
1
2
2
3
4
4
5
4
4
5
4
3
3
3
4
2
3
2
3
2
2
1
0
2
0
1
0
1
79
53
0
2
2
1
1
1
1
2
2
2
2
2
2
2
2
2
1
2
1
0
1
0
1
0
0
38 328
26 221
0
0
0
1
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
3
0
0
1
0
0
0
1
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4 7
4 7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 0
0 0
-------
TABLE 4-23
TOTAL PROJECTED NSPS STRUCTURES (1986-2000)
UNRESTRICTED ACTIVITY
$21/bbt SCENARIO
All Platforms
Region
Gulf
Pacific
Atlantic
Alaska
Model
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 16
Pacific 40
Pacific Totals
Atlantic 24
Cook Inlet 12
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms - All Regions
Total
76
235
123
180
114
27
755
30
54
84
8
1
1
2
4
851
Oil
12
89
34
84
62
27
308
13
54
67
3
0
1
2
3
381
Gas
64
146
89
96
52
0
447
17
0
17
5
1
0
0
1
470
Within 4-Miles
Total
23
60
43
14
0
0
140
0
20
20
0
0
0
2
2
162
Oil
0
27
15
14
0
0
56
0
20
20
0
0
0
2
2
78
Gas
23
33
28
0
0
0
84
0
0
0
0
0
0
0
0
84
Beyond 4 -Miles
Total
53
175
80
166
114
27
615
30
34
64
8
1
1
0
2
689
Oil
12
62
19
70
62
27
252
13
34
47
3
0
1
0
1
303
Gas
41
113
61
96
52
0
363
17
0
17
5
1
0
0
386
Oil only; all other projects are assumed to produce oil and casinghead gas.
4-56
-------
TABLE 4-24
TOTAL PROJECTED NSPS STRUCTURES (1986-2000)
RESTRICTED ACTIVITY
$21/bbl SCENARIO
All Platforms
Region
Gulf
Pacific
Atlantic
Alaska
Model
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 40
Pacific 70
Pacific Totals
Atlantic 24
Cook Inlet 12
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms - All Regions
Total
76
235
123
180
114
27
755
3
4
7
0
1
1
2
4
766
Oil
12
89
34
84
62
27
308
3
4
7
0
0
1
2
3
318
Gas
64
146
89
96
52
0
447
0
0
0
0
1
0
0
1
448
Within 4-Miles
Total
23
60
43
14
0
0
140
0
0
0
0
0
0
2
2
142
Oil
0
27
15
14
0
0
56
0
0
0
0
0
0
2
2
58
Gas
23
33
28
0
0
0
84
0
0
0
0
0
0
0
0
84
Beyond 4-Miles
Total
53
175
80
166
114
27
615
3
4
7
0
1
1
0
2
624
Oil
12
62
19
70
62
27
252
3
4
7
0
0
1
0
1
260
Gas
41
113
61
96
52
0
363
0
0
0
0
1
0
0
1
364
Oil only; all other projects are assumed to produce oil and casinghead gas.
4-57
-------
TABLE 4-25
TOTAL PROJECTED NSPS STRUCTURES (1986-2000)
UNRESTRICTED ACTIVITY - (HIGH DEVELOPMENT SCENARIO)
$32/bbl SCENARIO
All Platforms
Region
Gulf
Pacific
Atlantic
Alaska
Model
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 16
Pacific 40
Pacific Totals
Atlantic 24
Cook Inlet 12
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms All Regions
Total
80
241
127
183
118
29
778
40
68
108
15
4
2
24
30
931
Oil
12
90
36
86
63
29
316
18
68
86
6
0
2
24
26
434
Gas
68
151
91
97
55
0
462
22
0
22
9
4
0
0
4
497
Within 4-Miles
Total
25
61
46
14
0
0
146
0
25
25
0
0
0
18
18
189
Oil
0
27
17
14
0
0
58
0
25
25
0
0
0
18
18
101
Gas
25
34
29
0
0
0
88
0
0
0
0
0
0
0
0
88
Beyond 4-Mi les
Total
55
180
81
169
118
29
632
40
43
83
15
4
2
6
12
742
Oil
12
63
19
72
63
29
258
18
43
61
6
0
2
6
8
333
Gas
43
117
62
97
55
0
374
22
0
22
9
4
0
0
4<
409
* Oil only.
4-58
-------
TABLE 4-26
TOTAL PROJECTED NSPS STRUCTURES (1986-2000)
RESTRICTED ACTIVITY - (LOW DEVELOPMENT SCENARIO)
$15/bbl SCENARIO
All Platforms
Region
Gulf
Pacific
Atlantic
Alaska
Model
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 40
Pacific 70
Pacific Totals
Atlantic 24
Cook Inlet 12
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms - All Regions
Total
66
204
109
157
100
26
662
3
4
7
0
0
0
0
0
669
Oil
12
78
30
73
53
' 26
272
3
4
7
0
0
0
0
0
279
Gas
54
126
79
84
47
0
390
0
0
0
0
0
0
0
0
390
Within 4-Miles
Total
" 18
53
42
11
0
0
124
0
0
0
0
0
0
0
0
124
Oil
0
24
16
11
0
0
51
0
0
0
0
0
0
0
0
51
Gas
18
29
26
0
0
0
73
0
0
0
0
0
0
0
0
73
Beyond 4-Miles
Total
48
151
67
146
100 .
26
538
3
4
7
0
0
0
0
0
545
Oil
12
54
14
62
53
26
221
3
4
7
0
0
0
0
0
226
Gas
36
97
53
84
47
0
317
0
0
0
0
0
0
0
0
317
4-59
-------
TABLE 4-27
AVERAGE ANNUAL NUMBER OF WELLS DRILLED, BAT AND NSPS
Scenario
Gulf
Region
Pacific Alaska
Atlantic
Total
$32/bbl Unrestricted Development
Average Annual Number of Wells
Percentage Within 4 Miles of Shore
Number Within 4 Miles of Shore
Number Beyond 4 Miles of Shore
S21/bbl - Unrestricted Development
Average Annual Number of Wells
Percentage Within 4 Miles of Shore
Number Within 4 Miles of Shore
Number Beyond 4 Miles of Shore
$21/bbl - Restricted Development
Average Annual Number of Wells
Percentage Within 4 Miles of Shore
Number Within 4 Miles of Shore
Number Beyond 4 Miles of Shore
741
10X
74
667
715
10X
72
643
715
10X
72
643
302
30X
91
211
237
30X
71
166
32
OX
0
32
105
75X
79
26
12
75X
9
3
12
75X
9
3
30
OX
0
30
16
OX
0
16
0
NA
0
0
1,178
21X
243
935
980
15X
152
828
759
11X
81
678
$15/bbl Restricted Development
Average Annual Number of Wells
Percentage Within 4 Miles of Shore
Number Within 4 Miles of Shore
Number Beyond 4 Miles of Shore
638
10X
64
574
32
OX
0
32
0
NA
0
0
0
NA
0
0
670
10X
64
606
M
NA: Not Applicable
Source: ERG estimates
Note: Totals may not agree with Table 4-8 counts due to rounding.
08-Feb-9T
4-60
-------
and Table 4-8. It should be noted that, under the $21/bbl restricted
development scenario, 759 wells per year are projected. For comparison, the
most recent prediction for offshore wells drilled in 1991 is 749 wells
(Petzet, 1990).
API. 1988. Basic Petroleum Data Book. American Petroleum Institute, January
1988.
CCC. 1988. Oil and Gas Activities Affecting California's Coastal Zone: A
Summary Report. California Coastal Commission, December 1988, pages 31-33.
DOE. 1989. Department of Energy. Department of Energy Comments on the
Technical, Economic, and Environmental Data made available in 53FR 41356
on October 21, 1988, for the Offshore Oil and Gas Subcategory Effluent
Guidelines. Attachment with cover letter from Ted Williams, DOE to Dennis
Ruddy, EPA, 18 January, 1989.
DOI. 1990. Department of Interior News Release, Statement by Secretary of the
Interior Manuel Lujan concerning President's decisions regarding America's
offshore oil and gas program, U.S. Department of Interior, 26 June 1990.
EPA. 1985. Economic Impact Analysis of Proposed Effluent Limitations and
Standards for the Offshore Oil and Gas Industry. U.S. Environmental
Protection Agency, EPA 440/2-85-003, July 1985.
Kaplan. 1990. "Platform Projections and the Percentage of Shallow Wells
Revised for "Shallow" as Defined by 4-, 6-, and 8-miles from Shore,"
Memorandum to File, 18 July 1990.
Meier. 1990. Personal Communication between Eric M. Sigler, ERG, and Mark
A. Meier, California State Lands Commission, dated October 1, 1990.
MMS. 1985a. 30-Year Projections of Oil and Gas Production from the United
States Outer Continental Shelf Areas. Memorandum from Chief, Offshore
Resource Evaluation to Associate Director for Offshore Leasing, U.S.
Department of Interior, U.S. Minerals Management Service, MMS, 1985.
MMS. 1985b. Certain Input Values Used in the 30-Year Projection of Future Oil
and Gas Production From United States Outer Continental Shelf Areas,
Attachment to MMS 1985a, U.S. Minerals Management Service, 1985.
MMS. 1986. Proposed 5-Year Outer Continental Shelf Oil and Gas Leasing
Program Mid-1987 to Mid-1992. U.S. Department of the Interior, U.S.
Minerals Management Service, MMS 86-1029, 1986.
MMS. 1987. Secretarial Issue Document. Proposed Final, U.S. Department of the
Interior, U.S. Minerals Management Service, MMS, April 1987.
MMS. 1990a. Status of Leases. U.S. Department of the Interior, U.S. Minerals
Management Service, Pacific OCS Region, August 1990, page 24.
MMS. 1990b. Pacific Update August '87 - November '89. U.S. Department of the
Interior, U.S. Minerals Management Service, MMS 90-0013, Tables 11 & 13,
1990.
4-61
-------
OGJ. 1990. "Despite output push, U.S. probably cannot avoid oil production
decline in 1991," Oil and Gas Journal. 17 September 1990.
Petzet. 1990. "U.S. Drilling to Rise Centers Oil Prices Slump," Oil and Gas
Journal. 28 January 1991, 64-66.
Winham. 1990. Personal Communication between Eric M. Sigler, ERG, and Dena
Winham, MMS Pacific DCS Region, dated October 2, 1990.
4-62
-------
SECTION FIVE
ECONOMIC METHODOLOGY
This section describes the model that has been developed to simulate the
economic performance of offshore drilling and production projects. Thirty-
four projects are constructed to reflect cost and productivity differences
throughout the country. Costs for current practices for the disposal of
drilling and production wastes are incorporated into the 34 baseline projects.
Section 5.1 presents a description of the economic simulation methodology
while the 34 regional projects are described in Section 5.2. The baseline
summary financial statistics for NSPS projects are given in Section 5.3 while
those for BAT projects are listed in Section 5.4.
Ten appendices to this section provide details of all the data sets and
calculations described in summary fashion in the report text (Appendices A
through J). These appendices also describe the input data and algorithm logic
of the baseline economic cases.
5.1 DESCRIPTION OF THE ECONOMIC MODEL
To estimate the effects of the regulatory approaches, the economic
performance of model projects is simulated before and after new pollution
control requirements. This section reviews the economic model and its
components.
5.1.1 Economic Model Overview
The economic model simulates the performance and measures the
profitability of a petroleum production project. For the purposes of this
report, a project is defined as a single platform or island. For each
project, economic data representing typical costs for leasing, exploration,
delineation, production, and operating are entered, as well as typical
production rates, oil and gas selling prices, and other pertinent data. The
model calculates the annual after-tax cash flow for each year of operation, as
well as cumulative (i.e., lifetime) measures of a project's performance such
as net present value (NPV) and internal rate of return (IRR).
5-1
-------
The schematic design of the model is summarized in Figure 5-1. Two sets
of exogenous values -- project-specific and general-model variables -- are
entered into the model. The model provides the integrative calculation
procedures and algorithms that duplicate (1) the oil industry's standard
accounting procedures, (2) federal taxation rules after the Tax Reform Act of
1986, and (3) standard financial rate-of-return calculation methods. The
outputs of the economic model are a series of yearly project cash flows and
cumulative performance measures.
The regulatory approaches are incorporated into the economic model by
adding relevant capital costs and operating expenses to the set of cost data.
The model calculates all yearly and cumulative outputs for both the base case
and regulated cases for each project.
5.1.2 Parameter Description
A distinct set of parameter values is required for each of the model
projects and constitutes a complete economic description of each project. The
following categories of parameters are incorporated into each project:
1. Lease Cost - Bonus payments to Federal or state governments or to
private individuals for the land.
2. Geological and Geophysical Cost - Cost of analytic work prior to
drilling.
3. Drilling Cost per Well.
4. Cost of Production Equipment.
5. Discovery Efficiency - The number of wells drilled for one successful
well.
6. Production Rates - Initial production rates of oil and gas and
production decline rates.
7. Operation and Maintenance Costs.
8. Tax Rates - Rates for: Federal and state income taxes, severance
taxes, royalty payments, depreciation, and depletion.
9. Price - Wellhead selling price of oil and gas (also called the "first
purchase price" of the product).
10. Cost of Capital - Real rate of return for the industry.
11. Timing - Length of time required for each project phase (i.e.
leasing, exploration, delineation, development, and production).
5-2
-------
INPUTS
Project Specific Inputs
Location
Cost characteristics
Production profile
General Exogenous Inputs
Discount rate
Price of oil and gas
Tax and accounting practices for oil and
gas companies
ERG Model Algorithms for:
Production logic
Cost logic
Pollution control cost logic
Sequencing logic
Price revenue and earnings calculation
Financial analysis
Summary calculations
OUTPUTS
Cumulative project internal rate of return
Yearly project financial results
Cumulative project financial results
Cumulative present value of project results
Figure 5-1. General schematic diagram of ERG economic model.
5-3
-------
The parameter values used in the analysis are summarized in Section 5.2 and
described more fully in Appendices A through I.
5.1.3 Model Calculation Procedures
The model's calculational procedures are a set of rules and logic used to
convert the project parameters into measures of a project's financial
performance. These procedures fall into several categories:
Sequencing Logic - The economic model includes a scheduling sequence for
each phase of a project life: leasing, exploration, delineation, development,
and production. Project lead times range from as little as one year for small
single-well platforms in the Gulf of Mexico to 12 years for a deep-water
platform in Arctic Alaska.
Production Logic - The model equations use exogenous values for peak
production rates and production decline rates to define a production profile
for the well. Summary measures of production for the entire project lifetime
are also calculated.
Cost Logic - The model equations use exogenous cost data to define yearly
capital and operating costs of each project. Exogenous parameters include
capital cost (e.g., leasehold costs, geological and geophysical costs,
drilling cost, and production equipment cost) and operating costs. Using the
model sequencing logic, the exogenous cost information is converted to annual
capital and operating cost streams. Summary measures of all capital and
operating costs are calculated for the entire project lifetime.
Pollution Control Cost Logic - A set of equations incorporates the capital
and operating costs of additional pollution control approaches into the
project cost stream, thus creating a simulation of the economic effect of
alternative regulatory approaches.
Cost Accounting Practices - Specialized oil industry accounting procedures
are applied to project cost streams. Capital and operating costs are treated
in accordance with oil industry accounting practices. The model calculates
the expensed and capitalized portions of each capital expenditure, which in
turn are used as a base to estimate depreciation for each year of the
project's life. Cost accounting practices hold for both onshore and offshore
operations with a distinction being made that costs such as labor, fuel, etc.,
5-4
-------
incurred in the construction of offshore platform be considered as intangible
drilling costs (Houghton 1987). Firms with both "upstream" activities --
exploration, development, and production -- and "downstream" activities --
transportation, refining and marketing -- are called major integrated oil
companies (the "majors"). Majors expense 70 percent of intangible drilling
costs. Depletion allowances, which are also credited to the project, are
calculated on a cost basis for majors.
Firms with only "upstream" activities are called independents. Cost
accounting practices differ for independents -- they may expense 100 percent
of intangible drilling costs and may take a depletion allowance on either a
cost or percentage basis. Since most activity in the offshore regions is
performed by major oil companies, the analysis incorporates those cost
accounting measures. Independents play a larger role in coastal oil and gas
operations. An investigation of coastal operations may warrant consideration
of the alternate cost accounting practices appropriate for independents.
Price and Revenue Calculations - The wellhead price (also known as a
"first purchase price") of oil and gas is an exogenous parameter for the
model. These vary by region; see Section 5.2. The prices are multiplied by
the annual production volumes to calculate annual project revenues. Revenues
are calculated both as an annual stream and as a total for project lifetime.
Earnings and Cash Flow Analysis - The model calculates a project's annual
earnings, which are the difference between a project's revenues and its costs.
Tax and royalty payments are subtracted from before-tax earnings to calculate
annual cash flow. Depreciation and depletion are treated in these
calculations according to Federal laws. For the sake of simplicity, all
severance taxes are calculated as a percentage of gross income minus
royalties. This is the most common situation, although some states calculate
severance taxes on a fee-per-unit-production basis (e.g., $0.075 per Mcf).
Financial Performance Calculations - A variety of summary financial
measures are calculated in the model. Annual project cash flows are
discounted to the present using an 8 percent discount rate to calculate to net
present value (NPV) of the project. The internal rate of return (i.e., the
discount rate at which the present value of the project is zero) is also
calculated. The present value of all project costs is divided by the present
value of all petroleum production to calculate the average cost per unit of
production.
5-5
-------
5.1.4 Interpretation of Model Results
Based on the economic model logic described above, a number of summary
statistics and performance measures are calculated for each project,
including:
1. Internal rate of return (IRR).
2. Corporate cost per unit of production.
3. Production cost per unit of production.
4. Net present value (NPV).
5. Present value equivalent of production.
6. Present value of all project costs.
7. Present value of all project revenues.
8. Present value of additional pollution control costs.
The analysis of the economic status of the base cases, presented in Section
5.2, focuses on the first five parameters listed above as performance
measures.
The internal rate of return of a project is a measure of its
profitability. If the IRR of a project is greater than the corporation's
actual cost of capital, the project is profitable. In this analysis, the real
cost of capital is valued at 8 percent. Thus, projects with a real IRR higher
than 8 percent are considered profitable. The internal rate of return should
not be confused with a "hurdle rate." The latter is a projected rate of
return that must be exceeded before a company is willing to undertake a
project. Hurdle rates will vary by company.
The corporate cost of production is defined as the present value of all
net corporate cash outflows for the project life (i.e., the cost of leasing,
exploration, development, operating, royalties, severance tax and income tax
payments, adjusted for the tax savings due to depreciation and depletion)
divided by the present value of all production (e.g., barrel-of-oil equivalent
of oil and gas production). The present value calculations use a cost-of-
capital interest rate of 8 percent to discount costs, cash flow, and
production. If the corporate cost per unit of production is lower than the
projected wellhead selling price, the project is considered viable.
5-6
-------
The production cost per unit of production is a measure of the value of
net social resources expended in the development and operation of offshore
petroleum projects. The difference between company cost and production cost
is that production cost ignores the effect of transfers that do not use social
resources, such as income taxes, revenue taxes, and royalties. Included in
the calculation of this cost are the present values of: all investment costs,
operating costs, and geological/geophysical expenses. The sum of these costs
is divided by the present value equivalent of production to obtain production
cost.
The net present value (NPV) is calculated as the difference between then
present values of all cash inflows and all cash outflows. A positive value is
indicative that a project generates more revenues than investing the capital
elsewhere in a different opportunity with an expected rate of return equal to
the cost of capital used in this analysis.
In interpreting the summary statistics from the model simulations, several
factors must be considered. First, the input data are of varying quality.
There is an annual report on nationwide drilling costs and the data can be
adjusted to separate onshore and offshore drilling costs. In contrast, lease
equipment costs, initial well production rates, and production decline rates
are not readily available. Second, the use of "typical projects" implies an
aggregation of data and a concomitant loss of fine detail. There will
certainly be platforms that are more or less profitable than those in this
analysis. This analysis strives to identify a set of projects that reasonably
spans the diverse conditions within the industry and to evaluate the economic
impacts of alternative pollution control approaches upon each of those
projects.
5.2 CONSTRUCTION OF REGIONAL OFFSHORE OIL AND GAS PROJECTS
5.2.1 Overview
Four regions are analyzed in this study -- the Gulf of Mexico, the
Pacific, the Atlantic, and Alaska. Model projects,' ranging in size from a 1-
well platform in the Gulf to a 70-well platform in the Pacific, were developed
to span the diversity of size seen in the offshore oil and gas industry.
Three categories of project were developed on the basis of production: oil-
only, oil with casinghead gas (hereafter referred to as "oil/gas"), and gas-
5-7
-------
only. In all, 34 model projects were identified and included in this
analysis; see Table 5-1. Appendix A contains a fuller description of the
selection of the model projects.
5.2.2 Description of the Offshore Oil and Gas Projects
Parameter values for all projects are presented in Tables 5-2 through 5-7.
All values are in 1986 dollars and are based on data for 1986 unless otherwise
noted. Each parameter is defined below.
Project timing assumptions affect when capital investments are made and
when production first begins. First production in the Gulf of Mexico begins
one year after lease sale for small 1-well platforms (Table 5-2). Larger
projects in the Gulf may take up to six years before production begins (see
Gulf 58, Table 5-4). For the Pacific, first production occurs from 5 to 10
years after lease sale, depending upon project size (Table 5-4). No
production is occurring in the Atlantic at this time; project lead-times of 5
to 7 years are based on information in recent studies (Table 5-5). For
Alaska, production is assumed to occur six years after lease sale in Cook
Inlet and up to 12 years after lease sale in the Arctic (Table 5-7). Appendix
B contains a more complete description of timing assumptions.
Lease costs are based on 1986 DCS sales in the Gulf, on previous sales for
the other regions, and other factors (see Table 5-8 and Appendix C). They
range from $5,000 for the Atlantic project to $28,391,000 for the 58-well
platform in the Gulf of Mexico. Geological and geophysical expenses are 110.5
percent of the leasing costs in the Lower 48 State region and 107.7 percent of
leasing costs for Alaska projects (see Appendix D). The discovery efficiency
is the ratio of productive exploratory wells to all exploratory wells drilled
in that region. A value of.10 percent was chosen for the Atlantic since no
productive wells have yet been discovered in this region. Discovery
efficiencies for the Gulf, Pacific, and Alaska are 14 percent, 14 percent, and
27 percent, respectively (see Table 5-9 and Appendix C).
Well costs for exploratory and delineation wells are based on dry hole
costs, since even if they are discovery wells, they are not turned into
producers. These well costs are based on data in the 1986 Joint Association
Survey on Drilling Costs for the number of wells, type of well, footage
drilled, and costs for each state and Federal region with offshore activity
(API 1987a; see Table 5-10 and Appendix D). The average cost for an offshore
5-8
-------
TABLE 5-1
DISTRIBUTION OF OIL, OIL/GAS, AND GAS PRODUCING PLATFORMS
BY REGION AND SIZE
PRODUCTION TYPE
REGION AND
WELLS LOT SIZE
Gulf la'
Gulf Ib1
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Atlantic 24
Pacific 16
Pacific 40
OIL
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
OIL/GAS
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
GAS
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
COMMENTS
No gas -only platforms among large
platforms .
No gas -only platforms among large
platforms .
No gas -only platforms among large
Atlantic 24
Pacific 16
Pacific 40
Pacific 70
Cook Inlet 12/24
Beaufort Sea 48
- Gravel island
- Platform
Norton Basin 34
Navarin 48
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
Yes
Yes
No
No
Yes"
No
No
No
No
No gas -only platforms among large
platforms .
No gas -only platforms among large
platforms .
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
Source: ERG model project configurations based on typical projects reported in the
Department of the Interior Mineral Management Service platform
inspection system and the literature.
"The Gulf la shares production equipment with three other single-well stuctures
while the Gulf Ib has its own production equipment.
'The gas-only case is modeled as 12 wells.
5-9
-------
Gulf_dsc.,wk1
TABLE 5-2
BASELINE PARAMETERS FOR GULF OF MEXICO PROJECTS IN STATE WATERS
Parameter
Timing
lease to exp.
exp. to del.
del. to dev.
dev. to op
Total -yrs to op.
Exploration
Lease Bid ($000)
G & G expenses
Discovery eff.
Well cost ($000)
Platform/disc.
Delineation
Number of wells
Well cost ($000)
Development
Lease Eq. ($000)
Well cost ($000)
Number of wells
Uells/yr installed
Production
oil (bopd)
gas (MMcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 » M ($000)
Financial
oil ($/bbl)
gas ($/Mcf)
Corporate Tax Rate
Royalty
Severance - oi I
Severance - gas
(
oil
0
0
0
1
1
$586
110. 5X
14X
$4,355
4.3
0
$4,355
$0
$4,906
1
1
500
-
2
15X
$372
$23.82
-
34X
22X
6.19X
6.19X
iulf 1a
oil /gas
0
0
0
1
1
$586
110. 5X
14X
$4,355
4.3
0
$4,355
$0
$4,906
1
1
500
0.835
2
15X
$372
$23.82
$2.57
34X
22X
6.19X
6.19X
gas
0
0
0
1
1
$586
110. 5X
14X
$4,355
4.3
0
$4,355
$0
$6,302
1
1
-
4.000
4
15X
$372
-
$2.57
34X
22X
6.19X
6.19X
(
oil
0
0
0
1
1
$586
110. 5X
14X
$4,355
4.3
0
$4,355
$1,166
$4,906
1
1
500
-
2
15X
$200
$23.82
-
34X
22X
6.19X
6.19X
iulf 1b
oil /gas
0
0
0
1
1
$586
110. 5X
14X
$4,355
4.3
0
$4,355
$1,166
$4,906
1
1
500
0.835
2
15X
$200
$23.82
$2.57
34X
22X
6.19X
6.19X
gas
0
0
0
1
1
$586
110. 5X
14X
$4,355
4.3
0
$4,355
$1,166
$6,302
1
1
-
4.000
4
15X
$200
-
$2.57
34X
22X
6.19X
6.19X
Note: 1986 dollars.
Source: ERG estimates.
5-10
-------
Gulf_dsc.wk1
TABLE 5-3
BASELINE PARAMETERS FOR GULF OF MEXICO PROJECTS IN STATE WATERS (cont.)
Parameter
Timing
tease to exp.
exp. to del.
del. to dev.
dev. to op
Total -yrs to op.
Exploration
Lease Bid ($000)
G & G expenses
Discovery eff .
Well cost ($000)
Platform/disc.
Delineation
Number of wells
Well cost ($000)
Development
Lease Eq. ($000)
Well cost ($000)
Number of uells
Wells/yr installed
Production
oil (bopd)
gas (Pitef/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 4 M ($000)
Financial
oil ($/bbl)
gas ($/Mcf)
Corporate Tax Rate
Royalty
Severance * oil
Severance - gas
G
oil
0
0
1
1
2
$2,271
110. 5X
14X
$4,355
4.3
0
$4,355
$4,664
$4,906
4
4
500
-
2
15X
$689
$23.82
-
34X
22X
6.19X
6.19X
iulf 4
oil /gas
0
0
1
1
2
$2,271
110. 5X
14X
$4,355
4.3
0
$4,355
$4,664
$4,906
4
4
500
0.835
2
15X
$689
$23.82
$2.57
34X
22X
6.19X
6.19X
gas
0
0
1
1
2
$2,271
110. SX
14X
$4,355
4.3
0
$4,355
$4,664
$6,302
4
4
.
4.000
4
15X
$689
.
$2.57
34X
22X
6.19X
6.19X
C
oil
0
0
1
1
2
$3,407
110. SX
14X
$4,355
4.3
1
$4,355
$6,996
$4,906
6
6
500
-
2
15X
$910
$23.82
-
34X
22X
6.19X
6.19X
iulf 6
oil /gas
0
0
1
1
2
$3.407
110. 5X
14X
$4,355
4.3
1
$4,355
$6,996
$4,906
6
6
500
0.835
2
15X
$910
$23.82
$2.57
34X
22X
6.19X
6.19X
gas
0
0
1
1
2
$3,407
110. SX
14X
$4,355
4.3
1
$4,355
$6,996
$6,302
6
6
-
4.000
4
15X
$910
-
$2.57
34X
22X
6.19X
6.19X
C
oil
0
1
0
2
3
$5,678
110. SX
14X
$4,355
4.3
2
$4,355
$11,660
$4,906
10
6
500
-
2
15X
$2,312
$23.82
-
34X
22X
6.19X
6.19X
iulf 12
oil /gas
0
1
0
2
3
$5,678
110. 5X
14X
$4,355
4.3
2
$4,355
$11,660
$4,906
10
6
500
0.835
2
15X
$2,312
$23.82
$2.57
34X
22X
6.19X
6.19X
gas
0
1
0
2
3
$5,678
110.5%
14%
$4,355
4.3
2
$4,355
$11,660
$6,302
10
6
-
4.000
4
15X
$2,312
-
$2.57
34X
22X
6.19%
6.19X
Note: 1986 dollars.
Source: ERG estimates.
5-11
-------
gulf_dsc.wlc1
TABLE 5-4
BASELINE PARAMETERS FOR GULF OF MEXICO PROJECTS IN FEDERAL WATERS
Parameter
Timing
lease to exp.
exp. to del.
del. to dev.
dev. to op
Total-yrs to op.
Exploration
Lease Bid ($000)
G & G expenses
Discovery eff.
Well cost ($000)
Platform/disc.
Delineation
Number of wells
Well cost ($000)
Development
Lease Eq. ($000)
Well cost ($000)
Number of wells
Wells/yr installed
Production
oil (bopd)
gas (MMcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 & M ($000)
Financial
oil ($/bbl)
gas ($/Mcf)
Corporate Tax Rate
Royalty
Severance - oil
Severance gas
(
oil
0
1
0
2
3
$10,221
110. 5X
14X
$4,355
4.3
2
$4,355
$20,988
$4,906
18
12
500
-
2
15X
$3,311
$23.82
-
34X
17X
-
-
Julf 24
oil/gas
0
1
0
2
3
$10,221
110. 5X
14X
$4,355
4.3
2
$4,355
$20,988
$4,906
18
12
500
0.835
2
15X
$3,311
$23.82
$2.57
34X
17X
-
-
gas
.
0
1
0
3
4
$10,221
110. 5X
14X
$4,355
4.3
2
$4,355
$20,988
$6,302
18
12
-
4.000
4
15X
$3,311
.
$2.57
34X
17X
-
Gulf
oil
0
1
0
2
3
$18,170
110. 5X
14X
$4,355
4.3
2
$4,355
$37,312
$4,906
32
12
500
-
2
15X
$4,688
$23.82
-
34X
17X
-
40
oil/gas
0
1
0
2
3
$18,170
110.5X
14X
$4,355
4.3
2
$4,355
$37,312
$4,906
32
12
500
0.835
2
15X
$4,688
$23.82
$2.57
34X
17X
'
Gull
oil
0
2
2
2
6
$28,391
110. 5X
14X
$4,355
4.3
2
$4,355
$58,300
$4,906
50
12
500
-
2
15X
$6,471
$23.82
-
34X
17X
F 58
oil/gas
0
2
2
2
6
$28,391
110. 5X
14X
$4,355
4.3
2
$4,355
$58,300
$4,906
50
12
500
0.835
2
15X
$6,471
$23.82
$2.57
34X
17X
-
-
Note: 1986 dollars.
Source: ERG estimates.
5-12
-------
pac_dsc.uk1
TABLE 5-5
BASELINE PARAMETERS FOR PACIFIC PROJECTS
Parameter
Timing
tease to exp.
exp. to del.
del. to dev.
dev. to op
Total -yrs to op.
Exploration
Lease Bid ($000)
G & G expenses
Discovery eff.
Well cost ($000)
Platform/disc.
Delineation
Number of wells
Well cost ($000)
Development
Lease Eq. ($000)
Well cost ($000)
Number of wells
Uells/yr installed
Production
oil (bopd)
gas (MMcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 1 M ($000)
Financial
oil ($/bbl)
gas ($/Mcf)
Corporate Tax Rate
Royalty
Severance oil
Severance - gas
Pacific
oil/gas
1
1
1
2
5
$2,236
110. 5X
14X
$5,888
2
2
$5,888
$16,324
$2,357
U
12
900
0.478
2
33. OX
$4,008
$17.50
$1.89
34X
17X
"
16
gas
1
1
2
2
6
$2,236
110. 5X
14X
$5,888
2
2
$5,888
$16,324
$5.157
14
12
5.000
4
22. OX
$4,008
.
$1.89
34X
17X
-
"
Pacific 40
oi I /gas
1
2
3
2
8
$5.272
110. 5X
14X
$5,888
2
2
$5,888
$38,478
$2,357
33
12
900
0.478
2
33.0X
$6,872
$17.50
$1.89
34X
22X
-
"
Pacific 70
oil/gas
1
2
5
2
10
$9,585
110. 5X
14X
$5,888
2
2
$5,888
$69,960
$2,357
60
12
900
0.478
2
33. OX
$11,212
$17.50
$1.89
34X
17X
."
Note: 1986 dollars.
Source: ERG estimates.
5-13
-------
att_dsc
TABLE 5-6
BASELINE PARAMETERS FOR ATLANTIC PROJECTS
Parameter
Timing
lease to exp.
exp. to del.
del. to dev.
dev. to op
Total -yrs to op.
Atlantic 24
oil
1
2
2
2
7
gas
1
2
2
4
9
Exploration
Lease Bid (SOOO) $5 $5
G & G expenses 110.5X 110.5X
Discovery eff. 10X 10X
Well cost (SOOO) $27,792 $27,792
Platform/disc. 1 1
Delineation
Neuter of wells 22
Well cost (SOOO) $27,792 $27,792
Development
Lease Eq. ($000) $23,320 $23,320
Well cost ($000) $7,226 $7,226
Number of wells 20 20
Uells/yr installed 12 12
Production
oil (bopd) 1,000
gas (MMcf/day) - 7.5
Yrs. at Peak Prod. 2 8
Prod. Decline rate 15X 15X
Annual 0 t M ($000) $5,009 $5,009
Financial
oil (S/bbl) $17.50
gas ($/Mcf) - $1.89
Corporate Tax Rate 34X 34X
Royalty 17X 17X
Severance - oil
Severance - gas
Note: 1986 dollars.
Source: ERG estimates.
5-14
-------
ak_dsc
TABLE 5-7
BASELINE PARAMETERS FOR ALASKA PROJECTS
Parameter
Timing
tease to exp.
exp. to del.
del. to dev.
dev. to op
Total-yrs to op.
Exploration
Lease Bid ($000)
G & G expenses
Discovery eff.
Well cost (SOOO)
Platform/disc.
Delineation
Number of wells
Well cost (SOOO)
Development
Lease Eq. (SOOO)
Well cost (SOOO)
Number of wells
Uells/yr installed
Production
oil (bopd)
gas (MMcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 & M
F i nanc i a I
oil (S/bbl)
gas ($/Mcf)
Corporate Tax Rate
Royalty
Severance - oi I
Severance - gas
Cook
Inlet 24
oil/gas
1
1
2
2
6
$56
107.7X
27X
$13.851
1
2
$13,851
$1 00 ,000
$5,612
20
12
1,960
0.9
2
10X
$5,230
$19.58
$2.11
34X
22X
Cook
Inlet 12
gas
1
1
2
2
6
$56
107.7X
27X
$13,851
1
2
$13,851
$50,000
$3,188
10
6
-
15.00
16
15X
$3,677
-
$2.11
34X
22X
Beaufort
Gravel
oil
2
3
3
3
11
$7,097
107.7X
27X
$13,851
1
3
$13,851
$270,000
$5,612
40
12
1,960
-
2
10X
$18,100
$14.80
34X
22X
Beaufort
Platform
oil
2
3
4
3
12
$7,097
107.7X
27X
$13,851
1
3
$13,851
$303,700
$5,612
40
12
1,960
2
10X
$25,300
$14.80
34X
17X
Navarin
Platform
oil
2
3
3
3
11
$7,097
107.7X
27X
$13,851
1
3
$13,851
$524,400
$5,612
40
12
1,960
-
2
10X
$19,900
$14.80
-
34X
17X
-
-
Norton
Platform
oil
2
2
2
3
9
$4,968
107.7X
27X
$13.851
1
3
$13,851
$174,500
$5,612
28
12
1,960
-
2
10X
$19,000
$14.80
-
34X
17X
-
-
Note: 1986 dollars.
Source: ERG estimates.
5-15
-------
Slease.uk!
TABLE 5-8
LEASE PRICES FOR MODEL PROJECTS
Region
Gulf
Pacific
Atlantic
Alaska
Hunter of
Model Producing Production
Project Wells Ratio
1
4
6
12
24
40
58
16
40
70
24
Cook Inlet
Cook Inlet-gas
Beaufort -grave I
Beaufort-plat.
Norton
Navarin
1
4
6
10
18
32
50
14
33
60
20
20
10
40
40
28
40
0.3
1.0
1.5
2.5
4.5
8.0
12.5
0.4
1.0
1.8
1.0
1.0
1.0
1.0
1.0
0.7
1.0
Exploratory
Lease Wells/ Model
Price Discovery Platforms/ Project Lease
($000) Well Discovery Price (SOOO)
$1,318
$1,318
SI, 318
$1,318
$1,318
$1,318
$1,318
$1,423
$1,423
$1,423
$0.475
$15
$15
$1,918
$1,918
$1,918
$1,918
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
10.00
3.70
3.70
3.70
3.70
3.70
3.70
4.3
4.3
4.3
4.3
4.3
4.3
4.3
2.0
2.0
2.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
$568
$2,271
$3,407
$5,678
$10,221
$18,170
$28,391
$2,236
$5,272
$9,585
$5
$56
$56
$7,097
$7,097
$4,968
$7,097
Note: 1986 dollars.
Source: ERG estimates.
5-16
-------
disc eff.wkl
TABLE 5-9
TOTAL EXPLORATORY OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Region
Alaska
California
Oregon
Washington
Federal Pacific
TOTAL PACIFIC
Alabama
Florida
Louisiana
Texas
Federal -COM
TOTAL GULF OF MEXICO
ATLANTIC
GRAND TOTAL
Oil
20
44
0
0
0
44
0
0
267
45
0
312
0
376
Gas
7
10
0
0
0
10
2
0
349
273
0
624
0
641
Dry
73
294
8
6
38
346
0
24
3999
1732
241
5996
36
6451
Number of
Exploratory
Discovery Wells Per
Total Efficiency Discovery
100
348
8
6
38
400
2
24
4615
2050
241
6932
36
7468
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.00
0.14
3.70
7.41
7.41
na
7.34
Note: Well count includes wells in both Federal and State waters.
na = not applicable
Source: API 1988; MHS 1986b.
5-17
-------
uellnew.wkl
TABLE 5-10 19-Jan-90
AVERAGE WELL DEPTHS AND COSTS - 1986 DATA*
Region
Alaska
California
Louisiana
Texas
Fed-Alaska
Fed - Gulf
Fed-Pacific
AK- TOTAL
PAC- TOTAL
GULF -TOTAL
y, ALL OFFSHORE
1
*- ATLANTIC
00
Oil
Depth Cost per Cost per
(ft) foot (S/ft) well ($)
10.868
6,887
9,678
8,395
ERR
11.583
6,777
10,868
6,872
9,885
9,426
$335.47
$229.97
$274.13
$308.40
ERR
$716.27
$527.33
$335.47
$267.98
$340.37
$331.64
$3,645,773
$1.583.662
$2,653.026
$2,588,998
ERR
$8,296,256
$3,573,495
$3,645.773
$1,841.604
$3.364.631
$3,126,096
see discussion
Gas
Depth Cost per
(ft) foot ($/ft)
7,721
6.477
10,848
11,995
ERR
9,873
ERR
7,721
6,477
11,174
11,112
in text
$231.95
$721.18
$337.29
$486.59
ERR
$631.17
ERR
$231.95
$721.18
$408.05
$409.22
Cost per
well ($)
$1,790,891
$4,671,091
$3,658,899
$5,836.414
ERR
$6.231,854
ERR
$1,790,891
$4,671,091
$4,559.374
$4.547.079
Depth
(ft)
9.662
ERR
10.888
10.880
8,868
12,301
7.063
9.186
7,063
11.171
11.086
Dry
Cost per
foot ($/ft)
$1,047.05
ERR
$302.53
$376.95
$1,842.62
$641.10
$833.59
$1,507.90
$833.59
$389.81
$406.70
Cost per
well ($)
$10,116.095
ERR
$3,293,896
$4,101.249
$16,340.956
$7,886,401
$5,887,793
$13,851,011
$5.887.793
$4.354,555
$4,508.601
$27.791,575
Depth
(ft)
10.440
6.870
10,394
11.321
8.868
11,823
6.896
10,145
6,875
10.750
10.476
Total
Cost per
foot ($/ft)
$430.89
$248.87
$299.71
$433.69
$1.842.62
$661.58
$658.03
$662.27
$329.61
$379.62
$382.27
Cost per
well ($)
$4.498.524
$1.709.680
$3,115,359
$4.909.698
$16.340.956
$7,821,666
$4.537,786
$6.718.980
$2,266,029
$4,081,100
$4,004,805
* Current dollars.
Note: ERR denotes no wells drilled in that category in 1986.
Source: API 1987b.
-------
well in 1986 is $4,004,805. This value is the average of all wells, both dry
and productive.
The number of platforms per discovery well is based on the number of
discovery wells and platforms for the Gulf, on the number of platforms per
field for the Pacific, and on engineering studies of projected activity in the
Atlantic and Alaska (see Appendix C). Anywhere from 0 to 3 delineation wells
are modeled for a project based on the size and location of that project
(Appendix E).
Platform costs are included as part of the drilling costs in the JAS
survey. These costs do not include lease equipment such as flow lines, flow
tanks, separators, etc. A separate entry for lease equipment costs is made
based on the size of the project and the 1986 API Survey on Oil and Gas
Expenditures (API 198b); see Table 5-11. Alaska development costs are based
on the Steelhead platform in Cook Inlet and on data in Oil and Gas
Technologies for the Arctic and Deepwater (OTA 1985); see Table 5-12.
Well costs for development wells are based on the costs for productive
wells and are based on the 1986 Joint Association Survey. These costs are
adjusted by the discovery efficiency for development wells and distinctions
are made between oil wells and gas wells (Table 5-13). Not all wellslots on a
platform may be utilized by productive wells; the number of producing wells
per platform ranges from 3/4 to 5/6 of the wellslots. Each well is assumed to
take two months to drill; a single rig can therefore drill six wells per year.
Platforms with more than 12 wellslots are assumed to accommodate two drilling
rigs simultaneously. These platforms may therefore have development wells
installed at a rate of 12 per year. A more complete discussion of development
phase assumptions and data is located in Appendix F.
Initial production rates, years at peak production, and production decline
rates interact to form the "production profile" of a well. Production
profiles can vary widely by well, even among wells on the same platform. The
production profiles used in this analysis are based on field data, the
production profile used by MMS for recent EIS in the Gulf of Mexico, and
engineering studies. Peak production rates and production decline rates are
shown in Tables 5-14 and 5-15, respectively. Projects with oil production are
assumed to stay at peak production for two years. Gas-only projects stay at
peak production for four years (Gulf and Pacific), eight years (Atlantic), or
16 years (Cook Inlet, Alaska). Appendix G contains an expanded discussion of
these parameters.
5-19
-------
Equip.wk1
TABLE 5-11
LEASE EQUIPMENT COSTS GULF, PACIFIC AND ATLANTIC
Region
Gulf
Pac i f i c
Project
1b
4
6
12
24
48
58
16
40
70
Number of
Producing
Wells
1
4
6
10
18
32
50
14
33
60
Lease Equipment
Costs (SMM 1986)
$1.166
S4.664
$6.996
$11.660
S20.988
$37.312
$58.300
$16.324
$38.478
$69.960
Atlantic 24 20 $23.320
Source: ERG estimates.
5-20
-------
$_akcon.wk1
TABLE 5-12
LEASE EQUIPMENT COSTS FOR ALASKA PROJECTS
Development
Cost
Project (SMM 1984)
Beaufort platform
Navarin Basin
Norton Basin
Beaufort Gravel*
Cook Inlet oil*
Cook Inlet gas*
3.162
5.460
1,038
800
Notes: * Costs are in 1986
Ul
1
ro
1984 prices
product for
deflated
producers
Non-drilling Number of
Development Islands/
Cost (SMM 1984) Platforms
2.134
3.685
700
540
200
200
dollars.
.4
.5
.7
.0
.0
.0
by 0.4X based on implicit
' durable equipment.
7
7
4
2
2
4
price
Cost per Cost per Producing Cost per
Platform Platform Wells per Well
(SMM 1984) (SMM 1986) Platform (SHM 1986)
$304
$526
$175
$270
$100
$50
.9
.5
.2
.0
.0
.0
deflators for gross
$303.7
S524.4
$174.5
$270.0
$100.0
$50.0
national
40
40
28
40
20
10
$7.
$13.
$6.
$6.
$5.
$5.
59
11
23
75
00
00
Sources: OTA 1985; OGJ 1986; Offshore 1986; Economic Report 1987.
-------
dev_cost.wk1
TABLE 5-13
DEVELOPMENT WELL COST - 1986 DATA*
Number of
Development
Welts Per
Type of Producing
Region Production Well
Ul
ro
K>
Gulf oil,
gas
Pacific oil.
gas
Alaska oil,
gas
Atlantic oil,
gas
Note: Current
oil /gas
oil /gas
oil/gas
oi I/gas
dollars.
1.4
1.4
1.09
1.09
1.12
1.12
Average
Depth
(ft)
9.
11.
6.
6.
10.
1,
see
885
174
872
477
868
721
text
Cost per foot ($/ft)
Productive
$340
$408
$267
$721
$335
$231
.37
.05
.98
.18
.47 $1
.95 $1
Dry
$389
$389
$833
$833
.507
.507
.81
.81
.59
.59
.90
.90
for description
Composite Cost
per
Development
Well ($)
$4,905.
$6.301.
$2,357.
$5,157.
$5,612.
$3.187.
$7.225.
866
845
117
007
431
985
810
Source: ERG estimates, see Table D-2
-------
TABLE 5-14
PEAK OFFSHORE PER-WELL PRODUCTION RATES
REGION
Gulf
Pacific
Alaska'
Cook Inlet
Beaufort Sea
Beaufort Sea
Norton
Navarin
Atlantic
PROJECT
1
4
6
12
24
40
58
16
40
70
12
24
- Gravel 48
- Platform 48
34
48
24
OIL ONLY
BOPD
500
500
500
500
500
500
500
900
900
900
1,960
1,960
1,960
1,960
1,960
1,000
OIL
BOPD
500
500
500
500
500
500
500
900
900
900
1,960
1,000
AND GAS
MCF/DAY
835
835
835
835
835
835
835
478
478
478
900
7,500
GAS -ONLY
MCF/DAY
4,000
4,000
4,000
4,000
4,000
4,000
4,000
5,000
15,000
Source: ERG estimates.
"There is no infrastructure to transport produced gas from the Arctic
scenarios.
5-23
-------
TABLE 5-15
PRODUCTION DECLINE RATES
PRODUCTION DECLINE RATES (%)
OIL- ONLY
REGION PROJECT OIL/GAS
Gulf 1
4
6
12
24
40
58
Pacific 16
40
70
Alaska Cook Inlet
Beaufort Sea - Gravel
Beaufort Sea - Platform
Norton Basin
Navarin Basin
15
15
15
15
15
15
15
33
33
33
10
10
10
10
10
GAS -ONLY
15
15
15
15
15
15
15
22
--
15
--
Atlantic
24
15
15
-- - Not applicable.
Source: ERG estimates.
5-24
-------
Operation and maintenance costs (O&M) are based on the data in DOE 1987a,
an annual survey performed by the DOE Energy Information Administration. The
survey includes O&M costs for a 12-wellslot platform in 100 and 300 feet of
water, as well as an 18-wellslot platform in 100, 300, and 600 feet of water
in the Gulf of Mexico. A regression analysis was fit to the data using the
model: cost - a + b(wellslots) + c(water depth). The estimates for a, b, and
c are $1,286,123, $80,859 and $840, respectively. Labor costs and workover
costs form substantial portions of the overall costs and these are not
affected by water depth. For smaller platforms, the assumptions associated
with the DOE survey costs are not appropriate. A separate methodology was
used to derive costs for the Gulf 1, Gulf 4, and Gulf 6 model projects, see
Appendix G. Table 5-16 summarizes the projected O&M costs for Gulf of Mexico
projects.
The same equation and parameters are used to estimate O&M costs for the
larger Gulf projects are used for the Pacific and Cook Inlet projects with the
costs being adjusted for regional differences (Table 5-17). O&M costs for
Arctic projects are based on scenarios in OTA 1985. The scenario O&M costs
are divided among the number of platforms/island in the scenario and then
inflated to 1986 dollars (Table 5-18). Further information on O&M costs and
their derivation is located in Appendix G.
Wellhead prices for oil and gas (also known as "first purchase price") are
an integral part of the parameter inputs for the economic impact analysis.
Like other parameters in the analysis, there is a range of uncertainty around
the point estimate used in the computer simulations. Table 5-19 lists the
annual average wellhead price for oil from 1980 to November 1987. The price
for a barrel of oil nearly doubles from $12.51 in 1979 to $21.59 in 1980 and
rises by an additional 50 percent to 31.77 in 1981. The price then declines
for the next few years and collapses in 1986 to $12.66 per barrel. Prices
presently vary around the high teens for a barrel of oil. Higher oil prices
in future years are projected by two studies. The Annual Energy Outlook 1986
presented by the Energy Information Administration projects oil prices between
$26.80 and $41.50 (in 1986 dollars per barrel) by the year 2000 (DOE, 1987b).
The study "Lower Oil Prices: Mapping the Impact," by Harvard University's
Energy and Environmental Policy Center notes that, after adjusting for
inflation and currency movements, oil prices paid by most industrial companies
is at a 15-year low (Harvard, 1988). This study also projects higher oil
prices in the future.
The regulations cover the 15-year period from 1986 through 2000. Oil
prices can fluctuate widely within a 15-year period. The analysis should
5-25
-------
gulf_o&n.Hk1
TABLE 5-16
OPERATING COSTS FOR GULF OF MEXICO PLATFORMS
Project
Number of
Uellslots
Water
Depth (ft)
Cost
($1986)
Gulf 1a 1 33 $372.213
Gulf 1b 1 33 $199,882
Gulf 4 4 33 $689,324
Gulf 6 6 33 $910,137
Gulf 12 12 66 $2,311,861
Gulf 24 24 100 $3,310,725
Gulf 40 40 200 $4,688,455
Gulf 58 58 590 $6,471,456
Source: ERG estimates.
5-26
-------
gulf_ofan.uk1
TABLE 5-17
OPERATING COSTS FOR PACIFIC, ATLANTIC, AND COOK INLET PLATFORMS
Project
Number of
Uellslots
Water
Depth (ft)
Cost
($1986)
Regional
Cost
Factor
Estimated
Cost
($1986)
Pacific 16
Pacific 40
Pacific 70
Atlantic 24
Cook Inlet 24
Cook Inlet 12
16
40
70
24
24
12
300
300
1000
$2,831,820
$4,772,439
$7,786.100
300 $3,478.693
50 $3,268,733
50 $2,298,424
1.44 $4,077,821
1.44 $6,872,312
1.44 $11,211,984
1.44 $5,009,318
1.60 $5,229,973
1.60 $3,677,478
Source: ERG estimates.
5-27
-------
ak_o&m.wk1
TABLE 5-18
OPERATION AND MAINTENANCE COSTS FOR ALASKA PROJECTS
Project
Beaufort platform
Navarin Basin
Norton Basin
Beaufort Gravel
Operation and Number of
Maintenance Islands/
Cost <$MM 1984) Platforms
$168.0
$132.0
$72.0
$120.0
7
7
4
7
Cost per
Platform
(SMM 1984)
$24.0
$18.9
$18.0
$17.1
Cost per
Platform
($MM 1986)
$25.3
$19.9
$19.0
$18.1
Note: 1984 prices inflated by 5.56X based on change in consumer price index.
Sources: OTA 1985; Economic Report 1988.
5-28
-------
TABLE 5-19
CRUDE OIL PRICES. 1980 TO NOVEMBER 1987
YEAR
MONTH
1980 Average
1981 Average
1982 Average
1983 Average
1984 Average
1985 Average
1986
January
February
March
April
May
June
July
August
September
October
November
December
1986 Average
1987
January
February
March
April
May
June
July
August
September
October
November
DOMESTIC FIRST
PURCHASE PRICES*
21.59
31.77
28.52
26.19
25.88
24.09
23.12
17.65
12.62
10.68
10.75
10.68
9.25
9.77
11.09
11.00
11.05
11.73
12.51
13.89
14.50
14.53
14.95
15.29
15.95
16.88
17.06
16.25
15.95
15.45
*Current dollars.
Source: DOE 1988.
5-29
-------
incorporate an oil price representative of the entire 15-year period and not
reflect the lower range of the oil price cycle. The projected number of wells
is based on an oil price of $21.00 per barrel (1987 dollars, see Section
Four), and the same price is used within the economic analysis. Oil prices
are regionalized by taking the ratio of the regional wellhead price to the
national price for 1985 data (see Table 5-20). For the past five years, gas
prices per Mcf have averaged 10.8 percent of the price of a barrel of oil
(Table 5-21), and this factor is used to estimate regional wellhead prices for
gas.
The Tax Reform Act of 1986 (Public Law 99-514) set the corporate tax rate
at 34 percent, assuming that the company has at least $100,000 of net income
without the model project. Royalty rates of 22 and 17 percent are used for
state and Federal leases, respectively. Severance tax rates are based on
state severance tax rates within each region. For example, the severance tax
structure for Alaska consists of nominal rates that are then adjusted by a
formula called the Economic Limit Factor. Appendix I contains the financial
assumptions and data used in this analysis.
5.23 Results of Base Case Simulations - NSPS
For new sources, the model projects encompass the entire lifespan of the
oil and gas project. Costs begin with the purchase of the lease and end after
30 years of production or when the project becomes uneconomical and shuts
down. The costs and assumptions described in Section 5.2.2 are used with the
NSPS projects.
Tables 5-22 and 5-23 summarize the financial performance of each NSFS
project, including the internal rate of return (IRR) for each project. The
real cost of capital used in this study is 8 percent. In the Gulf, the Gulf
Ib project has the lowest IRR. For the gas-only cases, the IRR is 4.7 percent
while the IRR for the oil-and-gas case is 9.5 percent. IRRs for the other
Gulf projects range from 12.8 percent to 27.3 percent. The Gulf Ib gas-only
case, then, has an IRR less than the cost of capital used in this analysis.
Economic impacts are viewed as the amount of change caused by the cost of
additional pollution control relative to the baseline value. With a small
baseline value, we would expect the Gulf Ib projects to be the most sensitive
to any change in the IRR.
5-30
-------
wellhead.wk1 23-Jan-90
TABLE 5-20
WELLHEAD PRICES AND REGIONAL RELATIONSHIPS - 1985 DATA
Region
1985
Wellhead
Price ($/bbl)
Ratio
Estimated Oil
Price (S/bbl)
1986-2000
Estimated Gas
Price <$/Mcf)
1986-2000
National $24.09 1.00 $21.00 $2.27
Offshore Gulf S27.33 1.13 $23.82 $2.57
Offshore CA $20.08 0.83 $17.50 $1.89
AK North Slope $16.98 0.70 $14.80 $1.60
AK other $22.46 0.93 $19.58 $2.11
Source: DOE 1986.
5-31
-------
oiI_gas.wk1
TABLE 5-21
RELATIONSHIP OF DOMESTIC OIL AND GAS PRICES - 1982-1987
Oi I Gas
Price Price
Year (S/bbl) (S/Mcf) Ratio
1982 $28.52 $2.46 8.6X
1983 $26.19 $2.59 9.9X
1984 $25.88 $2.66 10.3X
1985 $24.09 $2.51 10.4X
1986 $12.51 $1.94 15.5X
Aug. 1987 $17.06 $1.71 10.OX
Average Ratio 10.8X
Note: Current dollars.
Source: DOE 1987, DOE 1988.
5-32
-------
TABLE 5-22
BASELINE FINANCIAL SUMMARY STATISTICS
NSPS PROJECTS - PROJECTS WITH OIL PRODUCTION
Region
Project
PV of Total Production
(Bbls-of-oil equivalent)
Corporate
Cost
Per BOE
Production
Cost
Per BOE
Net Present
Value
($1000)
Internal
Rate of
Return
Years Of
Production
Oil and Gas Production
ui
I
u»
UI
Gulf of Mexico
Atlantic
Pacific
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Atlantic 24
Pacific 16
Pacific 40
Pacific 70
1.159,301
4,301,632
6,452,448
9,611,069
17,470,722
29,889,385
35,194,925
25.801.198
11,449.953
20.252.704
29.277.100
Alaska
Cook Inlet 61.707.003
$21.16
$18.09
$17.71
S18.23
$16.26
$16.04
$16.53
$19.05
$12.96
$12.89
$12.38
$13.22
$13.71
$8.98
$8.40
$8.95
$8.13
$7.74
$7.90
$16.52
$7.19
$6.05
$5.94
$4.18
$654
$15,649
$25,909
$33.610
$95,532
$169,856
$182.742
($66.121)
$45.337
$81.686
$132.919
$357,708
9.5X
21.4X
23.IX
20. IX
27.3X
25.2X
20.A
2.6X
39.4X
33.8X
29.5X
39. OX
20
21
21
19
21
23
25
21
9
10
12
30
Projects with Oil-only Production
Alaska
B. Gravel Is.
B. Platform
Navarin
Norton
73.172,498
67,592,103
73,172,498
61,740,561
$12.19
$11.50
$12.41
$11.22
$5.53
$6.33
$7.47
$6.09
$191.157
$233.074
$175,208
$220.856
18.4X
20.5X
15. 2X
24. IX
30
28
30
27
Source: ERG estimates.
23-Jan-90
-------
TABLE 5-23
BASELINE FINANCIAL SUMMARY STATISTICS
NSPS PROJECTS - PROJECTS WITH GAS-ONLY PRODUCTION
Corporate
PV of Total Production Cost
Region Project (Bbls-of-oil equivalent) Per BOE
Gulf of Mexico Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Atlantic Atlantic 24
Pacific Pacific 16
Alaska Cook Inlet 12
Source: ERG estimates.
Ul
I
CJ
1,534,266
5,694,403
8,541,605
12,713,538
21,412,488
38,935.162
15,493,937
52,694,332
23-Jan-90
$15.73
$13.40
$13.12
$13.52
$12.29
$12.28
$10.08
$8.41
Production
Cost
Per BOE
$11.27
$7.69
$7.25
$7.68
$7.16
$10.52
$7.03
$2.96
Net Present
Value
($1000)
($1,706)
$6,885
$12,763
$13,767
$49,389
($59.921)
$10,241
$188.211
Internal
Rate of Years Of
Return Production
4.7X
12.8X
14.0X
12. IX
16. 6X
4. IX
11. 8X
31. 6X
20
21
21
19
21
25
13
29
-------
The Pacific projects have IRRs ranging from 11.8 percent to 39.4 percent.
Alaska projects have IRRs ranging from 15.2 percent to 39.0 percent.
The Atlantic projects also have IRRs less than the cost of capital used in
this study. The IRRs for the Atlantic projects range from 2.6 percent to 4.1
percent. As with the Gulf Ib projects, the IRRs for the Atlantic projects may
be sensitive to additional pollution control costs.
Net present value: Again, the Gulf Ib model project is distinguished by
its low values. The NPV for the Gulf Ib gas-only case is negative $1,706,000.
(The NPV is negative because the IRR is below the cost of capital). The NPV
for the oil-and-gas case is $654,000. The other scenarios have NPVs anywhere
from 3 to 90 times larger. This implies that any change in the NPV of a
project caused by the costs of additional pollution control will be most
evident in the Gulf Ib cases.
Production and corporate costs per BOE (barrels-of-oil-eauivalent): The
difference in the costs is that corporate costs include cash outflows such as
income and severance taxes that involve no social resources. If the corporate
cost is less than the wellhead price, then the amount of money received for a
barrel of oil exceeds the amount of money expended to recover that barrel,
i.e., the project is considered viable. Wellhead prices exceed corporate
costs for all projects except the Gulf Ib gas-only case and those in the
Atlantic. This is consistent with the negative net present values and low
IRRs seen for these projects.
Present value equivalent of production: The range in project size is
evident -- production ranges from 1,159,301 BOE for the Gulf Ib oil-and-gas
case to 73,172,498 BOE for projects in the Beaufort Sea and Navarin Basin of
Alaska. This parameter is included in the analysis to see whether additional
costs of pollution control will curtail production once a project is
undertaken.
5.2.4 Results of Base Case Simulations - BAT Projects
BAT regulations are applied to existing projects. For drilling wastes,
BAT wells are limited to wells drilled to complete a drilling program on
existing platforms. These projects are in the beginning of their productive
lifespan and so are included in the study of the impacts of the NSPS
regulations. For production wastes, additional pollution control costs would
5-35
-------
be incurred by projects anywhere within their productive lifespan. For BAT
regulations on produced water, we evaluated the impacts on projects mid-way
through their economic life.
BAT model projects were derived from the NSPS models. First, oil prices
were changed to reflect 1987 prices in co-ordination with the March 1988
version of the MMS Platform Inspection System, Complex/Structure data base
from which the counts of producing platforms in the Federal Gulf of Mexico
were obtained (Appendix H). Oil prices of $17.54/bbl and $11.82/bbl and gas
prices of $1.89/Mcf and $1.28/Mcf were used for the Gulf and Pacific,
respectively (DOE, 1989). These runs provided baseline economic lifetimes and
production profiles.
Second, all pre-production costs were removed from the models, initial
production was set to that at the mid-life of the well, and years at peak
production was set a one year. O&M costs are the same for BAT and NSPS
projects. These computer runs provided us with the baseline BAT financial
summary statistics which are given in Table 5-24 and 5-25.
Only projects in the Gulf and the Pacific are included in the analysis of
BAT regulations. This is because there is no existing production in the
Atlantic. Current production from Cook Inlet, Alaska is in the coastal
subcategory, not the offshore category. The only existing offshore project in
Alaska is the Endicott field on gravel islands in the Beaufort Sea and this
project is required to inject its produced water as a condition of its permit
from the State. There are a few oil-only projects in the Gulf and so economic
models were developed for them.
The years of production range from 4 to 11 years while the present value
of production ranges from 246,886 BOE for the Gulf la to 21,698,858 BOE for
the large Pacific 70 project. Net present values range from $939,000 to
$101,673. The net present value for the Gulf 1 projects is positive since it
no longer has to recover pre-production costs. (The pre-production costs are
sunk costs and are not considered when the operator must decide whether the
project would recover the costs of additional pollution control requirements.)
Since there are no pre-production costs, the internal rate of return is a
meaningless measure for BAT projects.
5-36
-------
TABLE 5-24
BASELINE FINANCIAL SUMMARY STATISTICS
BAT PROJECTS - PROJECTS WITH OIL PRODUCTION
01
I
ut
-J
Region
Oil and
Gulf of
Pacific
Project
Gas Production
Mexico Gutf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific 16
Pacific 40
Pacific 70
PV of Total Production
-------
TABLE 5-25
BASELINE FINANCIAL SUMMARY STATISTICS
BAT PROJECTS - GAS-ONLY PRODUCTION
PV of Total Production Corporate Cost
Region Project (Bbls-of-oil equivalent) per BOE
Production Cost
per BOE
Net Present Value
($1000)
Years of
Production
Gulf of Mexico Gulf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific
Pacific 16
476,918
370.486
1.383.149
1.980.296
4,445,835
6.854,869
8,880.736
S8.23
$7.78
$7.61
$7.59
$7.70
$6.99
$4.84
$4.06
$3.37
$3.11
$3.08
$3.25
$3.24
$2.35
$1,194
$1.097
$4,330
$6.237
$13,520
$25,653
$21.602
7
9
9
10
9
10
Note: There are no gat-only Gulf 40 or Gulf 58 projects at present.
Source: ERG estimates. 23-Jan-90
base b.wkl
tn
I
00
-------
53 REFERENCES
API 1987a. 1986 Joint Association Survey on Drilling Costs. American
Petroleum Institute, Washington, DC, November 1987.
API 1987b. 1986 Survey on Oil and Gas Expenditures. American Petroleum
Institute, Washington, DC, November 1987.
DOE 1987a. Costs and Indices for Domestic Oil and Gas Field Equipment and
Production Operations 1986. Department of Energy, Energy Information
Administration, DOE/EIA-0185 (86), September 1987.
DOE 1987b. Annual Energy Outlook 1986 With Projections to 2000. Department of
Energy, Energy Information Administration, DOE/EIA-0383 (86), February
1987.
DOE 1988. Petroleum Marketing Monthly. November 1987. U.S. Department of
Energy, Energy Information Agency, DOE/EIA-0380(87/11), Feb. 1988,
Table 1.
DOE 1989. Petroleum Marketing Monthly. March 1989. U.S. Department of Energy
Energy Information Agency, DOE/EIA-0380(89/03), June 1989.
Harvard 1988. B. Mossavar-Rahmani et al. Lower Oil Prices: Mapping the
Impact. Harvard University, Energy and Environmental Policy Center,
Cambridge, MA, 1988.
Houghton, J.L. 1987. Arthur Young's Oil and Gas: Federal Income Taxation.
Commerce Clearing House Inc., Chicago, 1987 Edition).
OTA 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of
Technology Assessment, Washington, DC, May 1985.
5-39
-------
SECTION SIX
COSTS OF COMPLIANCE
The regulatory options for the disposal of drilling and production wastes
are discussed in Section One. The costs of compliance were developed by the
Industrial Technology Division (ITD), U.S. Environmental Protection Agency and
are discussed in more detail in the Development Document for this proposal.
6.1 DRILLING FLUIDS AND DRILL CUTTINGS
In this section, incremental costs of increased pollution control are
calculated using current permit requirements as the baseline. The annual cost
associated with each option is a function of the number of wells drilled per
year, volume of wastes generated per well, toxicity test and static sheen
failure rates, and other assumptions. Section 6.1.1 summarizes assumptions
associated with the costing efforts while Section 6.1.2 reviews current permit
requirements. Section 6.1.3 estimates costs of compliance.
.1.1 Assumptions
Number of Wells Per Year: The annual cost of compliance is based on the
estimated average of 978 or 759 wells drilled per year. These are the average
annual number of projected wells drilled between 1986 and 2000 based on an
average oil price of $21.00 per barrel (constant dollars). The first
estimate, 978, is for unrestricted development while the second estimate, 759,
is for restricted development; see Section Four for details. Other estimates
for the annual cost of compliance are made for alternative assumptions for oil
price and development.
Model Well Characteristics: Model well characteristics were developed by
ITD relying on the Joint Association Survey on Drilling Costs. The model well
characteristics were used to estimate compliance costs and underlying
assumptions for the regulatory options. Separate model wells were developed
for each of the four geographic regions. Each model well has three segments:
6-1
-------
0 to 8,000 ft
8,000 to 10,000 ft: where 22 percent of the wells encounter a stuck
pipe problem
10,000 to 14,000 ft: only 30.8 percent of the wells go to depths
beyond 10,000 ft. An oil-based mud is assumed to be used in this
segment.
Table 6-1 summarizes the regional volumes of drilling fluids and drill
cuttings in the 0 to 10,000-ft interval. The volumes differ because the
average well depth differs by region.
\
Water-Based and Oil-Based Drilling Fluid Assumptions: The proposed
regulation and the alternative options presented here do not prohibit the use
of oil-based drilling fluids; they do prohibit the discharge of such fluids.
Water-based fluids are assumed I to be used for the 0 to 10,000-ft depth. For
wells that continue to 14,000 ft, an oil-based fluid is assumed to be used for
the 10,000 to 14,000-ft interval.) Spent oil-based fluid from this segment of
the drilling operations must be reused or barged to shore for disposal under
BPT regulations.
Lubricity Assumptions: Lubricity agents are assumed to be added only to
the water-based fluids used for the 0 to 10,000-ft well-depth interval. Wells
deeper than 10,000 ft are assumed-^to use an oil-based fluid and so require no
added oil for lubricity. No lubricity agent is needed between the 0 and
10,000-ft depth for 88 percent of/the wells. Of the 12 percent of the wells
that do use a lubricity agent, /it is assumed that 68 percent would have used
mineral oil while the remaining 32 percent would have used diesel. To comply
with the no-discharge-of-diesel requirement and to avoid barging, however, the
32 percent are now assumed to substitute mineral oil for diesel. This
assumption results in 88 percent of the wells using no lubricity agent, 8.16
percent using mineral oil without a change of plans, and 3.84 percent having
to change from diesel to mineral for lubricity purposes. (These assumptions
were developed by ITD, based on information in the 1984 Drilling Fluids Survey
by the American Petroleum^Institute (API)).
1
Stuck Pipe Assumptions: The/Offshore Operators' Committee (OOC) surveyed
2,287 wells drilled in the Wlf of Mexico from 1983 to 1986 (see FR 1988a) .
The study examined the number of wells drilled with water-based fluid each
year, the number of stuck pipe incidents, the spotting fluid used to free the
stuck pipe, and whether or not the "pill" or slug of the spotting fluid was
successful in freeing the pipe. Of the 2,287 wells surveyed, 506, or 22
6-2
-------
TABLE 6-1
REGIONAL VOLUMES OF DRILLING FLUIDS AND DRILL CUTTINGS
0 - 10,000 FT INTERVAL
volume of Effluent (bbl)
Region
Gulf
Pacific
Alaska
Atlantic
Fluids
6,932
6,047
6,385
9,476
Cuttings
1,471
1,265
1,345
2,577
Source: Environmental Protection Agency,
Industrial Technology Division.
6-3
-------
percent, had stuck pipe incidents. On this basis, the cost modeling efforts
assume 22 percent of all wells have stuck pipe incidents between 8,000 and
10,000 ft.
The OOC survey indicated that 298 of 506 (or 59 percent) stuck pipe
incidents were treated with a pill of diesel oil. The remaining 41 percent of
the stuck pipe incidents were treated with a mineral oil. These percentages
were used to estimate the number of wells for which a diesel pill would have
been used and which now must use mineral oil in order to avoid barging. As a
result, 9 percent of the wells would use a mineral oil pill, and 13 percent
that would have used a diesel oil pill, now choose to substitute a mineral oil
pill. All fluids with diesel oil pills would have to be barged due to the
toxicity of the remaining fluid. However, 44 percent of the fluids with
mineral oil pills can be discharged because they pass the toxicity and static
sheen tests. Thus, by substituting mineral for diesel pills, less barging is
required.
Toxicitv Test Failure Rates: The failure rate assumptions for the
toxicity test determine the amount of drilling fluids and cuttings that cannot
be discharged. Because operators are required to substitute mineral oil for
diesel oil, the mineral oil failure rates are used wherever oil is added to
the drilling fluid. Separate categories are maintained in the calculations,
however, to identify the amount of drilling fluids affected by the product
substitution requirement and the costs associated with the substitution of
mineral oil for diesel oil.
The data for the toxicity failure rates come from five sources. The first
two data sets are field fluid data collected by the American Petroleum
Institute and submitted to the Agency in August 1985 and October 1986. The
third data set includes the analytical results for field fluids collected
during the Diesel Pill Monitoring Program conducted by EPA, in cooperation
with API, from November 1985 through September 1987. The fourth data set is
field fluid information generated by industry and submitted to EPA Region VI
under the alternative toxicity request program. The fifth set of data is
discharge monitoring reports provided to EPA Region VI by industry under the
terms of the NPDES general permit for oil and gas operations in the Gulf of
Mexico. One percent of the water-based drilling fluids to which no oil has
been added for lubricity or spotting purposes is assumed to fail the toxicity
test. Thirty-three percent of the wells to which mineral oil has been added
as a lubricity agent are assumed to fail the toxicity test. Where oil has
been used as a spotting agent, 56 percent of the fluids are assumed to fail
6-4
-------
the toxicity test. Table 6-2 summarizes the toxicity test failure rates for
water-based drilling fluids.
Static Sheen Test Failure Rates: No water-based drilling fluid, even
those to which oil has been added for lubricity, spotting, or combined
purposes, is assumed to fail the static sheen test. All drill cuttings
associated with water-based fluids are assumed to pass the visual (BPT) and
the static sheen (BAT/NSPS) tests and may be discharged. The use of oil for
lubricity or spotting purposes does not cause the cuttings to fail the static
sheen test. Cuttings associated with oil-based fluids are assumed to fail the
visual sheen test even after washing. Costs associated with barging these
cuttings are BPT costs.
Zero Discharge of Drilling Effluents: Three of the regulatory options
considered include zero discharge of drilling fluids and drill cuttings. (The
zero discharge requirement is presumed to be met by barging the wastes to
shore for disposal.) First is the Zero Discharge option where all drilling
fluids and cuttings are barged to shore for treatment and disposal. The other
two options require barging of fluids and cuttings from wells drilled within 4
miles of the shore or less, and limits on toxicity, sheen, and metals content
of the fluids from operations beyond 4 miles. The two options are
distinguished by the limitations on the metals content of the barite or
discharged fluids. The percentage of wells projected to occur within 4 miles
differs by region. Table 4-27 shows these percentages.
Monitoring Requirements: Table 6-3 summarizes monitoring cost components
for both drilling fluids and drill cuttings. Fluids and cuttings that fall
under mandatory barging requirements are not monitored. No monitoring costs
are associated with drill cuttings or drilling fluids in the 10,000 to 14,000-
ft depth because of the use of an oil-based fluid and the proposed outright
prohibition on their discharge.
6.1.2 Current Permit Requirements
The current general permits for the Gulf of Mexico, Southern California,
and Alaska already contain requirements that are more stringent than BPT
guidelines. In some cases, the requirements exceed some of the options under
consideration. These requirements are summarized in Table 6-4 and are briefly
described below (FR 1985, FR 1986, and FR 1988b).
6-5
-------
o\
I
TABLE 6-2
TOXICITY AND STATIC SHEEN FAILURE RATES FOR WATER-BASED DRILLING FLUIDS - 0 TO 10,000 FEET
Well
Depth
and
Condition
Fluids - 0 to 8
Discharge
No Mineral
Percentage Lubricity Lubricity
of Drilling Needed Used
Fluids (88X) (8.16X)
,000 ft.
Fail Toxicity
Fail Static
Total, Fluids -
Fluids - 8,000
Sheen
0 to 8.000 ft. 100X
to 10,000 ft.
No stuck pipe 78X
Stuck pipe -
Stuck pipe -
Total, Fluids -
Discharge
Fail Toxicity
Fail Static Sheen
Mineral pill 9X
Discharge
Fail Toxicity
Fail Static Sheen
Diesel pill (Substitute Mineral pill) 13X
Discharge
Fail Toxicity
Fail Static Sheen
99X
1X
OX
99X
IX
OX
Diesel Lubricity
Used (3.84X)
(Substitute
Mineral
Lubricity)
67X
33X
OX
67X
33X
OX
67X
33X
OX
67X
33X
OX
44X 44X
56X 56X
OX OX
44X 44X
56X 56X
OX OX
8,000 to 10,000 ft. 100X
44X
56X
OX
44X
56X
OX
* Drilling fluids that fail either the toxicity or the static sheen test are assumed to be barged to shore for land disposal.
Source: Environmental Protection Agency, Industrial Technology Division.
-------
TABLE 6-3
OFFSHORE OIL AND GAS MONITORING COSTS FOR DRILLING FLUIDS AND DRILL CUTTINGS
Stream
Test
Cost per Sanple
Number of Samples*
Component Costs ($1986)
Static Diesel
Toxicity Mercury C acini urn Sheen Content
$1,000 $50 S50 $25 $75
222 10/20* 2 Well.
DRILLING FLUIDS
$2,000 $100 $100 $250 $150 $2,600
DRILL CUTTINGS
$500
$500
* Static sheen tests conducted daily on cuttings and every other day on drilling fluids,
assuming a twenty day drilling operation.
Source: Environmental Protection Agency, Industrial Technology Division.
6-7
-------
TABLE 6-4
SUMMARY OF CURRENT REQUIREMENTS FOR DRILLING FLUIDS
Requirement
No discharge of oil-based
fluids (BPT requirement)
Mandatory barging based
on distance from shore
Metals limitation
effluent
mercury (mg/kg)
cadmium (mg/kg)
No discharge of diesel oil
in detectable amounts
(Mineral oil substitution)
lubricity
pill
Toxicity limitation
limit
No discharge of "free oil"
static sheen test
Gulf of
Mexico
Yes
No
No
Yes
No**
Yes
30,000
ppra spp*
No
Region
Pacific
Yes
No
Yes
barite
1
2
Yes
No**
Yes
30,000
ppra spp*
Yes
Alaska
Yes
No
Yes
barite
1
3
Yes
Yes
No
Yes
* suspended particulate phase.
** Diesel pill plus a 50 bbl buffer of drilling fluid on either side of the pill
cannot be discharged; toxicity limit must be met by remaining fluid.
Source: FR, 1985; FR, 1986; and FR, 1988.
6-8
-------
No Discharge of Oil-Based Fluids: This is a BPT requirement and is
included in all regional permits.
Mandatory Barging Based on Distance from Shore: There are no current
requirements to barge fluids based on distance from shore.
Metals Limitation: The Gulf of Mexico permit has no requirement to limit
metals. Alaska and the Pacific place limitations on the metals in the barite,
while various proposed regulatory options limit the metals content either in
the barite or in the discharged drilling fluid and drill cuttings. Table 6-4
shows the metals limitations for each region. The limits for the Pacific and
Alaska are more stringent than the 5,3 option under consideration here.
No Discharge of Diesel Oil: All regions ban the discharge of fluids where
diesel oil has been used for lubricity. In the Gulf of Mexico and the
Pacific, the diesel oil pill and a minimum of 50 bbls of fluid on either side
of the pill must be withheld. The remainder of the fluid can be discharged if
it meets toxicity limitations. In Alaska, operators must withhold a mineral
oil pill plus a 50 bbl buffer on either side of the pill.
Toxicity Limits: Both the Gulf and Pacific require testing the fluid for
toxicity and have a 30,000 ppm spp limit. Alaska requires a bioassay test for
each mud system where mineral oil lubricity or a spotting agent is used, or,
if no mineral oil is used, one end-of-well bioassay test. The data appear to
be used to check the list of approved fluids and additives, not to determine
whether the fluid must be barged. (The approved list uses a toxicity limit of
30,000 ppm spp as its underlying basis.)
No Discharge of "Free Oil": Alaska and the Pacific require the static
sheen test while the Gulf requires the visual sheen test. The distinction is
moot because anything assumed to fail the static sheen test is considered
covered by the BPT level of control for the purpose of costing the current
analysis.
Monitoring Costs: Table 6-5 summarizes the incremental monitoring costs
borne by future drilling operations. Zero entries indicate that testing
already is required under current permit requirements. Note that no region
requires testing for oil content at this time.
6-9
-------
TABLE 6-5
SUMMARY OF INCREMENTAL MONITORING COSTS FROM CURRENT DRILLING FLUIDS BASELINE
Monitoring
Requirement
Region
Gulf Pacific Alaska Atlantic
Drilling Fluids
Mercury
Cadmium
Toxicity
Static Sheen
No diesel in detectable amounts
Total Drilling Fluids Monitoring Cost
Drill Cuttings
Static Sheen Test
$100
$100
so
$250
S150
S600
to
$0
SO
SO
$150
$150
$0
$0
$2,000
$0
$150
$2,150
$100
$100
$2,000
$250
$150
$2,600
$500
$0
$0
$500
Note: Zero entries denote that the monitoring requirement already exists
in current permits.
6-10
-------
6.1 J Cost of Regulatory Options
The cost of a regulatory option for drilling fluids and drill cuttings
depends on the average annual number of projected wells. That average will
vary depending upon the price of oil and whether economically feasible
development is restricted by environmental considerations. Section Four
discusses these factors and presents four sets of projections.
The costs presented in Tables 6-6 through 6-9 are for the $21/bbl
unrestricted scenario. These tables summarize the cost for each regulatory
option by region. Although diesel pills may be used as long as (1) the pill
and a 100-barrel minimum buffer are barged, and (2) the remaining fluid passes
the toxicity test, ERG models the Gulf and Pacific as substituting mineral oil
for diesel oil in pills because it is a lower cost option on the average
(Kaplan, 1989a).
Table 6-6 presents the costs for the Gulf of Mexico with the costs for the
5.3 All option given in the middle column. The use of 5,3 barite is
considered a no-cost option. (There are adequate supplies of barite meeting
these metals limitations, so no price increase would be incurred; see Kaplan
and Meyers, 1987). Although the current permit for the Gulf does not specify
metals limitations in the barite or discharged drilling fluid, no cost is
associated with the use of 5,3 barite. The current permit already requires
the substitution of mineral oil for diesel and toxicity testing, so these
items accrue no costs. No fluids or cuttings are assumed to fail the static
sheen test, so no costs are incurred by this requirement either. The only
costs incurred by moving to the 5,3 option in the Gulf are the increased
monitoring costs for fluids and cuttings. These costs are $600 and $500,
respectively, (see Table 6-5) for an average cost of $1,100 per well.
1.1 All: Compliance with the 1,1 All option assumes the use of "clean"
barite for all wells. In the Gulf, "clean" barite incurs a 15 percent price
increase. This item is listed in the "Clean barite" line. Like the 5,3 All
option, this option incurs additional monitoring costs.
Options Involving Mandatory Barging. Including those Based on Distance to
Shore: The costs listed in the "zero discharge" rows are the costs associated
with barging all fluids and cuttings from all wells (in the Zero Discharge
option) or from wells within 4 miles from shore (in the 4-Mile Barge options).
Because these fluids will be barged a priori, there is no need to substitute
mineral oil for diesel, to test for toxicity, or to barge the fluids that fail
6-11
-------
TABLE 6-6
en
I
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
GULF OF MEXICO
UNRESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil substituti tion
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
Discharge
$158,193
$0
($1,259)
($15.506)
$0
$176,388
($1.430)
$53,666
$0
$0
$53,666
$0
$211,859
$296
1.1 All
$8.108
$7.679
$0
$0
$0
$0
$429
$358
$0
$0
$0
$358
$8,466
$12
5,3 All
$429
$0
$0
$0
$0
$0
$429
$358
$0
$0
$0
$358
$787
$1.1
4 -MILE BARGE,
1,1 OTHER
$23,812
$7,007
($126)
($1.551)
$0
$18.239
$243
$5,688
$0
$0
$5,367
$322
$29,500
$41
4-MILE BARGE,
5.3 OTHER
$16,805
$0
($126)
($1.551)
$0
$18,239
$243
$5,688
$0
$0
$5,367
$322
$22,493
$31
Source: Industrial Technology Division, Environmental Protection Agency.
H&C$-UNR.UK3
19-NOV-90
-------
(ft
I
TABLE 6-7
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
PACIFIC
UNRESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil subs ti tut it ion
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
Discharge
$44.873
($1.697)
($397)
($4.005)
$0
$51.553
($581)
$15,180
$0
$0
$15.298
($119)
$60.053
$253
1,1 All
$885
$849
$0
$0
$0
$0
$36
$0
$0
$0
$0
$0
$885
$4
5.3 All*
$36
$0
$0
$0
$0
$0
$36
$0
$0
$0
$0
$0
$36
$0
4-MILE BARGE.
1,1 OTHER
$14,709
$172
($119)
($1,202)
$0
$15,857
($149)
$4,554
$0
SO
$4,589
($36)
$19,262
$81
4 -MILE BARGE,
5,3 OTHER*
$14.536
$0
($119)
($1.202)
$0
$15.857
($149)
$4,554
$0
$0
$4,589
($36)
$19,090
$81
* Current permit requires the use of 1,2 barite. This requirement cannot be relaxed when considering regulatory options.
Source: Industrial Technology Division, Environmental Protection Agency.
M&C$-UNR.UK3 19-NOV-90
-------
0\
TABLE 6-8
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
ALASKA
UNRESTRICTED ACTIVITY
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil subs ti tut it ion
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
D i scharge
$2,677
($43)
($20)
$0
$0
$2,745
($5)
$1,229
$0
$0
$1,235
($6)
$3,906
$325
REGULATORY (
1,1 All
$334
$86
$0
$222
$0
$0
$26
$0
$0
$0
$0
$0
$334
$28
)PTIONS
5.3 All
$248
$0
$0
$222
$0
$0
$26
$0
$0
$0
$0
$0
$248
$21
* Current permit requires the use of 1,3 barite. This requirement cannot be
relaxed when considering regulatory options.
NOTE: Alaska is exempted from the 4-mile Barge requirement. Restrictions on the metals content
of the barite and other components of the 1,1 Alt and the 5,3 All options remain in place.
Source: Industrial Technology Division, Environmental Protect ion Agency.
-------
TABLE 6-9
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
ATLANTIC
UNRESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil substituti tion
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
Discharge
$5,298
$0
$0
$0
SO
J5.298
SO
$2,104
SO
SO
$2,104
SO
$7,402
$463
1,1 All
$835
$172
$32
$589
$0
$0
$42
$9
SO
$0
$0
$9
$844
$53
5,3 All
$663
$0
$32
$589
$0
$0
$42
$9
$0
SO
$0
$9
$672
$42
4-MILE BARGE,
1,1 OTHER
$835
$172
$32
$589
$0
$0
$42
$9
$0
$0
$0
$9
$844
$53
4-MILE BARGE,
5,3 OTHER
$663
$0
$32
$589
$0
$0
$42
$9
SO
$0
$0
$9
$672
$42
Source: Industrial Technology Division, Environmental Protection Agency.
M&C$-UNR.UK3 .
19-NOV-90
-------
toxicity. Hence there are negative entries for mineral oil substitution,
toxicity test failure, and monitoring costs. The operators would no longer
incur these costs, which would be incurred under current permit conditions.
For the same reason, a lower cost for clean barite is seen in the 4-Mile
Barge; 1,1 Other option than in the 1,1 All option because only wells beyond U
miles would have to use clean barite.
The costs for the Pacific are given in Table 6-7. In this region, current
permit conditions require the use of barite with 1 mg/kg mercury and 2 mg/kg
cadmium. This requirement cannot be relaxed. An additional 5 percent
increase is associated with moving to the cleaner barite (Kaplan, 1989b).
Table 6-8 summarizes the cost for Alaska. For Alaska, cadmium and mercury
in the barite are limited to 3 mg/kg and 1 mg/kg, respectively. Changing to
clean barite to meet the 1,1 All option incurs an additional 10 percent cost
increase (Kaplan, 1989b). Current practices include the costs for mineral oil
substitution. Monitoring costs include testing for oil content and toxicity.
Note that no costs are listed in the Alaska region for either of the 4-Mile
Barge options. Due to the dangers, high costs, and uncertainties of barging
in arctic conditions, Alaska has been exempted from any zero discharge
requirement under these options. Instead, wells in this region must comply
with the 1,1 All or 5,3 All requirements under the 4-Mile Barge; 1,1 Other and
the 4-Mile Barge; 5,3 Other options, respectively.
There are no permits with more stringent requirements than BPT for the
Atlantic. Table 6-9 presents the costs for the regulatory options for this
region. Since no wells are assumed to occur within 4 miles from shore, there
is no difference between the respective 4-Mile Barge and the 1,1 All or 5,3
All options.
Annual Total and Per-Well Costs: The total annual cost and regional per-
well costs are summarized in Table 6-10. The per-well costs are weighted
averages for all wells; i.e., the costs reflect the percentage of wells that
barge and the percentage that do not barge. These values are used in the
economic impact analysis (see Sections Seven through Ten). The total annual
costs range from $2 million (1986 dollars) for the 5,3 All option to $283
million (1986 dollars) for the Zero Discharge option.
Tables 6-11 through 6-14 present the annual regulatory costs by region
under the $21/bbl restricted development scenario. Note that the costs in the
Gulf and Alaska regions do not change under this assumption. There are no
costs in the Atlantic region, since no activity is projected to occur there.
6-16
-------
TABLE 6-10
CTl
I
SUMMARY TABLE OF REGULATORY COSTS OF ALTERNATIVE POLLUTION CONTROL OPTIONS
NSPS DRILLING FLUIDS AND DRILL CUTTINGS
ANNUAL REGULATORY COST ($000 1986 DOLLARS)
UNRESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
TOTAL COST
PER WELL COST
Gulf of Mexico
Pac i f i c
Alaska
Atlantic
Zero
Discharge
$283,219
$296
$253
$325
$463
1.1 All
$10.527
$12
$4
$28
$53
5,3 All
$1,741
$1
$0
$21
$42
4-MILE BARGE,
1,1 OTHER*
$49,940
$41
$81
$28
$53
4-MILE BARGE.
5,3 OTHER**
$42.503
$31
$81
$21
$42
* Except for Alaska which is 1,1 All.
** Except for Alaska which is 5,3 All.
Source: ERG estimates.
N&C$-UNR.WK3
06-Feb-91
-------
TABLE 6-11
>-
00
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1966 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
GULF OF MEXICO
RESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil subs ti tut it ion
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
Discharge
$158,193
SO
($1.259)
($15,506)
$0
$176.388
($1.430)
$53,666
$0
$0
$53,666
$0
$211,859
$296
1,1 All
$8,108
$7,679
$0
$0
$0
$0
$429
$358
$0
$0
$0
$358
$8,466
$12
5,3 All
$429
$0
$0
$0
$0
$0
$429
$358
$0
$0
$0
$358
$787
$1.1
4-MILE BARGE,
1,1 OTHER
$23,812
$7,007
($126)
($1.551)
$0
$18,239
$243
$5.688
$0
$0 -
$5,367
$322
$29,500
$41
4-HILE BARGE,
5,3 OTHER
$16,805
$0
($126)
($1,551)
$0
$18,239
$243
$5,688
SO
SO
$5.367
$322
$22.493
$31
Source: Industrial Technology Division, Environmental Protection Agency.
M&CS-RES.UK3
19-NOV-90
-------
cr>
I
TABLE 6-12
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
PACIFIC
RESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil substitutition
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
' Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
Discharge
$6.059
($229)
($54)
($541)
$0
$6,961
($78)
$2,049
$0
$0
$2,065
($16)
$8,108
$253
1,1 All
$120
$115
SO
$0
$0
$0
$5
$0
$0
$0
so
$0
$120
$4
5,3 All*
$5
$0
SO
so
$0
so
$5
$0
so
so
so
so
$5
SO
4-MILE BARGE,
1,1 OTHER
$120
$115
$0
$0
$0
SO
$5
SO
SO
$0
so
so
SI 20
$4
4-MILE BARGE,
5,3 OTHER*
$5
SO
SO
$0
$0
$0
$5
$0
SO
so
so
$0
S5
SO
* Current permit requires the use of 1,2 barite. This requirement cannot be relaxed when considering regulatory options.
Source: Industrial Technology Division, Environmental Protection Agency.
M8CS-RES.UK3 19-NOV-90
-------
o\
I
to
TABLE 6-13
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS ($000 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
ALASKA
RESTRICTED ACTIVITY
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil substitutition
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
REGl
Zero
Discharge
$2.677
($43)
(S20)
(0
SO
$2,745
($5)
$1,229
$0
SO
$1,235
($6)
$3,906
$325
ILATORY OPTIONS
1,1 All
$334
$86
$0
$222
$0
$0
$26
$0
$0
$0
$0
$0
$334
S28
5.3 All*
$248
$0
$0
$222
$0
$0
$26
$0
$0
SO
SO
so
$248
$21
* Current permit requires the use of 1,3 barite. This requirement cannot be relaxed
when considering regulatory options.
NOTE: Alaska is exempted from the 4-mile barge requirement. Restrictions on the metals content
of the barite and other components of the 1,1 All and the 5,3 All options remain in place
Source: Industrial Technology Division, Environmental Protection Agency.
-------
TABLE 6-14
ANNUAL REGULATORY COST OF ALTERNATIVE POLLUTION CONTROL OPTIONS (SOOO 1986 DOLLARS)
DRILLING FLUIDS AND DRILL CUTTINGS
ATLANTIC
RESTRICTED ACTIVITY
I
K>
REGULATORY OPTIONS
Parameter
DRILLING FLUID COSTS
Clean barite
Mineral oil substitution
for diesel oil
Toxicity test failure
Static sheen test failure
Zero discharge
Monitoring costs
DRILL CUTTINGS COSTS
Static sheen test failure
No association with oil-based fluids
Zero discharge
Monitoring costs
TOTAL ANNUAL COSTS
ANNUAL COST PER WELL
Zero
Discharge
(0
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
1.1 All
SO
SO
SO
SO
SO
SO
so
so
so
so
so
so
so
so
5,3 All
SO
$0
SO
so
so
so
so
so
so
so
$0
so
$0
$0
4-MILE BARGE,
1,1 OTHER
SO
SO
$0
$0
SO
SO
SO
SO
SO
SO
SO
so
$0
so
4-MILE BARGE,
5,3 OTHER
SO
SO
SO
SO
$0
SO
SO
SO
SO
SO
SO
SO
so
so
Source: Industrial Technology Division, Environmental Protection Agency.
MSCS-RES.WK3
19-NOV-90
-------
Costs in the Pacific region decline due to the reduced amount of activity
projected. The total annual costs and regional per-well costs under the
restricted activity scenario are summarized in Table 6-15. Total annual costs
range from $1 million (1986 dollars) for the 5,3 All option to $224 million
(1986 dollars) for the Zero Discharge option.
As described in Section Four, four alternative scenarios have been
analyzed to account for po'ssible variations in regulatory costs due to oil
price changes and different levels of development. Table 6-16 summarizes the
total annual costs under each of the four alternative scenarios. The per-well
costs do not change, revert to the costs for another option, or go to zero
depending upon assumptions for future development. For example, under the
restricted development variations, there are no wells within 4 miles of shore
in the Pacific; thus, the per-well costs revert to the 1,1 All or 5,3 All per-
well costs. The cost for the 4-Mile Barge; 1,1 Other option ranges from $26
million to $60 million (1986 dollars) depending on the assumptions for the
price of oil and the level of development.
6.2 PRODUCED WATER - BAT
Section One presents the regulatory options for increased pollution
controls on produced water from existing projects. There are two basic
methods:
Filtration and discharge
Injection
The options under consideration are combinations of one or both disposal
methods depending upon the location of the platform (within 4 miles or beyond
4 miles from shore).
Two sets of capital and operation and maintenance (O&M) costs were
developed for filtration and reinjection. The final set of costs, based upon
membrane filtration technology, assumes that no platform addition is necessary
and uses a multiplier of 1.5 to cover the costs of transportation to the
offshore location and other considerations.
The second set of costs, based upon granular filtration technology,
reflects two important cost assumptions:
6-22
-------
TABLE 6-15
SUMMARY TABLE OF REGULATORY COSTS OF ALTERNATIVE POLLUTION CONTROL OPTIONS
NSPS DRILLING FLUIDS AND DRILL CUTTINGS
ANNUAL REGULATORY COST ($000 1986 DOLLARS)
RESTRICTED ACTIVITY
REGULATORY OPTIONS
Parameter
Zero
Discharge
1,1 Alt
5,3 All
4-MILE BARGE,
1.1 OTHER*
4-MILE BARGE,
5,3 OTHER**
TOTAL COST
$223,872
$8,919
$1.039
$29.954
$22,746
I
M
U>
PER WELL COST
Gulf of Mexico
Pacific
Alaska
Atlantic
$296
$253
$325
$0
$12
$4
$28
$0
$1
$0
$21
$0
$41
$4
$28
$0
$31
$0
$21
$0
* Except for Alaska which is 1,1 All.
** Except for Alaska which is 5,3 All.
Source: ERG estimates.
M&C$-RES.UK3
19-Nov-90
-------
TABLE 6-16
ANNUAL COST OF POLLUTION CONTROL OPTIONS
NSPS DRILL FLUIDS AND DRILL CUTTINGS
MILLIONS OF DOLLARS, 1986 DOLLARS
Regulatory Options
Scenario
$21/bbl -
$21/bbl -
S32/bbl -
$15/bbl -
Unrestricted
Restricted
Unrestricted
Restricted
Zero
Discharge
$283
$224
$344
$197
1,1 All
S11
S9
S14
$8
5,3 All
$2
$1
$4
$1
4-Mile Barge;
1,1 Other
$50
$30
$60
$26
4-Mile Barge;
5,3 Other
$43
$23
$51
$20
Source: ERG estimates.
6-24
-------
Platform additions are required to accommodate the extra equipment.
Platform additions can be two-thirds the entire capital cost for some
projects.
A multiplier of 3.5 is used to address the costs of getting the
material to its offshore location, etc.
The costing assumptions, capital costs, and O&M costs were developed by
EPA Industrial Technology Division, and are discussed in more detail in the
Development Document.
The injection option is subdivided into onshore and offshore injection.
Under the granular filter costs, it may be less expensive to drill a disposal
well onshore and pipe the produced water to shore for disposal. ERG assumes
37 percent of the platforms within 4 miles use onshore injection based on
information in WHA, 1984. For the membrane filter costs, the offshore
injection option is less expensive for most Gulf model projects than piping
the fluids to shore for treatment and disposal. No onshore injection is
considered with the membrane filter cost estimates.
Only projects in the Gulf of Mexico and the Pacific need to be considered
in the BAT analysis. The only offshore field presently in production in
Alaska is the Endicott field in the Beaufort Sea. This project must already
inject produced water due to State requirements. There is no current
production from projects in the Atlantic. Both the Gulf of Mexico and the
Pacific have oil-with-gas and gas-only projects. The Gulf of Mexico also has
a small number of oil-only projects. Table 6-17 summarizes the BAT projects
by region, size, and type of production; details on the platform count are
given in Appendix H. Table 6-18 summarizes the regional capital and annual
O&M costs for the BAT projects.
The model-specific capital and O&M costs are entered into the BAT economic
models to calculate the annualized cost of the regulation. The annualized
costs are calculated over the remaining lifetime of the project and address
the situation where the project shuts down early due to an increase in the
annual O&M costs. Tables 6-19 through 6-22 list the capital, O&M, and
annualized cost for each project and regulatory option.
Total annualized costs are obtained by multiplying the appropriate number
of structures by the cost of each disposal option and summing over all
entries. Table 6-23 lists the total annualized cost by disposal option for
the granular filter and membrane filter costs. For the granular filter
scenario, the costs range from $41 million (1986 dollars) for the projects
6-25
-------
TABLE 6-17
EXISTING STRUCTURES BY REGION
07-Feb-91
NUMBER OF STRUCTURES
Structure Oil Only
Type <= 4 mi les
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Gulf Totals
Pacific 16
Pacific 40
Pacific 70
Pacific Totals
Atlantic
Alaska
Totals
26
1
23
0
0
0
0
0
50
0
0
0
0
Oil Only Oil and Gas Oil and Gas Gas Only Gas Only Total
> 4 miles <= 4 miles > 4 miles <= 4 miles > 4 miles <= 4 mi les >
38
9
18
18
22
5
1
0
111
0
0
0
0
No existing
27
13
10
2
3
8
0
0
63
7
0
4
11
facilities
No facilities that do not
50
111
74
193
82
101
124
215
188
2
0
905
1
6
8
15
already re-inject
920
53
22
8
1
0
0
0
0
84 1
0
0
0
0
produced
84 1
337
228
156
156
104
39
0
0
,020
1
0
0
1
water
.021
106
36
41
3
3
8
0
0
197
7
0
4
11
208
Total
4 mi les
568
319
275
298
341
232
3
0
2,036
2
6
8
16
2,052
Total
674
355
316
301
344
240
3
0
2,233
9
6
12
27
2,260
Note: Structures in the Gulf of Mexico have been classified according to the number of producing wells.
Structures in the Pacific have been classified according to the number of wellslots.
Source: MMS, 1988; CCC, 1988; SAS printout kre_bat6.out; SAS runs dated July 1990.
6-26
-------
TABLE 6-18
BAT PRODUCED WATER
TOTAL CAPITAL AND ANNUAL O&M COSTS BY REGION
SMILLIONS, 1986 DOLLARS
Technology
Cost
Membrane
Filter
Effluent
Control
Opt i on
Zero Discharge
All Filter
4-Mile Filter;
BPT Other
Region
Gulf
Pacific
Total
Gulf
Pacific
Total
Gulf
Pacific
Total
Capital
Costs
$2,224.6
$133.7
$2,358.3
$393.1
$31.0
$424.1
$23.9
$11.4
$35.3
Annual
O&M
Costs
$151.5
$9.2
$160.7
$97.9
$6.4
$104.3
$6.1
$2.2
$8.4
Granular
Filter Zero Discharge
All Filter
4-Mile Filter;
BPT Other
Gulf
Pacific
Total
Gulf
Pacific
Total
Gulf
Pacific
Total
$4,461.4
$330.1
$4,791.5
$2,235.6
$179.1
$2,414.7
$116.7
$70.1
$186.8
$198.6
$12. 0
$210.6
$136.5
$8.7
$145.3
$8.0
$3.2
$11.2
Source: Environmental Protection Agency, Industrial Technology Division.
6-27
-------
TABLE 6-19
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
OIL AND GAS PLATFORMS
GULF OF MEXICO
Project
Scenario
Pollution Control Costs
($000, 1986 Dollars)
Capital
O&M
Annualized
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
$672
$286
$460
$385
$64
$2,019
$579
$1,710
$1,426
$170
$2,783
$1,237
$1,846
$1,546
$262
$3,361
$1,792
$1,890
$1,589
$298
$3,471
$2,812
$1,970
$715
$365
$4,312
$3,185
$2,610
$1,079
$426
$5,035
$3,393
$1,471
$502
$6,071
$3,647
$2,130
$596
$29
$18
$17
$24
$14
$99
$57
$67
$83
$45
$124
$78
$71
$98
$59
$143
$96
$74
$106
*67
$143
$124
$78
$90
$80
$222
$194
$80
$131
$113
$292
$248
$192
$165
$378
$314
$271
$227
$144
$61
$89
$88
$22
$441
$141
$331
$299
$66
$518 -
$250
$334
$312
$87
$587
$330
$324
$310
$99
$636
$523
$339
$183
$122
$787
$607
$408
$254
$154
$907
$656
$349
$206
$1,077
$724
$499
$273
Notes: There are no Gulf 40 or Gulf 58 projects within 4-miles from shore at present.
G refers to granular filtration costs for injection and filtration.
M refers to membrane filtration costs for injection and filtration.
Source: ERG estimates.
6-28
-------
TABLE 6-20
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
OIL AND GAS PLATFORMS
PACIFIC
Project
Scenario
Pollution Control Costs
($000, 1986 Dollars)
Capital
O&M
AnnuaIi zed
Pacific 16
Pacific 40
Pacific 70
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
N-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
H-Filtration
$7,700
$5,255
$4,248
$2,258
$738
$10,701
$5,979
$4.183
$1.007
$16,849
$8,322
$7,991
$7,484
$1,553
$257
$206
$78
$164
$125
$405
$301
$299
$214
$620
$434
$180
$500
$341
$1,983
$1,377
$1,045
$650
$267
$2,467
$1,438
$1,077
$373
$3,507
$1,837
$1,569
$1,742
$557
Notes: G refers to granular filtration costs for injection and filtration.
M refers to membrane filtration costs for injection and filtration.
Source: ERG estimates.
6-29
-------
TABLE 6-21
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED UATER
GAS PLATFORMS
GULF OF MEXICO AND PACIFIC REGIONS
Project
Scenario
Pollution Control Costs
(SOOO, 1986 Dollars)
Capital
CAM
Annualized
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
'
Pacific 16
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
S544
$132
$419
$408
$37
$1,672
$174
$667
$1,494
$48
$2,175
$529
$1,675
$1 ,634
$149
$2,231
$563
$1,699
$1 ,654
$164
$1,155
$632
$1,593
$507
$193
$1,423
$844
$1,660
$565
$236
$2,100
$1,319
$758
$375
$21
$10
$12
$20
$9
$78
$34
$39
$77
$34
S83
$39
$45
$79
S36
$86
$41
$48
$80
$37
$61
$49
$59
$49
$41
$69
$56
$66
$53
$44
$71
$57
$54
$45
$105
$30
$77
$83
$14
$334
$55
$132
$305
$36
$393
$106
$270
$294
$51
$382
$113
$276
$298
$55
$212
$130
$270
$112
$62
S245
$158
$273
$120
$69
$432
$281
$179
$104
Notes: There are no Gulf 40, Gulf 58, or Pacific 16 gas-only projects within
4 miles from shore at present.
G refers to granular filtration costs for injection and filtration.
M refers to membrane filtration costs for injection and filtration.
Source: ERG estimates.
6-30
-------
TABLE 6-22
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
OIL ONLY PLATFORMS
GULF OF MEXICO
Pollution Control Costs
($000, 1986 Dollars)
Project
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24.
Gulf 40
Gulf 58
Scenario
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
N-Filtretion
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Capital
$664
$278
$459
$384
$63
$2,016
$577
$1,708
$1,425
$170
$2,769
$1,223
$1,845
$1,545
$261
$3,340
$1.772
$1,888
$1,587
$297
$3,421
$2,764
$1,967
$712
$362
$4,302
$3,181
$2,596
$1,076
$425
$5,026
$3,389
$1,468
$500
$5,819
$3,642
$1,886
$594
OSM
$29
$18
$17
$24
$14
$99
$57
$67
$83
$45
$123
$77
$71
$97
$59
$141
$95
$73
$105
$67
$140
$121
$78
$88
$78
$220
$192
$80
$129
$111
$292
$248
$192
$165
$365
$309
$259
$223
Annual! zed
S142
$64
$96
$88
$23
$440
$141
$359
$321
S65
$515
$247
$334
$312
$89
$615
$326
$324
$310
$98
$626
$513
$358
$181
$120
$783
$604
$427
$260
$155
$906
$656
$358
$208
$1,073
$719
$459
$268
Notes: There are no Gulf 40 or Gulf 58 projects within 4-niles from shore at present.
G refers to granular filtration costs for injection and filtration.
M refers to membrane filtration costs for injection and filtration.
Source: ERG estimates.
6-31
-------
TABLE 6-23
ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT PRODUCED WATERS
MILLIONS OF DOLLARS, 1986 DOLLARS
Annualized Regulatory Cost
Granular Membrane
Option Filtration Filtration
Zero Discharge $845 $491
All Filter $480 $151
4-Mile Filter; BPT Other . $41 $13
Source: ERG estimates.
6-32
-------
within 4 miles of shore which must filter and discharge produced water, to
$845 million (1986 dollars) for all projects which must inject their produced
water. For the membrane filter scenario, costs range from $13 to $491 million
1986 dollars for the same disposal options.
63 PRODUCED WATER - NSPS
The filtration/discharge and injection of produced water are also options
for future projects that would fall under the New Source Performance
Standards. Section Four describes the methodology used to estimate the number
and type of new sources.
The capital, O&M costs, and the annualized costs are shown by project in
Tables 6-24 through 6-27. Table 6-28 summarizes the total capital and annual
O&M costs by region. The cost for each option is assumed to be the annualized
cost in 2000, the last year in the time frame for the analysis. Annualized
costs are cumulative over the 1986-2000 time period. The cost for the first
year is calculated as follows:
Multiply the annualized cost for a project by the number of such
projects going into operation that year, and
Sum the products over all projects.
For year two, the annualized cost is the cost associated with projects going
into operation that year plus the annualized cost for the preceding year.
Note that these costs apply on a per-project basis, and, therefore, do not
vary between the restricted and unrestricted scenarios. The difference in
total costs reflects the varying number of projects under each of the four
scenarios.
Tables 6-29 and 6-30 present the annualized costs for NSPS projects under
the $21/bbl unrestricted development scenario. Table 6-29 represents the
costs assuming the use of granular filtration technology. The costs range
from $27 million (1986 dollars) for projects within 4 miles of shore that must
filter and discharge their produced water to $275 million (1986 dollars) for
all projects that must inject their produced water. Similarly, Table 6-30
summarizes the annualized costs assuming the use of membrane filter
technology. For comparison, the costs drop to $17 million and $202 million
for the above-mentioned options.
6-33
-------
TABLE 6-24
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
OIL AND GAS PLATFORMS
GULF OF MEXICO
Project
Scenario
Pollution Control Costs
($000, 1986 Dollars)
Capital
O&M
Annual)zed
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Fi Itration
$1,928
$1,711
$485
$1 ,462
$205
$2,227
$1,848
$707
$1,571
$299
$2,339
$1,892
$805
$1,615
$341
$1,598
$1,976
$990
$746
$419
$2,225
$2,632
$1,131
$1,112
$474
$2,935
$3,176
$1,335
$1,510
$560
$3,960
$1,587
$2,177
$666
$97
$85
$55
$84
$47
$118
$94
$72
$99
$61
$128
$94
$81
$108
$69
$115
$94
$97
$93
$83
$163
$103
$136
$136
$118
S235
$125
$192
$199
$171
$324
$260
$280
$237
$278
$245
$96
$220
$62
$313
$256
$130
$235
S83
$328
$257
$147
$245
$94
$242
$260
$171
$145
$107
$334
$320
$213
$212
$140
$450
$380
$276
$297
$191
$606
$352
$419
$255
Notes: No 58-well structures are projected for the shallow waters of the
Gulf of Mexico.
G refers to granular filtrations costs for injection and filtration.
M refers to membrane filtrations costs for injection and filtration.
Source: ERG estimates.
6-34
-------
TABLE 6-25
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
OIL AND GAS PLATFORMS
ATLANTIC AND PACIFIC
Project
Scenario
Pollution Control Costs
($000, 1986 Dollars)
Capital
O&M
Annual)zed
Atlantic 24
Pacific 16
Pacific 40
Pacific 70
C-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
H-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
$6,297
$2,303
$3,780
$966
$4,365
$1,973
$2,320
$826
$7,376
$2,707
$4,283
$1.137
$12,668
$3,782
$7,658
$1,592
$316
$221
$277
$199
$203
$152
$172
$133
$359
$255
$317
$232
$585
$398
$527
$368
$824
$388
S567
$251
$718
$370
$430
$207
$1,181
$527
$768
$316
$1,881
$736
$1,273
$468
Notes: G refers to granular filtrations costs for injection and filtration.
M refers to membrane filtrations costs for injection and filtration.
Source: ERG estimates.
6-35
-------
TABLE 6-26
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
OIL AND GAS PLATFORMS AND OIL-ONLY PLATFORMS*
ALASKA
PROJECT
SCENARIO
Pollution Control Costs
($000, 1986 Dollars)
Capital
O&M
Annualized
Cook Inlet
Beaufort
Gravel Is.
Beaufort
Platform
Navarin
Norton
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
$13,462
$3,907
$8,848
$1,643
$36,655
$10,497
$20,948
$6,426
$36,300
$10,389
$20,823
$4,380
$36,656
$10,497
$20,948
$4,426
$22,514
$8,193
$11,725
$3,449
S596
$369
$541
$341
$655
$653
$623
$610
$646
$630
$615
$588
$655
$653
$623
$610
$681
$460
$617
$428
$1,593
$628
$1,173
$421
$3,347
$1,320
$2,106
$816
$3,351
$1,303
$2,111
$799
$3,347
$1,320
$2,106
$816
$2,322
$1,008
$1,411
$605
Notes: Cook Inlet project produces both oil and gas; all other projects are
assumed to produce only oil.
G refers to granular filtrations costs for injection and filtration.
M refers to membrane filtrations costs for injection and filtration.
Source: ERG estimates.
6-36
-------
TABLE 6-27
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
GAS-ONLY PLATFORMS
Project
Scenario
Pollution Control Costs
($000, 1986 Dollars)
Capital
O&M
Annualized
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific 16
Atlantic 24
Cook Inlet
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
H-Filtration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
$1,644
S667
$146
$1,508
$62
$2,089
$1,675
$443
$1,672
$188
$2,139
$1,699
$471
$1,690
$199
$1,051
$1,748
$527
$537
S223
$1,195
$1,815
$635
$588
$269
$1,762
$1,011
$795
$428
$2,013
$1,232
$893
$521
$2,456
$1,540
$1,056
$652
$77
$41
$34
$77
$34
$82
$49
S38
$79
$36
$85
$54
$40
$81
$37
$57
$68
$46
$49
$41
$66
$83
$53
$54
$45
$67
$54
$55
$46
$74
$59
$59
$50
$54
$44
$48
$39
$228
$100
$45
$215
$36
$268
$199
$75
$226
$50
$272
$204
$79
$227
$52
$144
$217
$86
$90
$54
$151
$217
$94
$91
$57
$244
$152
$129
$83
$52
$41
$42
$35
$246
$162
$126
$86
Note: G refers to granular filtration costs for filtration and injection.
M refers to membrane filtration costs for filtration and injection.
Source: ERG estimates.
6-37
-------
TABLE 6-28
NSPS PRODUCED WATER
TOTAL CAPITAL AND ANNUAL O&M COSTS BY REGION
^MILLIONS, 1986 DOLLARS
Technology
Cost
Membrane
Filter
Granular
Filter
C4 ^ 1 1 lAn^
cTT luent
Control
Option Region
Zero Discharge Gulf
Pacific
Alaska
Atlantic
Total
All Filter Gulf
Pacific
Alaska
Atlantic
Total
4-Mile Filter; Gulf
BPT Other Pacific
Alaska
Atlantic
Total
Zero Discharge Gulf
Pacific
Alaska
Atlantic
Total
All Filter Gulf
Pacific
Alaska
Atlantic
Total
4-Mile Filter; Gulf
BPT Other Pacific
Alaska
Atlantic
Total
Restricted
Capital
Costs
$957.8
S43.5
S51.8
$0.0
$1,053.0
$204.8
$9.8
$11.1
$0.0
$225.7
$32.2
$0.0
$8.9
$0.0
$41.1
$1,416.0
$72.8
$89.2
$0.0
$1,578.0
$485.0
$23.2
$26.4
$0.0
$534.7
$76.2
$0.0
$21.0
$0.0
$97.2
Activity
Annual
O&M Costs
$66.3
$3.1
$1.8
$0.0
$71.2
$44.3
$2.2
$1.6
$0.0
$48.0
$6.8
$0.0
$1.2
$0.0
S8.1
$75.6
$3.4
$2.0
$0.0
$81.0
$50.0
$2.4
$1.7
$0.0
$54.0
$7.7
SO.O
$1.3
$0.0
$9.0
Unrestricted
Capital
Costs C«
$957.8
$274.9
$51.8
$15.8
$1,300.3
$204.8
$79.4
$11.1
$5.5
$300.9
$32.2
$22.7
$8.9
SO.O
$63.8
$1,416.0
$485.0
$89.2
$29.0
$2,019.2
$485.0
$189.0
$26.4
$13.1
$713.6
$76.2
$54.1
$21.0
$0.0
$151.3
Activity
Annual
W Costs
$66.3
$20.3
$1.8
$1.1
$89.5
$44.3
$15.0
$1.6
$0.8
$61.7
$6.8
$4.6
$1.2
$0.0
$12.7
$75.6
S23.2
$2.0
$1.3
$102.0
$50.0
$16.6
$1.7
$1.0
$69.3
$7.7
$5.1
$1.3
$0.0
$14.1
Source: Environmental Protection Agency, Industrial Technology Division.
6-38
-------
TABLE 6-29
ANNUAL I ZED COSTS OF NSPS PRODUCED WATER CONTROL OPTIONS
GRANULAR FILTER TECHNOLOGY COSTS
UNRESTRICTED ACTIVITY
STHOUSAND, 1986 DOLLARS
$21/bbl
PRODUCED WATER CONTROL OPTIONS
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
ZERO
DISCHARGE
SO
$16,106
$35,363
$42.992
$54,277
$69, 149
$86,664
$108,639
$129,132
$151,378
$170,790
$194,328
$216,712
$236,858
$254,829
$275,109
ALL
FILTER
$0
$7,555
$16,650
$20,446
$25,748
$32,615
$40,691
$50,712
$60,325
$70,499
$79,701
$90,343
$100,780
$110,212
$118,483
$127,500
4-Mile Filter;
BPT Other
$0
$1,579
$3,531
$4,137
$5,342
$6,903
$8,482
$10,667
$12,171
$14,356
$15,736
$19,162
$21,193
$22,697
$24,200
$27,024
6-39
-------
TABLE 6-30
ANNUAL I ZED COSTS OF NSPS PRODUCED WATER CONTROL OPTIONS
MEMBRANE FILTER TECHNOLOGY COSTS
UNRESTRICTED ACTIVITY
STHOUSAND, 1986 DOLLARS
$21/bbl
PRODUCED WATER CONTROL OPTIONS
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
ZERO
DISCHARGE
SO
$12,184
$26,504
$31,637
$39,795
$50,455
$63,351
$79,763
$94,825
$111,488
$125,638
$142,715
$159,137
$173,902
$187,326
$202,249
ALL
FILTER
$0
$4,842
$10,638
$12,979
$16,308
$20,593
$25,686
$32,099
$38,191
$44,660
$50,483
$57,216
$63,832
$69,785
$75,033
$80,811
4-Mile Filter;
BPT Other
$0
$1,009
$2,252
$2,621
$3,373
$4,334
$5,343
$6,721
$7,680
$9,058
$9,929
$12,071
$13,347
$14,306
$15,266
$17,041
6-40
-------
The annualized costs for produced water disposal under the $21/bbl
restricted development scenario are displayed in Tables 6-31 and 6-32 for the
granular and membrane filter technology, respectively.
Tables 6-33 and 6-34 summarize the annualized costs in the year 2000 for:
$21/bbl unrestricted development
$21/bbl restricted development
$15/bbl restricted development
$32/bbl unrestricted development
Table 6-33 represents the costs with granular filtration, while Table 6-34
represents the costs with membrane filtration.
Note that the costs for the 4-Mile Filter; BPT Other option range from $12
million to $51 million (1986 dollars) with granular filtration and from $8
million to $32 million with membrane filtration.
The per-project annualized costs are lower for NSPS than BAT because it is
less expensive to design additional pollution control requirements into a new
platform than it is to retrofit an existing platform. This, coupled with the
fact that there are approximately two-and-one-half times as many existing
platforms as there are projected platforms, explains why the total annualized
costs for BAT-produced water pollution control options are several times
higher than total annualized costs for NSPS options.
6.4 COMBINED COST OF SELECTED REGULATORY OPTIONS
Six combinations of options have been chosen in order to analyze the
impacts of the increased pollution control on the three effluents. These
combinations are:
Drilling Fluids and Drill Cuttings: 4-Mile Barge; 1,1 Other1
Produced Water - BAT: 4-Mile Filter; BPT Other
(granular filter costs)
Produced Water - NSPS: 4-Mile Filter; BPT Other
(granular filter costs)
'Under the 4-Mile Barge; 1,1 Other option Alaska is exempt from the
barging requirement, but must comply with the 1,1 All restrictions.
6-41
-------
TABLE 6-31
ANNUAL!ZED COSTS OF NSPS PRODUCED WATER CONTROL OPTIONS
GRANULAR FILTER TECHNOLOGY COSTS
RESTRICTED ACTIVITY
STHOUSAND, 1986 DOLLARS
$21/bbl
PRODUCED WATER CONTROL OPTIONS
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
ZERO
DISCHARGE
$0
$13,257
$30,135
$34, 441
$41,466
$49,473
$65,302
$83,794
$98,307
$114,869
$128,596
$146,449
$161,093
$175,311
$188,534
$206,208
ALL
FILTER
$0
$6,197
$14,077
$16,297
$19,649
$23,358
$30,443
$38,558
$45,347
$52,891
$59,463
$67,475
$74.325
$80,975
$86,992
$94,802
4-Mile Filter;
BPT Other
$0
$1,052
$2,477
$2,556
$3,234
$3,740
$4,792
$5,923
$6,900
$8,031
$8,883
$11,255
$12,232
$13,208
$14,185
$16,481
6-42
-------
TABLE 6-32
ANNUAL IZED COSTS OF NSPS PRODUCED WATER CONTROL OPTIONS
MEMBRANE FILTER TECHNOLOGY COSTS
RESTRICTED ACTIVITY
STHOUSANDS, 1986 DOLLARS
$21/bbl
PRODUCED WATER CONTROL OPTIONS
YEAR
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
ZERO
DISCHARGE
SO
$10,390
$23,249
$26,286
$31,711
$37,972
$49,916
$64,115
$75,374
$88,406
$98,925
$112,371
$123,785
$134,790
$145,222
$158,479
ALL
FILTER
$0
$4,044
$9,151
$10,569
$12,743
$15,155
$19,710
$24,978
$29,397
$34,310
$38,578
$43,755
$48,213
$52,528
$56,455
$61,517
4-Mile Filter;
BPT Other
$0
$693
$1,619
$1,671
$2,107
$2,435
$3,128
$3,873
$4,516
$5,261
$5,815
$7,324
$7,967
$8,610
$9,253
$10,712
6-43
-------
TABLE 6-33
ANNUALIZED COST OF POLLUTION CONTROL IN THE YEAR 2000
NSPS PRODUCED WATER
GRANULAR FILTRATION TECHNOLOGY COSTS
MILLIONS, 1986 DOLLARS
Annualized Regulatory Costs
$21/bbl $21/bbl $15/bbl $32/bbl
Option Unrestricted Restricted Restricted Unrestricted
Zero Discharge $275 $206 $170 $375
All Filter $128 $95 $80 $168
4-Mile Filter; BPT Other $27 $16 $12 $51
Source: ERG estimates.
6-44
-------
TABLE 6-34
ANNUAL 1 ZED COST OF POLLUTION CONTROL IN THE YEAR 2000
NSPS PRODUCED WATER
MEMBRANE FILTRATION TECHNOLOGY COSTS
{MILLIONS, 1986 DOLLARS
Annualized Regulatory Costs
$21/bbl $21/bbl $15/bbl $32/bbl
Option Unrestricted Restricted Restricted Unrestricted
Zero Discharge $202 $158 $135 $270
All Filter $81 $62 $53 $108
4-Mile Filter; BPT Other $17 $11 $8 $32
Source: ERG estimates.
6-45
-------
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other1
Zero Discharge
(granular filter costs)
Zero Discharge
(granular filter costs)
4-Mile Barge; 1,1 Other1
All Filter
(granular filter costs)
All Filter
(granular filter costs)
4-Mile Barge; 1,1 Other1
All Filter
(membrane filter costs)
All Filter
(membrane filter costs)
Drilling Fluids and Drill Cuttings: 4-Mile Barge; 1,1 Other1
Produced Water - BAT: BPT All
Produced Water - NSPS: BPT All
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other1
4-Mile Filter; BPT Other
(membrane filter costs)
4-Mile Filter; BPT Other
(membrane filter costs)
These combinations are referred to as regulatory packages A through F,
respectively. Table 6-35 presents the combined cost of each package for the
$21/bbl scenario. Two sets of costs are presented for each regulatory package
(unrestricted and restricted development scenario). The costs presented are
the annualized costs in 2000 for NSPS effluents. The cost for offshore
package F (4-Mile Barge; 1,1 All and 4-Mile Filter; BPT Other with membrane
filter costs) ranges from $54 to $80 million (1986 dollars) depending upon the
level of development. The costs range from $30 million for regulatory package
E to $1,081 million (1986 dollars) for regulatory package B under restricted
development, and from $50 million to $1,170 million for the same options under
unrestricted development. Note that costs drop from $657 to $282 million or
from $605 to $242 million when the use of granular filtration is replaced by
membrane filtration in packages C and D, respectively. Similarly, the costs
drop from $118 to $80 million or from $88 to $54 million when membrane
filtration is assumed for Option F.
Tables 6-36 through 6-39 summarize the costs for the regulatory packages
by region. Note that the costs for the Gulf (Table 6-36) and Alaska (Table 6-
37) are the same for both restricted and unrestricted development scenarios.
6-46
-------
TABLE 6-35
COMBINED COST OF SELECTED REGULATORY PACKAGES
SHILL10NS, 1986 DOLLARS
S21/bbl
Regulatory
Package Effluent
A
B
C
D
E
F
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
BAT
NSPS
and Drill Cuttings
- BAT
NSPS
and Drill Cuttings
- BAT
- NSPS
Effluent
Control
Opt i on
4-Mile Barge; 1
4-Mile Filter;
4-Mile Filter;
4-Mile Barge; 1
Zero Discharge
Zero Discharge
4-Mile Barge; 1
All Filter
All Filter
Annuali zed Cost in the Year 2000
Restricted Unrestricted
,1 Other*
BPT Other
BPT Other
,1 Other*
,1 Other*
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1
BPT All
BPT All
4-Mile Barge; 1
4-Mile Filter;
4-Mile Filter;
,1 Other*
,1 Other*
BPT Other - Membrane
BPT Other - Membrane
$30
$41
$16
$88
$30
$845
$206
$1,081
$30
$480
$95
$605
$30
$151
$62
$242
$30
$0
$0
$30
$30
$13
$11
$54
$50
$41
$27
$118
$50
$845
$275
$1,170
$50
$480
$128
$657
$50
$151
$81
$282
$50
$0
$0
$50
$50
$13
$17
$80
Notes:
Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Entries may not sun due to independent rounding.
Source: ERG estimates.
tab6-35&.wk3
08-Feb-91
6-47
-------
TABLE 6-36
COMBINED COST OF SELECTED REGULATORY PACKAGES - GULF REGION
SMILLIONS, 1986 DOLLARS
$21/bbt
Regulatory
Package Effluent
A
B
C
D
E
F
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Effluent Annual ized Cost in the Year 2000
Option Restricted Unrestricted
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
4-Mile Barge; 1,1 Other*
All Filter
All Filter
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1,1 Other*
BPT All
BPT All
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other - Membrane
4-Mile Filter; BPT Other - Membrane
$29.5
$24.3
$13.8
$67.6
$29.5
$776.8
$186.6
$992.9
$29.5
$438.1
$86.8
$554.4
$29.5
$139.6
$56.6
$225.7
$29.5
$0.0
SO.O
$29.5
$29.5
$8.8
$9.1
$47.4
$29.5
$24.3
$13.8
$67.6
$29.5
$776.8
$186.6
$992.9
$29.5
$438.1
$86.8
$554.4
$29.5
$139.6
$56.6
'*
$29.5
$0.0
$0.0
$29.5
$29.5
$8.8
$9.1
$47.4
Notes:
Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Entries may not son due to independent rounding.
Source: ERG estimates.
tab6-35i.wk3
08-Feb-91
6-48
-------
TABLE 6-37
COMBINED COST OF SELECTED REGULATORY PACKAGES - ALASKA REGION
MILLIONS, 1986 DOLLARS
$21/bbl
Regulatory
Package Effluent
A
B
C
0
E
F
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Contained
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
-BAT
NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
Effluent
Control
Option
4-Mile Barge; 1
4-Mile Filter;
4-Mile Filter;
4-Mile Barge; 1
Zero Discharge
Zero Discharge
4-Mile Barge; 1
All Filter
All Filter
4-Mile Barge; 1
Annuali zed Cost in the Year 2000
Restricted
,1 Other*
BPT Other
BPT Other
,1 Other*
,1 Other*
,1 Other*
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1
BPT All
BPT All
4-Mile Barge; 1
4-Mile Filter;
4-Mile Filter;
,1 Other*
,1 Other*
BPT Other - Membrane
BPT Other - Membrane
SO
SO
$2
S3
SO
so
$8
So-
SO
SO
$3
S3
SO
$0
$2
S2
(0
so
so
$0
so
so
$1
$2
Unrestricted
.3
.0
.6
.0
.3
.0
.5
.9
.3
.0
.4
.8
.3
.0
.1
.5
.3
.0
.0
.3
.3
.0
.6
.0
SO
so
S2
S3
SO
$0
S8
S8
SO
SO
S3
S3
SO
so
S2
$2
SO
so
so
so
so
so
$1
S2
.3
.0
.6
.0
.3
.0
.5
.9
.3
.0
.4
.8
.3
.0
.1
.5
.3
.0
.0
.3
.3
.0
.6
.0
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
Notes: All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Entries may not sum due to independent rounding.
Source: ERG estimates.
tab6-3S&.wk3
08-Feb-91
6-49
-------
TABLE 6-38
COMBINED COST OF SELECTED REGULATORY PACKAGES - PACIFIC REGION
SMILLIONS, 1986 DOLLARS
$21/bbl
Regulatory
Package Effluent
A
B
C
D
E
F
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Drilling
Produced
Produced
Combined
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
Fluid
Water
Water
Cost
and Drill Cuttings
-
-
BAT
NSPS
and Drill Cuttings
-
-
BAT
NSPS
and Drill Cuttings
-
-
BAT
NSPS
and Drill Cuttings
-
-
BAT
NSPS
and Drill Cuttings
-
-
BAT
NSPS
and Drill Cuttings
-
-
BAT
NSPS
Effluent
Control
Option
4-Mile Barge; 1
4-Mile Filter;
4-Mile Filter;
4-Mile Barge; 1
Zero Discharge
Zero Discharge
4-Mile Barge; 1
All Filter
All Filter
4-Mile Barge; 1
Annual! zed Cost in the Year 2000
Restricted
,1 Other*
BPT Other
BPT Other
,1 Other*
,1 Other*
,1 Other*
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1
BPT All
BPT All
4-Mile Barge; 1
4-Mile Filter;
4-Mile Filter;
,1 Other*
.1 Other*
BPT Other - Membrane
BPT Other - Membrane
SO
$17
$0
$17
SO
$67
$11
$79
$0
$42
$4
$46
$0
$11
$2
$14
SO
SO
SO
$0
$0
$4
SO
$4
Unrestricted
.1
.0
.0
.1
.1
.9
.1
.0
.1
.0
.5
.6
.1
.2
.8
.1
.1
.0
.0
.1
.1
.1
.0
.2
$19
$17
$10
$46
$19
$67
$77
$164
.3
.0
.5
.8
.3
.9
.2
.4
$19.3
$42
$35
$97
$19
$11
$21
*
$19
$0
$0
$19
$19
$4
$6
$29
.0
.9
.1
.3
.2
.2
»
.3
.0
.0
.3
.3
.1
.3
.7
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
Notes: All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Entries may not sum due to independent rounding.
Source: ERG estimates.
tab6-35&.wk3
08-Feb-91
6-50
-------
TABLE 6-39
COMBINED COST OF SELECTED REGULATORY PACKAGES - ATLANTIC REGION
MILLIONS, 1986 DOLLARS
$21/bbl
Regul story
Package
A
B
C
D
E
F
Effluent
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Combined Cost
Drilling Fluid and Drill Cuttings
Produced Water BAT
Produced Water - NSPS
Combined Cost
Effluent
Control
Option
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
4-Mile Barge; 1,1 Other*
All Filter
All Filter
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Manbrane
4-Mile Barge; 1,1 Other*
BPT All
BPT All
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
Annual i zed Cost
Restricted
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
- Membrane $0.0
- Membrane $0.0
$0.0
in the Year 2000
Unrestricted
$0.8
$0.0
$0.0
$0.8
$0.8
$0.0
$2.7
$3.6
$0.8
$0.0
$1.4
$2.2
$0.8
$0.0
$0.9
$1.8
$0.8
$0.0
$0.0
$0.8
$0.8
$0.0
$0.0
$0.8
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
Notes: All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Entries nay not sura due to independent rounding.
Source: ERG estimates.
tab6-35&.wk3
OS-Feb-91
6-51
-------
The costs for the Pacific (Table 6-38) and the Atlantic (Table 6-39) do vary
according to the assumptions on the level of development. In all cases, the
Gulf of Mexico bears the majority of the costs because it has the majority of
the projected development.
6.5 REFERENCES
FR 1985. "Draft General NPDES Permit for Offshore Oil and Gas Exploration
Activities Off Southern California," Federal Register volume 50, 22 August
1985, 34036 ff.
FR 1986. "Final NPDES General Permit for the Outer Continental Shelf (OCS)
of the Gulf of Mexico," Federal Register volume 51, 9 July 1986, 24897 ff.
FR 1988a. "Oil and Gas Extraction Point Source Category, Offshore
Subcategory; Effluent Limitations Guidelines and New Source Performance
Standards; New Information and Request for Comments," Federal Register
volume 53, 21 October 1988, 41356 ff.
FR 1988b. "Final NPDES General Permit for Offshore Oil and Gas Operations on
the Outer Continental Shelf of Alaska: Beaufort Sea II and Chukchi Sea,"
Federal Register volume 53, 28 September 1988, 37846 ff.
Kaplan 1989a. "Determination of Least-Cost Approach to Using Pill in the
Pacific Region," memorandum to Offshore file from Maureen F. Kaplan,
Eastern Research Group, Inc., 21 December 1989.
Kaplan 1989b. "Agreement on Price Increase for 1,2 and 1,3 Barite,"
memorandum to Offshore file from Maureen F. Kaplan, Eastern Research
Group, Inc., 20 December 1989.
Kaplan and Meyers 1987. "The Adequacy of Available Foreign and Domestic
Supplies of Barite That Meet Revised Limitations for Cadmium and Mercury
Content," memorandum from Maureen F. Kaplan and David Meyers, Eastern
Research Group, Inc., to Ann Watkins, EPA, 4 November 1987.
WHA 1984. "Potential Impacts of Proposed EPA BAT/NSPS Standards for Produced
Water Discharges from Offshore Oil and Gas Extraction Industry," Walk,
Haydel Associates, January 1984, Table 2-7.
6-52
-------
SECTION SEVEN
IMPACTS ON REPRESENTATIVE FACILITIES
New and existing offshore projects incur additional costs for increased
pollution control of drilling and production wastes. Section Five describes
the offshore oil and gas projects used in this analysis and presents the
results of the base case simulations. Section Six describes incremental costs
of compliance under the various pollution control options. In this section,
the incremental costs are incorporated into the economic simulations. By
examining the change in the financial summary statistics for each project, ERG
assesses the economic impacts of the various approaches. Section Seven is
organized according to effluent and type of regulation (e.g., BAT or NSPS).
Drilling wastes are discussed in Section 7.1. Production wastes are discussed
in Section 7.2 for BAT projects and in Section 7.3 for NSPS projects. Section
7.4 discusses the combined effect of selected pollution control options.
7.1 DRILLING FLUIDS AND DRILL CUTTINGS
The incremental costs of pollution control are incurred by every
exploratory, delineation, and development well. Tables 7-1 and 7-2 list the
impacts for the oil and gas projects for the Gulf of Mexico. Table 7-3 lists
the impacts for the oil and gas projects in the Pacific and the Atlantic. Oil-
producing projects in Alaska and their impacts are presented in Table 7-4.
Impacts on gas-only projects are presented in Table 7-5 for the Gulf of Mexico
and in Table 7-6 for all other regions.
7.1.1 Financial Summary Statistics
PV of Total Production: The present value (PV) of total production is
given in terms of barrels-of-oil equivalent (BOE) and is related to the
economic lifetime of the project. There is no change in this parameter for
any project under any regulatory scenario.
Corporate Cost per BOE: The corporate cost of production changes less
than 2.3 percent or 47 cents per BOE for all pollution control options. The
7-1
-------
TABLE 7-1
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
GULF OF MEXICO
PV of Total Production
(Bbls-of-oil equivalent)
PROJECT
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 4
Gulf 4
Gulf 4
Gulf 4
Gulf t,
Gulf 4
"J4 Gulf 6
ro Gulf 6
Gulf 6
Gulf 6
Gulf 6
Gulf 6
Gulf 12
Gulf 12
Gulf 12
Gulf 12
Gulf 12
Gulf 12
SCENARIO
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Basel ine
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4 -Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Data X
1,159,301
1,159,301
1,159,301
1,159,301
1,159,301
1,159,301
4,301,632
4,301,632
4.301,632
4,301,632
4.301,632
4.301.632
6,452,448
6,452,448
6,452.448
6,452.448
6,452,448
6,452,448
9,611,069
9.611,069
9,611,069
9,611,069
9,611,069
9,611,069
Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data
$21.16
$21.63
$21.23
$21.21
$21.18
$21.17
$18.09
$18.35
$18.13
$18.12
$18.10
$18.09
$17.71
$17.96
$17.75
$17.74
$17.72
$17.71
$18.23
$18.46
$18.26
$18.25
$18.24
$18.23
X Change
2.2X
0.3X
0.2X
0.1X
O.OX
1.5X
0.2X
0.2X
0.1X
O.OX
1.4X
0.2X
0.2X
0.1X
O.OX
1.3X
0.2X
0.1X
0.1X
O.OX
Production Cost
Per BOE
Data
$13.71
$14.39
$13.81
$13.78
$13.74
$13.71
$8.98
$9.35
$9.03
$9.02
$8.99
$8.98
$8.40
$8.74
$8.45
$8.43
S8.41
$8.40
$8.95
$9.27
$9.00
$8.98
$8.96
$8.95
X Change
5. OX
0.7X
0.5X
0.2X
O.OX
4. IX
0.6X
0.5X
0.2X
O.OX
4. IX
0.6X
0.4X
0.2X
O.OX
3.6X
0.5X
0.3X
0.1X
O.OX
Net Present Value
($1000)
Data
$654
$110
$579
$597
$632
$652
$15,649
$14,518
$15,492
$15,530
$15,603
$15,645
$25,909
$24.327
$25.690
$25.743
$25.845
$25,904
$33,610
$31,369
$33,300
$33.375
$33,519
$33,603
X Change
-83. 1X
-11. 5X
-8.7X
-3.4X
-0.3X
-7.2X
-1.0X
-0.8X
-0.3X
-O.OX
-6.1X
-0.8X
-0.6X
-0.2X
-O.OX
-6.7X
-0.9X
-0.7X
-0.3X
-O.OX
Internal Rate
Of Return
Data X
9.5X
8.2X
9.3X
9.4X
9.4X
9.5X
21. 4X
19. 9X
21. 2X
21. 2X
21. 3X
21. 4X
23.1%
21. 7X
22. 9X
23. OX
23. 1X
23. 1X
20. 1X
18. 9X
19. 9X
20. OX
20. OX
20.1%
Change
-13. 2X
-2. OX
-0.9X
-0.6X
-O.OX
-6.8X
-0.8X
-0.8X
-0.3X
-O.OX
-6.3X
-1.0X
-0.6X
-0.3X
-O.OX
-5.9X
-1.0X
-0.5X
-0.2%
-O.OX
Years Of
Production
Data
20
20
20
20
20
20
21
21
21
21
21
21
21
21
21
21
21
21
19
19
19
19
19
19
X Change
O.OX
O.OX
0.0%
O.OX
0.0%
0.0%
O/
O.C..
0.0%
O.OX
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Source: ERG estimates.
-------
TABLE 7-2
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS AND OIL-ONLY PLATFORMS
GULF OF MEXICO - Continued
PV of Total Production
(Bbls-of-oil equivalent)
PROJECT
Gulf 24
Gulf 24
Gulf 24
Gulf 24
Gulf 24
Gulf 24
Gulf 40
Gulf 40
Gulf 40
Gulf 40
Gulf 40
Gulf 40
Gulf 58
-J1 Gulf 58
it Gulf 58
Gulf 58
Gulf 58
Gulf 58
SCENARIO
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5.3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Basel ine
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5.3 Other
1,1 All
5,3 All
Data
17,470,722
17.470.722
17.470.722
17.470.722
17.470,722
17.470,722
29,889,385
29.889,385
29,889.385
29,889,385
29.889,385
29.889,385
35,194,925
35,194.925
35.194,925
35.194.925
35,194,925
35.194,925
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data
$16.26
$16.47
(16.29
S16.28
S16.27
$16.26
$16.04
$16.24
$16.07
$16.06
$16.05
$16.04
$16.53
$16.74
$16.56
$16.55
$16.54
$16.53
X Change
1.3X
0.2X
0.1X
0.1X
O.OX
1.3X
0.2X
0.1X
0.1X
O.OX
1.2X
0.2X
0.1X
O.OX
O.OX
Production Cost
Per BOE
Data
$8.13
$8.42
$8.17
$8.16
$8.15
$8.14
$7.74
$8.02
$7.78
$7.77
$7.76
$7.75
$7.90
$8.17
$7.94
$7.93
$7.91
$7.90
X Change
3.6X
0.4X
0.3X
0.1X
O.OX
3.6X
0.5X
0.3X
0.1X
O.OX
3.4X
0.5X
0.4X
0.1%
O.OX
Net Present Value
($1000)
Data
$95.532
$91,824
$95,019
$95.144
$95,382
$95,520
$169,856
$163.806
$169,018
$169.222
$169,610
$169,835
$182,742
$175,575
$181.750
$181.992
$182,452
$182.718
X Change
-3.9X
-0.5X
-0.4X
-0.2X
-O.OX
-3.6X
-0.5X
-0.4X
-0.1X
-O.OX
-3.9X
-0.5X
-0.4X
-0.2X
-O.OX
Internal Rate
Of Return
Data X
27.3%
25. 9X
27. 1X
27.2X
27. 2X
27.3%
25. 2X
24. 1X
25. IX
25. 1X
25. 2X
25. 2X
20. 7%
19. 9X
20. 6X
20.6%
1 20.7%
20. 7X
Change
-5.0%
-0.8X
-0.4%
-0.2%
-0.0%
-4.4%
-0.6%
-0.6%
-0.2%
-0.0%
-3.9%
-0.6%
-0.6X
-0.2%
-0.0%
Years Of
Production
Data
21
21
21
21
21
21
23
23
23
23
23
23
25
25
25
25
25
25
% Change
0.0%
0.0%
O.OX
0.0%
O.OX
0.0%
0.0%
0.0%
O.OX
0.0%
0.0%
0.0%
O.OX
0.0%
0.0%
Source: ERG estimates.
-------
TABLE 7-3
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
ATLANTIC AND PACIFIC
PV of Total Production
(Bbls-of-oil equivalent) .
PROJECT SCENARIO
Atlantic 24 Baseline
Atlantic 24 Zero Discharge
Atlantic 24 4-Mile Barge; 1,1 Other
Atlantic 24 4-Mile Barge; 5,3 Other
Atlantic 24 1,1 All
Atlantic 24 5,3 All
Pacific 16 Baseline
Pacific 16 Zero Discharge
Pacific 16 4-Mile Barge; 1,1 Other
Pacific 16 4-Mile Barge; 5,3 Other
Pacific 16 1.1 All
Pacific 16 5,3 All
I Pacific 40 Baseline
* Pacific 40 Zero Discharge
Pacific 40 4-Mile Barge; 1,1 Other
Pacific 40 4-Mile Barge; 5,3 Other
Pacific 40 1,1 All
Pacific 40 5,3 All
Pacific 70 Baseline
Pacific 70 Zero Discharge
Pacific 70 4-Mile Barge; 1,1 Other
Pacific 70 4-Mile Barge; 5,3 Other
Pacific 70 1,1 All
Pacific 70 5,3 All
Data X
25,801.198
25,801,198
25,801,198
25.801,198
25,801.198
25,801.198
11.449.953
11.449,953
11.449,953
11.449.953
11,449,953
11,449,953
20,252,704
20.252,704
20,252.704
20.252,704
20.252.704
20,252.704
29,277,100
29,277.100
29,277,100
29,277,100
29,277.100
29,277,100
Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data X
S19.05
$19.34
$19.08
$19.08
$19.08
$19.08
$12.96
$13.19
$13.04
$13.04
$12.97
$12.96
$12.89
$13.09
$12.95
$12.95
$12.89
$12.89
$12.38
$12.58
$12.44
$12.44
$12.38
$12.38
Change
1.5X
0.2X
0.1X
0.2X
0.1X
1.8X
0.6X
0.6X
O.OX
O.OX
1.6X
0.5X
0.5X
O.OX
O.OX
1.6X
0.5X
0.5X
O.OX
O.OX
Production
Per BOE
Data X
$16.52
$16.92
$16.56
$16.55
$16.56
$16.55
$7.19
$7.51
$7.29
$7.29
$7.20
$7.19
$6.05
$6.32
$6.13
$6.13
$6.05
$6.05
$5.94
$6.19
$6.02
$6.02
$5.94
$5.94
Cost
Change
2.5X
0.3X
0.2X
0.3X
0.2X
4.4X
1.4X
1.4X
0.1X
O.OX
4.5X
1.4X
1.4X
0.1X
O.OX
4.3X
1.4X
1.4X
0.1X
O.OX
Net Present Value
($1000)
Data X
($66,121)
($73,721)
($66,991)
($66,810)
($66,991)
($66,810)
$45,337
$42,686
$44.488
$44,488
$45,295
$45.337
$81,686
$77,529
$80,355
$80.355
$81.620
$81.686
$132,919
$127,198
$131,087
$131,087
$132.828
$132,919
Change
-11. 5X
-1.3X
-1.0X
-1.3X
-1.0X
-5.8X
-1.9X
-1.9X
-0.1X
O.OX
-5. IX
-1.6X
-1.6X
-0.1X
O.OX
-4.3X
-1.4X
-1.4X
-0.1X
O.OX
Internal Rate
Of Return
Data X
2.6X
2.1X
2.5X
2.5X
2.5X
2.5X
39. 4X
36. IX
38. 3X
38. 3X
39. 3X
39. 4X
33. 8X
31. 5X
33. IX
33. IX
33. 8X
33. BX
29.5X
27. 8X
29. OX
29.0X
29. 5X
29.5X
Change
-18.7X
-2.2X
-1.7X
-2.2X
-1.7X
-8.2X
-2.7X
-2.7X
-0.1X
O.OX
-6.8X
-2.2X
-2.2X
-0.1X
O.OX
-5.7X
-1.7X
-1.7X
-0.1X
O.OX
Years Of
Production
Data
21
21
21
21
21
21
9
9
9
9
9
9
10
10
10
10
10
10
^^
12
12
12
12
12
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
0.0'
0.0.
O.OX
Note: There is no activity within 4 miles of shore for the Atlantic, so only the Zero Discharge. 1,1 All, and 5,3 All options are applicable.
For the Pacific, the 4-Mile Barge scenarios refer to the $21/bbt unrestricted development scenario.
There is no activity within 4 miles for the Pacific under the S21/bbl restricted development scenario. The impacts, then, revert to
the 1,1 All and 5,3 All options.
Source: ERG estimates.
-------
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS AND OIL-ONLY PLATFORMS*
ALASKA
PV of Total Production
(Bbls-of-oil equivalent)
PROJECT
Cook Inlet
Cook Inlet
Cook Inlet
Cook Inlet
Cook Inlet
Cook Inlet
Beaufort G
Beaufort G
Beaufort G
Beaufort G
Beaufort G
Beaufort G
-4
1 Beaufort P
01 Beaufort P
Beaufort P
Beaufort P
Beaufort P
Beaufort P
Navarin
Navarin
Navarin
Navarin
Navarin
Navarin
Norton
Norton
Norton
Norton
Norton
Norton
SCENARIO
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4-Hile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Basel ine
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5.3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5.3 Other
1,1 All
5,3 All
Basel ine
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Data
61,707.003
61,707.003
61,707.003
61,707,003
61,707,003
61,707.003
73,172,498
73,172.498
73,172,498
73,172.498
73.172.498
73.172.498
67,592,103
67,592,103
67,592,103
67,592.103
67,592.103
67.592.103
73,172,498
73.172,498
73.172.498
73,172.498
73,172,498
73,172,498
61,740,561
61,740,561
61,740,561
61.740.561
61.740.561
61,740,561
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data
$13.22
$13.29
$13.27
$13.27
$13.22
$13.22
$12.19
$12.26
$12.25
$12.25
$12.19
$12.19
$11.50
$11.58
$11.56
$11.56
$11.51
$11.50
$12.41
$12.48
$12.46
$12.46
$12.41
$12.41
$11.22
$11.30
$11.28
$11.28
$11.23
$11.23
X Change
0.5X
0.4X
0.4X
O.OX
O.OX
0.6X
0.5X
0.5X
0.1X
O.OX
0.7X
0.5X
0.5X
0.1X
O.OX
0.6X
0.5X
0.5X
0.1X
O.OX
0.7X
0.5X
0.5X
0.1X
O.OX
Production
Per BOE
Data X
$4.18
$4.28
$4.26
$4.26
$4.19
$4.19
$5.53
$5.63
$5.61
$5.61
$5.54
$5.54
$6.33
$6.43
$6.41
$6.41
$6.34
$6.34
$7.47
$7.56
$7.54
$7.54
$7.47
$7.47
$6.09
$6.19
$6.17
$6.17
$6.09
$6.09
Cost
Change
2.3X
1.8X
1.8X
0.2X
0.1X
1.7X
1.4X
1.4X
0.2X
0.1X
1.6%
1.2X
1.2X
0.1X
0.1X
1.3X
1.0X
1.0X
0.1X
0.1X
1.7X
1.3X
1.3X
0.1X
0.1X
Net Present Value
($1000)
Data
$357,708
$353.300
$354,263
$354,263
$357.328
$357,423
$191.157
$185,740
$186,924
$186,924
$190.690
$190.807
$223,074
$217,969
$219,084
$219,084
$222.634
$222.744
$175.208
$169,792
$170,975
$170,975
$174,741
$174,858
$220,856
$216,060
$217,108
$217,108
$220,443
$220,547
X Change
-1.2X
-1.0X
-1.0X
-0.1X
-0.1X
-2.8X
-2.2X
-2.2X
-0.2X
-0.2X
-2.3X
-1.8X
-1.8X
-0.2X
-0.1X
-3. IX
-2.4X
-2.4X
-0.3X
-0.2X
-2.2X
-1.7X
-1.7X
-0.2X
-0.1X
Internal Rate
Of Return
Data X
39. OX
37. 9X
38. 2X
38. 2X
38. 9X
39. OX
18. 4X
18.0X
18. 1X
IB. IX
18.4%
18. 4X
20.5%
20. OX
20. 1X
20. IX
20. 5X
20. 5X
15. 2X
14. 9X
14. 9X
14. 9X
15. IX
15. 1X
24. 1X
23. 5X
23. 6X
23. 6X
24. IX
24. IX
Change
-2.8X
-2.2X
-2.2X
-0.2X
-0.2X
-2.6X
-2. OX
-2. OX
-0.2X
-0.2X
-2.4X
-1.8X
-1.8X
-0.2X
-0.2X
-2. OX
-1.6X
-1.6X
-0.2X
-0.1X
-2.7X
-2. IX
-2. IX
-0.2X
-0.2X
Years Of
Production
Data X
30
30
30
30
30
30
30
30
30
30
30
30
28
28
28
28
28
28
30
30
30
30
30
30
27
27
27
27
27
27
Change
O.OX
O.OX
O.OX
O.OX
O.OX
0.0%
O.OX
O.OX
0.0%
O.OX
0.0%
O.OX
O.OX
O.OX
O.OX
0.0%
O.OX
O.OX
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
* Cook Inlet project produces both oil and gas; all other projects are assumed to produce only oil.
Source: ERG estimates.
-------
TABLE 7-5
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - GAS-ONLY PLATFORMS
GULF OF MEXICO
PV of Total Production
(Bbls-of-oil equivalent)
PROJECT
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 1b
Gulf 4
Gulf 4
Gulf 4
Gulf 4
Gulf 4
,Gulf 4
Gulf 6
1 Gulf 6
-------
TABLE 7-6
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - GAS-ONLY PLATFORMS
ATLANTIC, PACIFIC, AND ALASKA
PV of Total Production
(Bbls-of-oil equivalent)
PROJECT
Atlantic
Atlantic
Atlantic
Atlantic
Atlantic
Atlantic
Pacific 16
Pacific 16
Pacific 16
Pacific 16
Pacific 16
Pacific 16
Cook Inlet
Cook Inlet
Cook Inlet
Cook Inlet
Cook Inlet
Cook Inlet
SCENARIO
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4-Mile Barge; 1.1 Other
4-Mile Barge; 5.3 Other
1,1 All
5,3 All
Basel ine
Zero Discharge
4-Mile Barge; 1.1 Other
4-Mile Barge; 5.3 Other
1,1 All
5,3 All
Data X
38.935,162
38,935,162
38.935,162
38,935.162
38.935,162
38.935,162
15,493.937
15.493,937
15.493,937
15.493.937
15.493.937
15.493.937
52,694.332
52,694,332
52,694,332
52,694,332
52.694.332
52.694,332
Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data
$12.28
$12.46
$12.30
$12.29
$12.30
$12.29
$10.08
$10.24
$10.13
$10.13
$10.08
$10.08
$8.41
$8.47
$8.46
$8.46
$8.42
$8.42
X Change
1.5X
0.2X
0.1X
0.2X
0.1X
1.6X
0.5X
0.5X
O.OX
O.OX
0.7X
0.6X
0.6X
0.1X
0.1X
Production Cost
Per BOE
Data
$10.52
$10.77
$10.55
$10.54
$10.55
$10.54
$7.03
$7.25
$7.10
$7.10
$7.04
$7.03
$2.96
$3.04
$3.02
$3.02
$2.97
$2.97
X Change
2.4X
0.3X
0.2X
0.3X
0.2X
3. IX
0.9X
0.9X
O.OX
O.OX
2.6X
2. IX
2. OX
0.4X
0.3X
Net Present Value
($1000)
Data X
($59,921)
($66.969)
($60.728)
($60.560)
($60.728)
($60,560)
$10,241
$7.726
$9.436
$9.436
$10,202
$10,241
$188,211
$185,415
$186,026
$186.026
$187.970
$188,031
Change
-11. 8X
-1.3X
-1.1X
-1.3X
-1.1X
-24.6%
-7.9X
-7.9X
-0.4X
O.OX
-1.5X
-1.2X
-1.2X
-0.1X
-0.1X
Internal Rate
Of Return
Data X
4.1%
3.7X
4. IX
4.1X
4.1X
4. IX
11.8%
10.8%
11. 5X
11. 5X
11.8%
11.8%
31.6%
30. 7X
30. 9X
30. 9X
31. 5X
31. 5X
Change
-9.8X
O.OX
O.OX
O.OX
O.OX
-8.7%
-2.8%
-2.8%
-0.1%
0.0%
-2.8%
-2.2X
-2.2X
-0.2X
-0.2%
Years Of
Production
Data
25
25
25
25
25
25
13
13
13
13
13
13
29
29
29
29
29
29
% Change
0.0%
O.OX
O.OX
O.OX
O.OX
0.0%
O.OX
O.OX
O.OX
O.OX
0.0%
0.0%
0.0%
0.0%
0.0%
Source: ERG estimates.
-------
2.3 percent impact is for the Zero Discharge option for the smallest project
investigated -- the Gulf Ib. The 2.3 percent increase is seen for the gas-
only project while the 47 cent increase is seen for the oil and gas project.
Under the 4-Mile Barge; 1,1 Other option, the corporate cost per BOE increases
by less than a dime for the Gulf Ib. For the Gulf 12 and larger projects, the
impacts are about half as much as those seen for the Gulf Ib.
Production Cost per BOE: Slightly higher impacts are seen on the
production cost than on the corporate cost. There are two reasons for this.
First, the pollution control options increase investment costs. This leads to
a higher amount that can be depreciated which, in turn, leads to lower taxes.
The change in the corporate cost reflects after-tax effects while the change
in production cost reflects pre-tax effects. Second, the baseline value for
the production cost is smaller than that for the corporate cost. The smaller
baseline value implies that a change of the same magnitude (e.g., two cents
per BOE) will have a larger proportional impact. Under the 4-Mile Barge; 1,1
Other option, production cost increases by no more than 0.7 percent or 10
cents per BOE for the most affected project, the Gulf Ib.
Internal Rate of Return: This parameter varies greatly depending upon the
size of the project and the pollution control option. For all options except
Zero Discharge and all projects except the Gulf Ib, the internal rate of
return (IRR) decreases by 3 percent or less. For the Zero Discharge option,
except for the Gulf Ib and Atlantic 24 projects, the IRR declines by 2 to 8.2
percent. Because of the small baseline IRR values for the Gulf Ib and
Atlantic 24 projects, decreases of less than 1.3 percent in the IRR itself
appear as declines in the range of 10 to 20 percent. Even for the Gulf Ib the
IRR declines less than 4 percent under the 4-Mile Barge; 1,1 Other option.
Net Present Value: The magnitude of the impact on net present value (NPV)
is related to the size of the baseline value for NPV. For oil-producing
projects (except for the Gulf Ib), the NPV declines by 7.2 percent or less for
the Zero Discharge option. Gas-only projects (except for the Gulf Ib) show
declines in NPV ranging from 2 to 25 percent. Because of the small net
present values for the Gulf Ib projects, a decrease in the net present value
of approximately half a million dollars under the Zero Discharge option
appears as a decrease of 31 to 83 percent in the projects' NPV. Under the 4-
Mile Barge; 1,1 Other option, the NPV for the Gulf Ib projects decline by less
than 100 thousand dollars.
7-8
-------
7.1.2 Sensitivity Analysis
Two cases were analyzed in the sensitivity analysis:
$15/bbl price of oil
. $32/bbl price of oil
The sensitivity analysis cases were run for the Gulf Ib and the Gulf 12 oil
and gas projects. The Gulf Ib is the smallest project in the study and is,
therefore, likely to show greater impacts than the larger projects, while the
Gulf 12 is more representative of a typical-sized Gulf project.
Tables 7-7 and 7-8 summarize results of the sensitivity analysis. There
is no early shut-off of the projects, so no change is seen in the PV of total
production. The corporate and production costs per BOE for each option range
only within 1 percent from those in the baseline case. The net present value
and the internal rate of return range more widely, but greater variation is
caused by the change in oil prices than by the various regulatory options.
Under the $15/bbl scenario, the Gulf Ib has a negative net present value in
the baseline case. (In other words, many projects of this size would not be
economical to undertake under this oil price even without the proposed
regulations.) Even the Zero Discharge option for the Gulf Ib project does not
lead to a negative net present value in the $21/bbl and $32/bbl scenarios.
7.2 PRODUCED WATER - BAT
The incremental costs of additional pollution controls on produced water
from existing projects were applied at the mid-life of each economic model
(see Section Five). There are no existing structures in the Atlantic and the
only offshore project in Alaska (the Endicott field) is already required to
inject its produced water by State regulations. Therefore, ERG examined the
potential impacts of BAT regulations only for facilities in the Gulf of Mexico
and the Pacific.
There are two sets of costs for filtration and injection. Granular filter
technology costs assume that an addition to the platform is deemed necessary
for the additional pollution control equipment and a 3.5 multiplier is used to
account for transportation costs and other factors (see Section Six). Membrane
filter technology costs assume no platform addition and a 1.5 multiplier to
7-9
-------
I
>-
o
TABLE 7-7
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - SENSITIVITY ANALYSIS
GULF OF MEXICO - GULF 1b PROJECT - OIL AND GAS PRODUCTION
SENSIT1VIT
ANALYSIS
Baseline
$15/bbl
$32/bbl
PV of Total Production
(Bbls-of-oil equivalent)
YD IT PI II ATrtD V - - *
HCUULn 1 UK I
SCENARIO Data
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1.1 All
5,3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1.1 All
5.3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
.159,301
.159,301
.159,301
,159,301
,159.301
,159,301
,153,130
,153,130
,153,130
.153,130
,153,130
,153,130
,163,124
,163.124
.163.124
.163,124
.163.124
.163,124
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data
$21.16
$21.63
$21.23
$21.21
$21.18
$21.17
$17.96
$18.43
$18.03
$18.01
$17.98
$17.96
$27.06
$27.53
$27.13
$27.11
$27.08
$27.06
X Change
2.2X
0.3X
0.2X
0.1X
O.OX
2.6X
0.4X
0.3X
0.1X
O.OX
1.7X
0.3X
0.2X
0.1X
O.OX
Production Cost
Per BOE
Data
$13.71
$14.39
$13.81
$13.78
$13.74
$13.71
$13.71
$14.39
$13.80
$13.78
$13.74
$13.71
$13.73
$14.41
$13.83
$13.80
$13.76
$13.73
X Change
5. OX
0.7X
0.5X
0.2X
O.OX
5. OX
0.7X
0.5X
0.2X
O.OX
4.9X
0.7X
0.5X
0.2X
O.OX
Net Present Value
($1000)
Data X
$654
$110
$579
$597
$632
$652
($2.806)
($3.349)
($2,880)
($2,861)
($2.828)
($2.808)
$7.038
$6,494
$6,962
$6.981
$7,016
$7,036
Change
-83. IX
-11. 5X
-8.7X
-3.4X
-0.3X
-19. 4X
-2.6X
-2. OX
-0.8X
-0.1X
-7.7X
-1.1X
-0.8X
-0.3X
-O.OX
Internal Rate
Of Return
Data X
9.5X
8.2X
9.3X
9.4X
9.4X
9.5X
1.1X
0.1X
1.0X
1.0X
1.1X
1.1X
22. 9X
21. 2X
22. 7X
22. 7X
22. 9X
22. 9X
Change
-13. 2X
-2. OX
-0.9X
-0.6X
-O.OX
-88. 5X
-9.4X
-9.4X
-3.7X
-0.3X
-7.8X
-1.1X
-1.1X
-0.3X
-O.OX
Years Of
Production
Data
20
20
20
20
20
20
18
18
18
18
18
18
22
22
22
22
22
22
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
0.0%
O.OX
0.0%
O.OX
0.0%
Source: ERG estimates.
-------
TABLE 7-8
POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS AND DRILL CUTTINGS
MODEL PROJECT IMPACTS - SENSITIVITY ANALYSIS
GULF OF MEXICO - GULF 12 PROJECT - OIL AND GAS PRODUCTION
PI
(1
SENSITIVITY REGULATORY
ANALYSIS SCENARIO
Basel ine
$15/bbl
$32/bbl
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5,3 Other
1,1 All
5,3 All
Baseline
Zero Discharge
4-Mile Barge; 1,1 Other
4-Mile Barge; 5.3 Other
1.1 All
5,3 All
/ of Total Production
Jbls-of-oil equivalent)
Data X
9,611,069
9,611,069
9,611,069
9.611.069
9,611,069
9,611,069
9,539,096
9.539.096
9.539.096
9.539.096
9,539.096
9,539,096
9.671.105
9,671.105
9.671.105
9.671,105
9,671.105
9.671,105
Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
Per BOE
Data
(18.23
$18.46
$18.26
$18.25
$18.24
$18.23
$15.01
$15.24
$15.04
$15.03
$15.02
$15.01
$24.15
$24.39
$24.19
$24.18
$24.16
$24.15
X Change
1.3X
0.2X
0.1X
0.1X
O.OX
1.6X
0.2X
0.1X
0.1X
O.OX
1.0X
0.1X
0.1X
O.OX
O.OX
Production Cost
Per BOE
Data
$8.95
$9.27
$9.00
$8.98
$8.96
$8.95
$8.92
$9.24
$8.96
$8.95
$8.93
$8.92
$9.02
$9.34
$9.06
$9.05
$9.03
$9.02
X Change
3.6X
0.5X
0.3X
O.U
O.OX
3.6%
0.5X
0.4X
0.1X
O.OX
3.5X
0.5X
0.4X
0.1X
O.OX
Net Present Value
($1000)
Data
$33,610
$31.369
$33,300
$33,375
$33,519
$33,603
$4,931
$2.690
$4,632
$4,707
$4,840
$4,924
$86,639
$84,397
$86,326
$86,401
$86,548
$86,631
X Change
-6.7X
-0.9X
-0.7X
-0.3X
-O.OX
-45. 5X
-6.1X
-4.5X
-1.8X
-0.2X
-2.6X
-0.4X
-0.3X
-0.1X
-O.OX
Internal Rate
Of Return
Data X
20.1%
18. 9X
19. 9X
20. OX
20. OX
20. 1X
9.9X
9. OX
9.8X
9.9X
9.9X
9.9X
36. 4X
34. 7X
36. IX
36. 2X
36. 3X
36. 4X
Change
-5.9X
-1.0X
-0.5X
-0.2X
-O.OX
-9.2%
-1.5%
-0.5%
-0.4%
-0.0%
-4.6%
-0.8%
-0.5%
-0.2X
-O.OX
Years Of
Production
Data
19
19
19
19
19
19
17
17
17
17
17
17
22
22
22
22
22
22
X Change
0.0%
0.0%
O.OX
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Source: ERG estimates.
-------
account for transportation, etc. Tables 7-9 through 7-15 summarize the
impacts for the various options.
PV of Total Production: Increased annual operation and maintenance costs
(O&M) can lead to early abandonment of a project. The offshore injection
option leads to an early closure in 14 out of 26 projects with granular filter
costs and for 9 out of 26 projects with membrane filter costs. Onshore
injection leads to early closures in 8 out of 26 projects. Filtration leads
to early closures in either 11 or 8 out of 26 projects, depending on whether
granular or membrane filter costs are assumed. Most of the curtailments
involve the last year of production after a substantial amount of natural
decline has taken place. The impacts of early project closure are
investigated in Section Nine.
Corporate Cost per BOE: The Gulf Ib assumes that one reinjection well is
required to service one producing well. Under this assumption, the corporate
cost per BOE may increase by a factor of 2 to 2.5 or by $12/BOE to $17/BOE
(depending on whether granular or membrane filter costs are used in the
evaluation). The impacts on all other projects are far less severe, with
increases ranging from 2 to 51 percent or from $0.06/BOE to $5.83/BOE for the
Pacific 16 gas-only project and the Gulf 4 oil and gas project, respectively.
For the filtration options, the corporate cost per BOE increases by 14 to 43
percent for the Gulf Ib project. All other projects show increases of 1 to 34
percent or $0.09/BOE to $2.52/BOE.'
Production Cost per BQE: Production costs more than double for the Gulf
Ib under the Zero Discharge option. In contrast, where four single well
structures are assumed to share production/disposal facilities, production
costs rise by less than 40 percent even under the higher granular filter
costs. For all other structures, production cost increases do not exceed
$4.45/BOE for the Zero Discharge option.
Costs for the filtration options raise production costs per BOE by 26 to
67 percent for the Gulf Ib (depending on whether membrane or granular filter
1 In the seventh year of operation, the Pacific 16-well gas-only project
barely brings in sufficient revenue to cover operating costs. With any
increment to annual operating costs, the project shuts down after 6 years of
operation. Not only does the project not have to pay the additional year of
operating costs, but there is surplus depreciation from the capital
investments for incremental pollution control. Surplus depreciation is
assumed to lower total project costs (see Appendix J). With the combination
of these two factors, it appears to be slightly more economical to shut the
project down after 6 years, considering the production cost per BOE.
7-12
-------
TABLE 7-9
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
GULF OF MEXICO
I
h-«
CJ
Pollution Control Costs
Project
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Scenario
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Capital
$672
$286
$460
$385
$64
$2,019
$579
$1,710
$1,426
$170
$2,783
$1,237
$1,846
$1.546
$262
$3,361
$1,792
$1,890
$1,589
$298
$3,471
$2.812
$1,970
$715
$365
O&M
$29
$18
$17
$24
$14
$99
$57
$67
$83
$45
SI 24
$78
$71
$98
$59
$143
$96
$74
$106
$67
$143
$124
$78
$90
$80
Armualized
$144
$61
$89
$88
$22
$441
$141
$331
$299
$66
$518
$250
$334
$312
$87
$587
$330
$324
$310
$99
$636
$523
$339
$183
$122
PV of Total Production
(Bbls-of-oit equivalent)
Data
315,596
295,947
315,596
315.596
295.947
315,596
246,886
212,874
227,008
227.008
227,008
227,008
914,626
882, 192
882.192
882, 192
882, 192
914.626
,410,228
,371,938
,371,938
,371,938
,371,938
,371,938
2,882,620
2,780,400
2,780,400
2,882,620
2,780,400
2,780,400
X Change
-6.2X
O.OX
O.OX
-6.2X
O.OX
-13.8X
-8.1X
-8.1X
-8. IX
-8.1X
-3.5X
-3.5X
-3.5X
-3.5X
O.OX
-2.7X
-2.7X
-2.7X
-2.7X
-2.7X
-3.5X
-3.5X
O.OX
-3.5X
-3.5X
Corporate Cost
per BOE
Data X
$12.32
$16.38
$14.09
$15.04
$14.63
$12.83
$11.61
$29.17
$16.57
$25.36
$23.44
$13.28
$11.38
$17.21
$13.99
$15.15
$14.68
$12.14
$11.13
$15.66
$13.55
$13.60
$13.32
$11.58
$11.58
$13.77
$13.34
$12.87
$11.99
$11.76
Change
33. OX
14. 3X
22. OX
18. 7X
4.1X
151. 3X
42. 8X
118. 4X
101 .9X
14. 4X
51. 2X
22. 9X
33. IX
29. OX
6.7X
40. 7X
21. 7X
22. 2X
19. 7X
4. IX
19. OX
15. 2X
11. IX
3.6X
1.6X
Production Cost
per BOE
Data
S6.14
$8.54
$7.34
$7.88
$7.48
$6.58
S5.06
$15.98
$8.44
$13.64
$12.77
$6.38
$4.71
$8.45
$6.40
$7.04
$6.88
$5.40
$4.33
$7.24
$5.89
$5.86
$5.78
$4.67
$5.01
$6.32
$6.05
$5.86
$5.22
$5.07
X Change
39. IX
19. 6X
28. «
21. 9X
7.1X
216. OX
66. 8X
169. 8X
152. 4X
26. 1X
79. 5X
35. 9X
49. 6X
. 46. IX
14. 7X
67. 3X
36. OX
35. 2X
33. 6X
7. 8X
26.2%
20. 7X
17.0X
4.2X
1.3X
Net Present Value
($1000)
Data X
$1,159
$576
$890
$766
$800
$1,064
$1,083
($723)
$452
($400)
($250)
$787
$4,224
$1,714
$3,009
$2,594
$2,710
$3,790
$6,864
$3,822
$5,151
$5,173
$5,258
$6,353
$12,735
$9,650
$10,199
$10,985
$11,849
$12,142
Change
-50. 2X
-23. 2X
-33. 9X
-30. 9X
-8.2X
-166. BX
-58. 2X
-136.9X
-123. IX
-27. 3X
-59. 4X
-28.8X
-38. 6X
-35. 8X
-10. 3X
-44. 3X
-25. OX
-24. 6X
-23. 4X
-7.4X
-24. 2X
-19. 9X
-13. 7X
-7. OX
-4.7X
Years of
Production
Data
7
6
7
7
6
7
9
6
7
7
7
7
9
8
8
8
8
9
10
9
9
9
9
9
9
8
8
9
8
8
X Change
-14. 3X
O.OX
O.OX
-14. 3X
O.OX
-33. 3X
-22.2%
-22.2%
-22.2*.
-22. Z%
-11. IX
-11. IX
-11. IX
-11. IX
O.OX
-10. OX
-10. OX
-10. OX
-10. OX
-10. OX
-11. IX
-11. IX
O.OX
-11. IX
-11. IX
Notes: There are no Gulf 40 or Gulf 58 projects within 4 miles of shore.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-10
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
GULF OF MEXICO - continued
Pollution Control Costs
Project
Gulf 24
Gulf 40
Gulf 58
Scenario
Baseline
G-Zero Discharge
G-Filtration
Onshore
H-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Capital
$4,312
S3. IBS
$2,610
$1.079
$426
$5,035
$3.393
$1.471
$502
$6,071
$3.647
$2.130
$596
O&M
$222
$194
$80
$131
$113
$292
$248
$192
$165
$378
$314
$271
$227
Annuali zed
$787
$607
$408
$254
$154
$907
$656
$349
$206
$1,077
$724
$499
$273
PV of Total Production
(Bbls-of-oil equivalent)
Data
4,482,198
4,360,502
4,360,502
4,482,198
4.482,198
4.482,198
7,594,632
7,435,738
7,435.738
7,594.632
7,594,632
11,473,877
11.473,877
11,473,877
11,473,877
11.473,877
X Change
-2.7%
-2.7X
O.OX
O.OX
O.OX
-2. IX
-2. IX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$10.50
$12.28
$11.81
$11.59
$11.05
$10.78
$10.14
$11.37
$10.96
$10.59
$10.36
$9.89
$10.96
$10.57
$10.32
$10.07
X Change
16. 9X
12. 4X
10. 3X
5.2X
2.6X
12. IX
8. IX
4.5X
2. IX
10. 8X
6.8X
4.4X
1.9X
Production Cost
per BOE
Data
$4.96
$6.05
$5.75
$5.66
$5.39
$5.22
$4.41
$5.17
$4.91
$4.78
$4.63
$4.03
$4.79
$4.54
$4.38
$4.22
X Change
22. IX
16. OX
14. 2X
8.8X
5.3X
17.3X
. 11. 4X
8.5X
5. OX
19. OX
12. 7X
8.8X
4. 8X
Net Present Value
($1000)
Data
$24.605
$20,510
$21,443
$22,358
$23,242
$23,795
$44,451
$39.444
$40,826
$42,480
$43,312
$70,044
$63,863
$65.920
$67,225
$68,540
X Change
-16.6X
-12. 9X
-9.1X
-5.5X
-3.3X
-11.3%
-8.2X
-4.4X
-2.6X
-8.8%
-5.9%
-4.0%
-2.1%
Years of
Production
Data
10
9
9
10
10
10
11
10
10
11
11
11
11
11
11
11
% Change
-10.0%
-10. OX
O.OX
0.0%
0.0%
-9.1%
-9.1%
O.OX
0.0%
O.OX
0.0%
0.0%
Notes: There are no Gulf 40 or Gulf 58 projects within 4 miles of shore.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-11
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
PACIFIC
01
Pollution Control Costs
Project
Pac. 16
Pac. 40
Pac. 70
Scenario
Basel ine
G-Zero Discharge
G-Filtration
Onshore
H-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
N-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Capital
$7.700
$5.255
$4,248
$2,258
$738
$10,701
$5.979
$4,183
$1,007
$16,849
$8.322
$7,991
$7,484
$1.553
OSM
$257
$206
$78
$164
$125
$405
$301
$299
$214
$620
$434
$180
$500
$341
Annual i zed
$1.983
$1.377
$1,045
$650
$267
$2,467
$1,438
$1.077
$373
$3.507
$1,837
$1,569
$1,742
$557
PV of Total Production
(Bbls-of-oil equivalent)
Data
3.925,097
3,925,097
3,925,097
3,925.097
3,925.097
3.925.097
9.984,146
9.984.146
9.984.146
9.984,146
9.984,146
21.698.858
21,698.858
21,698.858
21.698,858
21,698,858
21,698,858
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$7.40
$11.07
$9.92
$9.31
$8.53
$7.81
$7.36
$9.37
$8.50
$8.18
$7.60
$6.75
$8.19
$7.48
$7.33
$7.42
$6.92
X Change
49. 6X
34. OX
25. 7X
15. 2X
5.5X
27. 3X
15. 5X
11. 2X
3.2X
21. 5X
10. 9X
8.7X
10. OX
2.6X
Production Cost
per BOE
Data
$3.38
$5.56
$4.89
$4.53
$4.10
$3.68
$2.75
$3.98
$3.47
$3.29
$2.93
$2.39
$3.30
$2.86
$2.80
$2.84
$2.53
X Change
64. 4X
44. 7X
34. OX
21. U
8.7X
44. 9X
26. 2X
19. 6X
6.8X
38. OX
19. 9X
17. OX
18. 9X
6. OX
Net Present Value
($1000)
Data X
$15,815
$9,767
$11.621
$12.224
$13.848
$15.017
$40,642
$31,903
$35.564
$36,854
$39.355
$101.673
$87.639
$94.353
$93.191
$94.753
$99.512
Change
-38. 2X
-26. 5X
-22. 7X
-12. 4X
-5. OX
-21. 5X
-12. 5X
-9.3X
-3.2X
-13. 8X
-7.2X
-8.3X
-6.8X
-2. IX
Years of
Production
Data
4
4
4
4
4
4
5
5
5
5
5
6
6
6
6
6
6
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Notes: G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-12
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - GAS PLATFORMS
GULF OF MEXICO
--J
I
Project
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Scenario
Baseline
G-Zero Discharge
G-Filtratioo
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Pollution
Capital
$544
$132
$419
$408
$37
$1.672
$174
$667
$1.494
$48
$2.175
$529
$1.675
$1,634
$149
$2.231
$563
$1,699
$1,654
$164
PV of Total Production
Control Costs (Bbls-of-oil equivalent)
O&M
$21
$10
$12
$20
$9
$78
$34
$39
$77
$34
$83
$39
$45
$79
$36
$86
$41
$48
$80
$37
Annual i zed
$105
$30
$77
$83
$14
$334
$55
$132
$305
$36
$393
$106
$270
$294
$51
$382
$113
$276
$298
$55
Data
476,918
476,918
476.918
476.918
476,918
476,918
370,486
340,656
357,349
357,349
340,656
357,349
,383,149
.334,101
,383,149
,383.149
,383.149
.383,149
.980.296
,926,528
,926,528
.926,528
,926,528
,926,528
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
-8. IX
-3.5X
-3.5X
-8. IX
-3.5X
-3.5X
O.OX
O.OX
O.OX
O.OX
-2.7X
-2.7X
-2.7X
-2.7X
-2.7X
4.445.835
$1.155
$632
$1,593
$507
$193
$61
$49
$59
$49
$41
$212 4,445,835
$130 4,445,835
$270 4.445,835
$112 4.445,835
$62 4.445.835
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$8.23
$10.36
$8.79
$9.84
$9.86
$8.43
$7.78
$16.86
$8.88
$11.31
$15.94
$8.26
$7.61
$10.56
$8.38
$9.83
$9.88
$7.90
$7.59
$9.68
$8.09
$9.12
$9.15
$7.73
$7.70
$8.20
$7.99
$8.37
$7.94
$7.81
X Change
25. 9X
6.7X
19. 5X
19. 8X
2.4X
116. 7X
14. IX
45. 4X
104. 9X
6.2X
38.8X
10. 2X
29. 2X
29. 9X
3.9X
27. 6X
6.6X
20. 2X
20. 6X
1.8X
6.6%
3.8X
8.7X
3.1X
1.5X
Production Cost
per BOE
Data
$4.06
$5.44
$4.45
$5.07
$5.14
$4.24
$3.37
$9.15
$4.25
$5.72
$8.61
$3.89
$3.11
$4.96
$3.67
$4.53
$4.65
$3.38
$3.08
$4.39
$3.38
$3.99
$4.07
$3.16
$3.25
$3.59
$3.46
$3.69
$3.43
$3.35
X Change
33. 8X
9.5X
24. 8X
26.4X
4.4X
171. 5X
26. 2X
69. 6X
155. 5X
15. 4X
59. 3X
17. 9X
45. 5X
49. 4X
8.7X
42. 5X
9.7X
29. 6X
32. 2X
2.5X
10. 6X
6.5X
13. 6X
5.6X
3.1X
Net Present Value
($1000)
Data X
$1,194
$727
$1,064
$851
$830
$1,136
$1,097
($397)
$839
$462
($265)
$933
$4,330
$2.410
$3.786
$2.929
$2,819
$4.074
$6,237
$4,263
$5,658
$4,805
$4,706
$5.965
$13,520
$12,431
$12.859
$12,123
$12,949
$13,211
Change
-39. IX
-10. 9X
-28.8X
-30. 5X
-4.9X
-136. 2X
-23. 5X
-57. 9X
-124. 1X
-15. OX
-44. 3X
-12. 6X
-32. 4X
-34. 9X
-5.9X
-31. 7X
-9.3X
-23. OX
-24.6%
-4.4X
-8.0%
-4.9%
-10.3%
-4.2%
-2.3%
Years of
Production
Data
7
7
7
7
7
7
9
7
8
8
7
8
9
8
9
9
9
9
10
9
9
9
9
9
9
9
9
9
9
9
% Change
0.0%
O.OX
0.0%
0.0%
0.0%
-22.2%
-11.1%
-11.1%
-22.2%
-11.1%
-11.1%
0.0%
0.0%
0.0%
0.0%
-10.0%
-10.0%
-10.0%
-10.0%
-in 0%
0.0%
0.0%
0.0%
0.0%
0.0%
Notes: There are no Gulf 40 or Gulf 58 projects within 4 miles of shore.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-13
BAT POLLUTION CONTROL OPTIONS FOR PRODI
MODEL PROJECT IMPACTS - GAS PLATFORMS
GULF OF MEXICO (continued) AND PACIFIC REGIONS
PV of Total Production
Pollution Control Costs
Project
Gulf 24
Pac. 16
Scenario
Basel ine
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Capital
$1,423
$844
$1,660
$565
$236
$2,100
$1,319
$758
$375
DIM
$69
$56
$66
$53
$44
$71
$57
$54
$45
Annual i zed
$245
$158
$273
$120
$69
$432
$281
$179
$104
(Bbls-of-oil
Data
6,854,869
6,854,869
6,854,869
6,854,869
6,854,869
6,854,869
8,880,736
8,490,674
8,490.674
8,490.674
8,490,674
equivalent)
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
-4.4X
-4.4X
-4.4X
-4.4X
Corporate Cost
per BOE
Data
$6.99
$7.40
$7.24
$7.45
$7.17
$7.08
$4.84
$5.19
$5.02
$4.90
$4.82
X Change
5.8X
3.6X
6.7X
2.6X
1.3X
7.2X
3.8X
1.3X
-0.3X
Production Cost
per BOE
Data
$3.24
$3.52
$3.42
$3.55
$3.38
$3.32
$2.35
S2.47
$2.37
$2.30
$2.25
X Change
8.5X
5.5X
9.5X
4.2X
2.4X
5. OX
0.8X
-2. IX
-4.2X
Net Present Value
($1000)
Data
$25.653
$24,315
$24,795
$24,156
$25,008
$25.285
$21.602
$19.862
$20.467
$20.880
$21.182
Years of
Production
X Change
-5.2X
-3.3X
-5.8X
-2.5X
-1.4X
-8.1X
-5.3X
-3.3X
-1.9X
Data
10
10
10
10
10
10
7
6
6
6
6
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
-14. 3X
-14. 3X
-14. 3X
-14. 3X
-J
I
Notes: There are no gas-only Gulf 40 or Gulf 58 projects at present.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-14
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL-ONLY PLATFORMS
GULF OF MEXICO
Pollution Control Costs
Project
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Scenario
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Capital
$664
$278
$459
$384
$63
$2.016
$577
$1,708
$1.425
$170
$2,769
$1.223
$1,845
$1.545
$261
$3,340
$1,772
$1.888
$1,587
$297
$3,421
$2.764
$1,967
$712
$362
O&M
$29
$18
$17
$24
$14
$99
$57
$67
$83
$45
$123
$77
$71
$97
$59
$141
$95
$73
$105
$67
$140
$121
$78
$88
$78
Annual! zed
$142
$64
$96
$88
$23
$440
$141
$359
$321
$65
$515
$247
$334
$312
$89
$615
$326
$324
$310
$98
$626
$513
$358
$181
$120
PV of Total Production
(Bbls-of-oil equivalent)
Data
248,611
248,611
248,611
248,611
248.611
248,611
200.293
179,049
190,936
179,049
179,049
190,936
764,960
737,834
737,834
737,834
737,834
737,834
1,146.599
1,105.939
1,146,599
1,146,599
1,146,599
1.146.599
2,322.310
2.322,310
2,322,310
2,322,310
2,322,310
2.322.310
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
-10. 6X
-4.7X
-10.6X
-10. 6X
-4.7X
-3.5X
-3.5X
-3.5X
-3.5X
-3.5X
-3.5X
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$13.64
$18.67
$15.81
$17.09
$16.63
$14.26
$12.85
$33.88
$18.92
$30.32
$27.83
$15.02
$12.78
$19.72
$15.87
$17.29
$16.72
$13.52
$12.34
$17.88
$15.35
$15.45
$15.11
$13.03
$12.85
$15.61
$15.10
$14.43
$13.52
$13.24
X Change
36. 9X
16. OX
25. 3X
22. OX
4.5X
163. 6X
47. 2X
135. 9X
116. 5X
16.8%
54. 2X
24. 1X
35. 2X
30. 8X
5.8X
44. 9X
24. 4X
25. 2X
22. 4X
5.6X
21 .6X
17. 5X
12.4%
5.2X
3.1X
Production Cost
per BOE
Data X
$6.92
$10.13
$8.37
$9.09
$8.90
$7.44
$5.73
$18.98
$10.02
$16.42
$15.25
$7.57
$5.63
$10.08
$7.62
$8.42
$8.22
$6.18
$4.96
$8.48
$7.02
$7.01
$6.92
$5.58
$5.72
$7.54
$7.21
$6.76
$6.25
$6.07
Change
46. 4X
20. 9X
31 .4X
28.6%
7.4X
230.9%
74. 7X
186.4%
166. OX
32. OX
79. OX
35.4%
49.6%
46. OX
9.8X
71. 1X
41.6%
41.3%
39. 5X
12. 5X
31.8%
26. OX
18. 2X
9.2X
6. IX
Net Present Value
($1000)
Data X
$970
$403
$716
$586
$622
$882
$939
($848)
$318
($528)
($372)
$652
$3,638
$1,163
$2,458
$2,030
/ $2.147
$3,224
$5,960
$2,960
$4.285
$4.288
$4.376
$5,470
$10,903
$7.893
$8,440
$9,183
$10,051
$10.343
Change
-58.4%
-26. 2X
-39. 6X
-35. 9X
-9.1X
-190. 4X
-66. 1X
-156. 2X
-139. 7X
-30. 5X
-68. OX
-32. 4X
-44. 2X
-41. OX
-11. 4X
-50.3%
-28. IX
-28. OX
-26. 6X
-8.2X
-27.6%
-22. 6X
-15. 8X
-7.8X
-5. IX
Years of
Production
Data
6
6
6
6
6
6
8
6
7
6
6
7
9
8
8
8
8
8
9
8
9
9
9
9
8
8
8
8
8
8
X Change
0.0%
O.OX
O.OX
O.OX
O.OX
-25.0%
-12. 5X
-25.0%
-25.0%
-12.5%
-11. IX
-11.1%
-11. IX
-11. IX
-11. IX
-11. IX
O.OX
0.0%
0.0%
O.OX
0.0%
0.0%
O.OX
O.OX
O.OX
Notes: There are no Gulf 40 or Gulf 58 projects within 4 miles of shore.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-15
BAT POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL-ONLY PLATFORMS
GULF OF MEXICO - continued
vo
Pollution Control Costs
Project
Gulf 24
Gulf 40
Gulf 58
Scenario
Baseline
G-Zero Discharge
G-Filtration
Onshore
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G- Filtration
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Capital
$4.302
S3. 181
$2.596
$1.076
(425
$5,026
$3.389
$1.468
$500
$5,819
$3,642
$1,886
$594
O&N
$220
$192
$80
$129
$111
$292
$248
$192
$165
$365
$309
$259
$223
Armuali zed
$783
$604
$427
$260
$155
$906
$656
$358
$208
$1.073
$719
$459
$268
PV of Total Production
(Bbls-of-oil equivalent)
Data
3,644,365
3,644,365
3,644.365
3.644.365
3,644,365
3.644,365
6,212.018
6.212.018
6,212,018
6.212,018
6,212.018
9,582,253
9,381,774
9,582.253
9,582,253
9,582,253
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
-2. IX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$11.68
$13.96
$13.40
$13.00
$12.33
$12.00
$11.27
S12.88
$12.39
$11.82
$11.53
$11.11
$12.23
$11.92
$11.58
$11.33
X Change
19. 6X
14. 8X
11. 3X
5.6X
2.8X
14. 2X
9.9X
4.8X
2.3X
10. OX
7.3X
4.2X
1.9X
Production Cost
per BOE
Data
$5.68
$7.23
$6.88
$6.52
$6.19
$5.98
$5.06
$6.19
$5.88
$5.51
$5.32
$4.82
$5.51
$5.43
$5.21
$5.05
X Change
27. 4X
21. 2X
15. OX
9. IX
5.4X
22.2%.
16. IX
8.8X
5. IX
14. 3X
12. 7X
8.1X
4.7X
Net Present Value
($1000)
Data
$21,365
$17,341
$18,268
$19,155
$20,052
$20,599
$38,926
$33,990
$35,369
$37,012
$37.834
$61,581
$55.650
$57.483
$58,994
$60,100
X Change
-18.8X
-14. 5X
-10. 3X
-6. IX
-3.6X
-12. 7X
-9.1X
-4.9X
-2.8X
-9.6X
-6.7X
-4.2X
-2.4X
Years of
Production
Data
9
9
9
9
9
9
10
10
10
10
10
11
10
11
11
11
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
-9. IX
O.OX
O.OX
O.OX
Notes: There are no Gulf 40 or Gulf 58 projects within 4 miles of shore.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
costs are used in the evaluation). For all other structures, cost increases
are less than $2/BOE.
Net Present Value: For the Gulf Ib oil and gas project, the NPV changes
from positive to negative for the Zero Discharge options while it remains
positive for the filtration options. All other projects show no change in the
sign of the baseline net present value (i.e., all that begin positive remain
positive and all that begin negative remain negative). Decreases of 2 to 59
percent are seen for the Zero Discharge option with the higher increases
associated with projects having small baseline net present values. Section
Nine examines the potential loss of production from all structures, including
the Gulf Ib.
73 PRODUCED WATER - NSPS
The incremental costs of additional pollution controls on produced water
from future projects are applied at the beginning of each economic model (see
Section Five). Future projects are projected for all four regions -- Gulf of
Mexico, Pacific, Atlantic, and Alaska. Section Four discusses the methodology
used to estimate the number of projects that go into operation during 1986 -
2000.
As described in Section 7.2 for BAT produced water, there are two sets of
costs for filtration and injection. They are differentiated by whether or not
an addition to the platform is deemed necessary for the additional pollution
control equipment and by the multiplier used to account for transportation
costs and other factors (see Section Six). The impacts for the various
options are summarized in Tables 7-16 through 7-21.
73.1 Financial Summary Statistics
PV of Total Production: Increased annual operation and maintenance costs
(O&M) can lead to early abandonment of a project. Only 5 out of 24 projects
show early closures, and these closures occur regardless of the disposal
option. This implies that the project brings in just enough revenue in the
last year of operation to cover operating costs, i.e., any additional annual
costs will cause the project to close a year earlier. The impacts of early
project closure are investigated in Section Nine.
7-20
-------
TABLE 7-._
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
GULF OF MEXICO
Pollution Control Costs
Project Scenario
Gulf 1b Baseline
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
Gulf 4 Baseline
G-Zero Discharge
Onshore
G-Filtration
H-Zero Discharge
M-Filtration
71 Gulf 6 Baseline
to G-Zero Discharge
*"* Onshore
G-Fi Itration
H-Zero Discharge
M-Filtration
Gulf 12 Baseline
G-Zero Discharge
Onshore
G-Fi Itration
M-Zero Discharge
M-Filtration
Gulf 24 Baseline
G-Zero Discharge
Onshore
G-Fi Itration
M-Zero Discharge
M-Filtration
Capital
SI. 928
$1,711
$485
$1,462
$205
$2.227
$1,848
$707
$1,571
$299
$2,339
$1.892
$805
$1,615
$341
$1.598
$1.976
$990
$746
$419
$2,225
$2,632
$1.131
$1,112
$474
out
$97
$85
$55
$84
$47
$118
$94
$72
$99
$61
$128
$94
$81
$108
$69
$115
$94
$97
$93
$83
$163
$103
$136
$136
$118
Annual i zed
$278
$245
$96
$220
$62
$313
$256
$130
$235
$83
$328
$257
$147
$245
$94
$242
$260
$171
$145
$107
$334
S320
$213
$212
$140
PV of Total Production
(Bbls-of-oil equivalent)
Data
,159,301
.148.742
.148.742
.153.130
.148.742
1.153.130
4,301.632
4,293,709
4,293,709
4,293.709
4,293.709
4.293.709
6.452.448
6,452.448
6,452,448
6,452,448
6.452.448
6.452.448
9.611.069
9,611.069
9,611,069
9.611.069
9.611.069
9.611,069
17.470.722
17.470,722
17.470,722
17,470,722
17,470.722
17.470,722
X Change
-0.9X
-0.9X
-0.5X
-0.9X
-0.5X
-0.2X
-0.2X
-0.2X
-0.2X
-0.2X
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$21.16
$24.58
$24.19
$22.19
$23.81
$21.72
$18.09
$19.08
$18.90
$18.45
$18.81
$18.28
$17.71
$18.41
$18.27
$17.99
$18.22
$17.86
$18.23
$18.56
$18.61
$18.45
$18.41
$18.35
$16.26
$16.52
$16.53
$16.41
$16.40
$16.34
X Change
16. 2X
14. 3X
4.8X
12. 5X
2.7X
5.5X
4.5X
2. OX
4. OX
1.1X
4. OX
3.2X
1.6X
2.9X
0.9X
1.8X
2. IX
1.2X
1.0X
0.6X
1.6X
1.7X
0.9X
0.9X
0.5X
Production Cost
per BOE
Data
$13.71
$16.17
$15.88
$14.57
$15.66
$14.27
$8.98
$9.70
$9.56
$9.27
$9.52
$9.16
$8.40
$8.92
$8.80
$8.63
$8.78
$8.55
$8.95
S9.20
$9.22
$9.13
$9.10
$9.06
$8.13
$8.33
$8.32
$8.26
$8.26
$8.22
X Change
17. 9X
15. 8X
6.3X
14. 2X
4.1X
8. OX
6.5X
3.2X
6. OX
2. OX
6.2X
4.8X
2.7X
4.6X
1.7X
2.8X
3. OX
2. OX
1.7X
1.3X
2.5X
2.4X
1.6X
1.6X
1.1X
Net Present Value
($1000)
Data X
$654
($1.346)
($1.114)
($41)
($931)
$210
$15.649
$13.439
$13,836
$14.743
$13.993
$15.083
$25.909
$23,547
$24,053
$24.867
$24,157
$25,254
$33.610
$31,883
$31,735
$32,401
$32,590
$32.870
$95.532
$93,073
$93,137
$93.983
$93,996
$94,536
Change
-305.8X
-270.4X
-106.3X
-242.3X
-67. 8X
-14. 1X
-11. 6X
-5.8X
-10. 6X
-3.6X
-9.1X
-7.2X
-4. OX
-6.8X
-2.5X
-5. IX
-5.6X
-3.6X
-3. OX
-2.2X
-2.6X
-2.5X
-1.6X
-1.6X
-1.0X
Internal Rate
of Return
Data X
9.5X
5.1X
5.6X
7.9X
6. OX
8.5X
21. 4X
19. OX
19. 4X
20. 5X
19. 6X
20. 9X
23.1%
21. 4X
21. 7X
22. AX
21. 8X
22.7%
20. 1X
19. 3X
19. 2X
19. 6X
19. 7X
19. 8X
27. 3X
26. 6X
26. 6X
26. 9X
26. 9X
27. 1X
Change
-45. 8X
-40. 8X
-16. 8X
-37. OX
-10. 7X
-11.1%
-9.3X
-4.3%
-8.3%
-2.5%
-7.6%
-6.0%
-3.0%
-5.4X
-1.5X
-3.8%
-4.3%
-2.5%
-2.1%
-1.4%
-2.5%
-2. A
-1.4%
-1.4%
-0.8%
Years of
Production
Data
20
17
17
18
17
18
21
20
20
20
20
20
21
21
21
21
21
21
19
19
19
19
19
19
21
21
21
21
21
21
X Change
-15.0%
-15. OX
-10. OX
-15. OX
-10.0%
-4.8%
-4.8%
-4.8%
-4.8%
-4.8%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Notes: G refers to granular filter technology costs for injection and filtration.
H refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-17
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
GULF OF MEXICO - continued
PV of Total Production
Pollution Control Costs
Project
Gulf 40
Gulf 58
-j
1
K)
to
Scenario
Baseline
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Capital
(2,935
$3,176
(1,335
SI, 510
(560
(3,960
(1,587
(2,177
(666
O&M
(235
(125
(192
(199
(171
(324
(260
(280
(237
Annual i zed
(450
(380
(276
(297
(191
(606
(352
(419
(255
(Bbls-of-oil
Data
29,889,385
29,889,385
29,889,385
29,889,385
29.889,385
29,889,385
35,194,925
35,194,925
35,194,925
35,194,925
35,194,925
equivalent)
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
(16.04
(16.25
(16.24
(16.15
(16.16
(16.11
(16.53
(16.72
(16.72
(16.65
(16.59
X Change
1.3X
1.2X
0.7X
0.8X
0.4X
1.2X
1.2X
0.7X
0.4X
Production Cost
per BOE
Data
(7.74
(7.91
(7.88
(7.84
(7.85
(7.81
(7.90
(8.05
(7.99
(8.01
(7.96
X Change
2. IX
1.8X
1.3X
1.4X
0.9X
1.9X
1.1X
1.3X
0.8X
Net Present Value
((1000)
Data
(169,856
(166,454
(166.931
(167,807
(167,649
(168,464
(182,742
(178.986
(180,610
(180,187
(181,235
Internal Rate
of Return
X Change
-2. OX
-1.7X
-1.2X
-1.3X
-0.8X
-2. IX
-1.2X
-1.4X
-0.8X
Data X
25. 2X
24. 8X
24. 8X
25. OX
25. OX
25. IX
20. 7X
20. 4X
20. 6X
20.5X
20. 6X
Change
-1.7X
-1.7X
-0.8X
-0.9X
-0.4X
-1.4X
-0.6X
-0.8X
-0.3X
Years of
Production
Data
23
23
23
23
23
23
25
25
25
25
25
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
0.0%
O.OX
O.OX
O.OX
Notes: No 58-well structures are projected within 4 miles of shore in the Gulf of Mexico.
G refers to granular filter technology costs for injection and filtration.
N refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-18
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS
ATLANTIC AND PACIFIC
CO
Pollution Control Costs
Project
Atl. 24
Pac. 16
Pac. 40
Pac. 70
Scenario
Basel ine
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
H-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Baseline
G-Zero Discharge
G-Fi Itration
M-Zero Discharge
H-Fi Itration
Capital
$6,297
$2,303
$3.780
$966
$4,365
$1,973
$2.320
$826
$7.376
$2.707
$4,283
$1.137
$12.668
$3,782
$7,658
$1,592
OftM
$316
$221
$277
$199
$203
$152
$172
$133
$359
$255
$317
$232
$585
$398
$527
$368
Armualized
$824
$388
$567
$251
$718
$370
$430
$207
$1,181
$527
$768
$316
$1,881
$736
$1,273
$468
PV of Total Production
(Bbls-of-oil equivalent)
Data
25.801,198
25.801,198
25,801,198
25.801,198
25,801.198
11.449,953
11,449,953
11,449,953
11,449,953
11,449,953
20,252,704
20,252,704
20,252,704
20,252,704
20.252,704
29,277,100
29,277,100
29,277,100
29,277.100
29.277,100
X Change
O.OX
O.OX
-O.OX
-O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
-O.OX
-O.OX
Corporate Cost
per BOE
Data
$19.05
$19.39
$19.19
$19.27
$19.13
$12.96
$13.55
$13.24
$13.29
$13.10
$12.89
$13.34
$13.07
$13.16
$12.98
$12.38
$12.85
$12.54
$12.68
$12.47
X Change
1.8X
0.8X
1.2X
0.4X
4.5X
2.2X
2.5X
1.1X
3.5X
1.4X
2. IX
0.7X
3. 8X
1.3X
2.4X
0.7X
Production Cost
per BOE
Data
$16.52
$16.76
$16.63
$16.68
$16.59
$7.19
$7.58
$7.39
$7.42
$7.30
$6.05
$6.35
$6.18
$6.24
$6.13
$5.94
$6.24
$6.06
$6.14
$6.01
X Change
1.5X
0.7X
1.0X
0.4X
5.4X
2. 8X
3.2X
1.6X
4.9%
2.2X
3.2X
1.3X
5. IX
2. OX
3.4X
1.2X
Net Present Value
($1000)
Data X
($66.121)
($70.702)
($68.234)
($69.234)
($67.450)
$45.337
$42.113
$43,698
$43,427
$44.440
$81,686
$77.199
$79.721
$78.802
$80.539
$132.919
$126,176
$130,351
$128,410
$131,338
Change
-6.9X
-3.2X
-4.7X
-2. OX
-7.1X
-3.6X
-4.2X
-2. OX
-5.5X
-2.4X
-3.5X
-1.4X
-5. IX
-1.9X
-3.4X
-1.2X
Internal Rate
of Return
Data X
2.6X
2.2X
2.4X
2.3X
2.5X
39. 4X
35. 9X
37. 7X
37. 4X
38. 5X
33. 8X
31.6%
32. 9X
32. 5X
33. 4X
29. 5X
27. 8X
28. 9X
28. 4X
29. 2X
Change
-14. 2X
-7.5X
-10. 3X
-5.4X
-8.9X
-4.4X
-5.1X
-2.2X
-6.4%
-2.5X
-3.9X
-1.2X
-5.8%
-2.0%
-3.7X
-1.0X
Years of
Production
Data
21
21
21
21
21
9
9
9
9
9
10
10
10
10
10
12
12
12
12
12
X Cl enge
O.OX
O.OX
O.OX
O.OX
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Notes: G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-19
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - OIL AND GAS PLATFORMS AND OIL-ONLY PLATFORMS
ALASKA
Pollution Control Costs
PROJECT SCENARIO
Cook Inlet Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Beaufort: Baseline
gravel- G-Zero Discharge
island G-Filtration
M-Zero Discharge
M-Filtration
K> Beaufort: Baseline
* platform G-Zero Discharge
G-Filtration
H-Zero Discharge
M-Filtration
Navarin Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Norton Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Capital
$13,462
$3,907
$8,848
$1,643
$36.655
$10.497
$20.948
$4,426
$36,300
$10,389
$20,823
$4,380
$36,656
$10,497
$20,948
$4,426
$22,514
$8,193
$11,725
$3,449
O&M
$596
$369
$541
$341
$655
$653
$623
$610
$646
$630
$615
$588
$655
$653
$623
$610
$681
$460
$617
$428
Armualized
$1.593
$628
$1.173
$421
$3.347
$1.320
$2.106
$816
$3.351
$1,303
$2.111
$799
$3,347
$1,320
$2,106
$816
$2.322
$1.008
$1,411
$605
PV of Total Production
(Bbls-of-oil equivalent)
Data
61,707,003
61.707.003
61,707,003
61.707.003
61,707,003
73,172,498
73,172.498
73,172,498
73,172.498
73,172,498
67,592,103
67,592,103
67,592,103
67,592,103
67,592.103
73,172,498
73,172.498
73,172,498
73,172,498
73.172.498
61.740,561
61,635,409
61,635,409
61,635,409
61,635,409
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
-O.OX
-O.OX
O.OX
O.OX
-O.OX
-O.OX
O.OX
O.OX
-O.OX
-O.OX
-0.2X
-0.2X
-0.2X
-0.2X
Corporate Cost
Per BOE
Data
$13.22
$13.55
$13.33
$13.44
$13.28
$12.19
$12.68
$12.35
$12.48
$12.27
$11.50
$11.99
$11.66
$11.79
$11.58
$12.41
$12.90
$12.57
$12.70
$12.49
$11.22
$11.65
$11.39
$11.46
$11.30
X Change
2.5X
0.8X
1.7X
0.4X
4. OX
1.3X
2.4X
0.7X
4.3X
1.4X
2.5X
0.7X
3.9X
1.3X
2.3X
0.6X
3.9X
1.5X
2. IX
0.7X
Production Cost
Per BOE
Data
$4.18
$4.42
$4.28
$4.36
$4.25
$5.53
$5.84
$5.65
$5.72
$5.60
$6.33
$6.64
$6.45
$6.52
$6.40
$7.47
$7.77
$7.59
$7.66
$7.54
$6.09
$6.36
$6.20
$6.25
$6.15
X Change
5.7X
2.3X
4.2X
1.6X
5.5X
2.2X
3.5X
1.3X
4.8X
1.9X
3. IX
1.2X
4. IX
1.6X
2.5X
1.0X
4.5X
1.8X
2.6X
1.0X
Net Present Value
($1000)
Data
$357,708
$347.200
$353.666
S350.045
$355.069
$191.157
$174.043
$184.655
$180.520
$187.263
$233,074
$207,373
$217,189
$213.302
$219.583
$175.208
$158.093
$168.706
$164.571
$171,315
$220,856
$207,676
$215.239
$212,979
$217,585
X Change
-2.9X
-1.1X
-2. IX
-0.7X
-9. OX
-3.4X
-5.6X
-2. OX
-11. OX
-6.8X
-8.5X
-5.8X
-9.8X
-3.7X
-6.1X
-2.2X
-6. OX
-2.5X
-3.6X
-1.5X
Internal Rate
Of Return
Data X
39. OX
37. OX
38. 4X
37. 7X
38.7X
18. AX
17. 1X
18. OX
17. 6X
18. 2X
20. 5X
19. 2X
20. IX
19. 7X
20. 3X
15. 2X
14. 3X
14. 8X
14. 6X
15. OX
2A.U
22.6%
23. 5X
23. 3X
23. 8X
Change
-5.1X
-1.6X
-3.5X
-0.8X
-7. OX
-2.3X
-4.2X
-1.1X
-6.4X
-2. IX
-3.9X
-1.1X
-6.2X
-2.3X
-3.9X
-1.4X
-6.2X
-2.5X
-3.5X
-1.2X
Years C
Product) t/ii
Data
30
30
30
30
30
30
30
30
30
30
28
28
28
28
28
30
30
30
30
30
27
26
26
26
26
X Change
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-3.7
-3.7
-3.7
-3.7
Notes: Cook Inlet project produces both oil and gas; all other projects are assumed to produce only oil.
G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-20
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - GAS-ONLY PLATFORMS
GULF OF MEXICO
Pollution Control Costs
Project Scenario
Gulf 1b Baseline
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtratlon
Gulf 4 Baseline
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
Gulf 6 Baseline
' G-Zero Discharge
jjj Onshore
m G-Filtration
M-Zero Discharge
M-Filtration
Gulf 12 Baseline
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
Gulf 24 Baseline
G-Zero Discharge
Onshore
G-Filtration
M-Zero Discharge
M-Filtration
Capital
$1.644
$667
$146
$1,508
$62
$2,089
$1,675
$443
$1,672
$188
$2,139
$1.699
$471
$1,690
$199
$1,051
$1,748
$527
$537
$223
$1.195
$1,815
$635
$588
$269
OtM
$77
$41
$34
$77
$34
$82
$49
$38
$79
$36
$85
$54
$40
$81
$37
$57
$68
$46
$49
$41
$66
$83
$53
$54
$45
Annual! zed
$228
$100
$45
$215
$36
$268
$199
$75
$226
$50
$272
$204
$79
$227
$52
$144
$217
$86
$90
$54
$151
$217
$94
$91
$57
PV of Total Production
(Bbls-of-oil equivalent)
Data
1.534,266
1.524,970
1,530,172
1,530,172
1,524,970
1,530,172
5,694,403
5,682,468
5.682,468
5,682,468
5,682,468
5,682.468
8.541,605
8,541,605
8.541,605
8,541.605
8,541,605
8,541,605
12.713,538
12,713,538
12,713,538
12.713,538
12,713,538
12,713.538
21,412,488
21.412.488
21,412,488
21.412.488
21,412,488
21,412,488
X Change
-0.6X
-0.3X
-0.3X
-0.6X
-0.3X
-0.2X
-0.2X
-0.2X
-0.2X
-0.2X
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$15.73
$17.91
$16.65
$16.03
$17.75
$15.94
$13.40
$14.08
$13.93
$13.57
$13.96
$13.49
$13.12
$13.58
$13.48
$13.24
$13.49
$13.18
$13.52
S13.67
$13.77
$13.60
$13.61
$13.56
$12.29
$12.40
$12.45
$12.35
$12.35
$12.32
X Change
13.9X
5.8X
1.9X
12.9X
1.3X
5. IX
3.9X
1.2X
4.2X
0.7X
3.5X
2.7X
0.9X
2.9X
0.5X
1.1X
1.8X
0.6X
0.6X
0.3X
0.9X
1.3X
0.5X
0.5X
0.3X
Production Cost
per BOE
Data
$11.27
$12.83
$11.96
$11.58
$12.74
$11.52
$7.69
$8.16
$8.04
$7.82
$8.08
$7.77
$7.25
$7.58
$7.49
$7.35
$7.52
$7.31
$7.68
$7.79
$7.85
$7.75
$7.75
$7.72
$7.16
$7.23
$7.26
$7.20
$7.20
$7.19
X Change
13. 9X
6.2X
2.8X
13.0X
2.3X
6.1X
4.5X
1.7X
5.1X
1.1X
4.5X
3.4X
1.3X
3.8X
0.9X
1.5X
2.2X
0.9X
0.9X
0.6X
1.0X
1.5X
0.6X
0.6X
0.4X
Net Present Value
($1000)
Data X
($1.706)
($3,382)
($2,447)
($2,028)
($3,279)
($1,964)
$6,885
$4,980
$5,461
$6,360
$5,280
$6,543
$12,763
$10,795
$11,282
$12,199
$11,126
$12,400
$13,767
$12,731
$12,193
$13,155
$13,130
$13,391
$49,389
$48,238
$47.733
$48.685
$48.710
$48.970
Change
-98.3X
-43. 4X
-18. 9X
-92. 2X
-15. IX
-27. 7X
-20. 7X
-7.6X
-23. 3X
-5. OX
-15. 4X
-11. 6X
-4.4X
-12. 8X
-2.8X
-7.5X
-11. 4X
-4.4X
-4.6X
-2.7X
-2.3X
-3.4X
-1.4X
-1.4X
-0.8X
Internal Rate
of Return
Data X
4.7X
1.7X
3.3X
4. OX
1.9X
4. IX
12. 8X
11. 3X
11. 7X
12. AX
11. 6X
12. 5X
14. OX
13. OX
13. 2X
13. 7X
13. 1X
13. 8X
12. 1X
11. 8X
11. 6X
11. 9X
11. 9X
12. OX
16. 6X
16. 3X
16. 2X
16. AX
16. AX
16. 5X
Change
-63. 8X
-29. 9X
-14. 9X
-60.6X
-12. 6X
-11. 4X
-8.8X
-3.3X
-9.6X
-2. IX
-7.4X
-5.7X
-2. OX
-6. IX
-1.2X
-2.8X
-4.2X
-1.6X
-1.6X
-0.9X
-1.6%
-2.3X
-1.0X
-1.0%
-0.6X
Years of
Production
Data
20
18
19
19
18
19
21
20
20
20
20
20
21
21
21
21
21
21
19
19
19
19
19
19
21
21
21
21
21
21
X Change
-10. OX
-5. OX
-5. OX
-10. OX
-5. OX
-4.8X
-4. 8X
-4.8X
-4.8X
-4.8X
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
0.0%
O.OX
O.OX
O.OX
O.OX
Notes: G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
TABLE 7-21
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - GAS-ONLY PLATFORMS
PACIFIC, ATLANTIC, AND ALASKA REGIONS
Pollution Control Costs
Project Scenario
Pac. 16 Baseline
G-Zero Discharge
G-Filtration
M-Zero Discharge
M-Filtration
Atlan. Baseline
G-Zero Discharge
G-Filtration
H-Zero Discharge
H-Filtration
Cook Baseline
G-Zero Discharge
G-Filtration
I M-Zero Discharge
to H-Filtration
Capital
$1.762
$1.011
$795
$428
$2,013
$1.232
$893
$521
$2.456
$1.540
$1.056
$652
O&M
$67
$54
$55
$46
$74
$59
$59
$50
$54
$44
$48
$39
Annual ized
$244
$152
$129
$83
$52
$41
$42
$35
$246
$162
$126
$86
PV of Total Production
(Bbls-of-oil equivalent)
Data
15.493,937
15,493.937
15.493.937
15,493.937
15,493.937
38.935.162
38,935,162
38,935,162
38.935,162
38,935,162
52,694,332
52.694.332
52,694.332
52.694,332
52.694.332
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$10.08
$10.24
$10.17
$10.15
$10.12
$12.28
$12.28
$12.28
$12.28
$12.28
$8.41
$8.48
$8.46
$8.44
$8.43
X Change
1.6X
0.9X
0.7X
0.4X
O.OX
O.OX
O.OX
O.OX
0.8X
0.6X
0.4X
0.3X
Production Cost
per BOE
Data
$7.03
$7.14
$7.10
$7.09
$7.07
$10.52
$10.53
$10.53
$10.53
$10.53
S2.96
$3.01
$2.99
$2.99
$2.98
X Change
1.6X
1.0X
0.9X
0.6X
0.1X
0.1X
0.1X
0.1X
1.5X
1.1X
0.8X
0.6X
Net Present Value
($1000)
Data X
$10,241
$9.021
$9.488
$9.604
$9.840
($59.921)
($60,203)
($60,145)
($60,147)
($60.112)
$188.211
$186,572
$187,135
$187.385
$187.650
Change
-11. 9X
-7.4X
-6.2X
-3.9X
-0.5X
-0.4X
-0.4X
-0.3X
-0.9X
-0.6X
-0.4X
-0.3X
Internal Rate
of Return
Data X
11. 8X
11. 3X
11. 5X
11. 6X
11. 7X
4. IX
4. IX
4. IX
4.1X
4.1X
31. 6X
31. 1X
31. 3X
31. AX
31. 5X
Change
-3.9X
-2.3X
-1.9X
-1.1X
-0.2X
-0.1X
-0.1X
-0.1X
-1.5%
-0.9X
-0.7X
-0.4X
Years of
Production
Data
13
13
13
13
13
25
25
25
25
25
29
29
29
29
29
X Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
' '%
( X
O.OX
O.OX
Notes: G refers to granular filter technology costs for injection and filtration.
M refers to membrane filter technology costs for injection and filtration.
Source: ERG estimates.
-------
Corporate Cost per BOE: The Gulf Ib assumes that one reinjection well is
required to service one producing well. Under this assumption, the corporate
cost per BOE may increase by 13 to 16 percent or about $2.00/BOE to $3.50/BOE
(depending on whether granular or membrane filter costs are used in the
evaluation). This increase is enough, however, to change the net present
value from positive to negative (see below). The impacts on all other
projects are far less severe, with increases ranging from 1 to 6 percent or
from $0.07/BOE to $1.01/BOE for the Cook Inlet gas-only project to the Gulf 4
oil and gas project.
For the filtration option, the corporate cost per BOE increases by 2 to 5
percent for the Gulf Ib project. All other projects show increases of
0.3 to 2.2 percent.
Production Cost per BOE: Production costs increase by 14 to 18 percent
for the Gulf Ib under the Zero Discharge option. For all other structures,
production cost increases do not exceed 8 percent or $0.72/BOE for the Zero
Discharge option.
Costs for the filtration options raise production costs per BOE by 4 to 6
percent for the Gulf Ib (depending on whether membrane granular filter costs
are used in the evaluation). For all other structures, cost increases do not
exceed 3.5 percent or less than 30 cents per BOE.
Net Present Value: For the Gulf Ib oil and gas project, the NPV changes
from positive to negative for the Zero Discharge options, while it remains
positive for the filtration option using membrane filter costs. All other
projects show no change in the sign of the baseline net present value (i.e.,
all that begin positive remain positive and all that begin negative remain
negative). Decreases of 2 to 28 percent are seen for the Zero Discharge
option, with the greater change occurring in projects with small baseline net
present values. Section Nine examines the potential loss of production from
all structures, including the Gulf Ib.
7-27
-------
7.3.2 Sensitivity Analysis
Two sensitivity cases were examined for for re-injection and filtration:
$15/bbl
$32/bbl
The cases were run for the Gulf Ib and Gulf 12 oil and gas projects (see
Tables 7-22 and 7-23). Granular filter costs were used because they are
higher than membrane filter costs. The change in the price of oil has a
greater impact on the financial summary statistics than do the regulatory
options within a given price scenario.
7.4 COMBINED EFFECTS OF SELECTED REGULATORY OPTIONS
Existing projects, for the most part, will have had their drilling
programs completed by the time any new effluent standards are enacted. The
rare exceptions will be drilling programs on large platforms that were set
before the regulations go into place but will not be completed until after the
regulations are in effect. Existing projects, then, primarily bear BAT
produced water costs. Section 7.2 describes the impacts from these costs on
representative facilities.
New projects will bear the combined costs of increased pollution control
for both drilling and production wastes. In this section, ERG examines the
impacts of the costs for the combinations discussed in Section 6.4 on the Gulf
Ib and Gulf 12 oil and gas projects.
The results are shown in Table 7-24. The first line is the baseline case
without any added regulatory costs of increased pollution control. The
following lines list the financial summary statistics when the respective
combination of NSPS drilling fluids, drill cuttings, and produced water
pollution control options are considered. These data are given for five
regulatory combinations for both the Gulf Ib and Gulf 12 projects. The
combined impacts were calculated by running the models with both the drilling
fluids and drill cutting control costs and the produced water control costs.
Combining the pollution control costs shows that the effects are only additive
(i.e., the combined effects are roughly equal to the sum of the two effects
when analyzed independently).
7-28
-------
TABLE 7-22
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - SENSITIVITY ANALYSIS
GRANULAR FILTER COSTS
GULF OF MEXICO - GULF IB PROJECT - OIL AND GAS PRODUCTION
Sensitivity Regulatory
Analysis Scenario
Baseline Baseline
Zero Discharge
Onshore Shallow
Filtration
$15/bbl Baseline
Zero Discharge
Onshore Shallow
^ Filtration
K> $32/bbl Baseline
*° Zero Discharge
Onshore Shallow
Filtration
PV of Totat
Pollution Control Costs Production (BOE)
Capital
$1,928
$1,711
$485
$1.928
$1.711
$485
$1.928
$1,711
$485
O&M
$97
$85
$55
$97
$85
$55
$97
$85
$55
Annuali zed Data
$278
$245
$96
$289
$255
$98
$266
$235
$94
,159,301
,148,742
,148,742
,153,130
,153,130
,136,083
,136,083
,143,167
,163.124
,159,301
,159.301
,161,441
Change
-0.9X
-0.9%
-0.5%
-1.5%
-1.5%
-0.9%
-0.3%
-0.3%
-0.1%
Corporate Cost
per BOE
Data
$21.16
$24.58
$24.19
$22.19
$17.96
$21.42
$21.03
$19.00
$26.75
$30.15
$29.76
$27.78
Change
16.2%
14.3%
4.8%
19.3%
17.1%
5.8%
12.7%
11.2%
3.8%
Production Cost
per BOE
Data
$13.71
$16.17
$15.88
$14.57
$13.71
$16.20
$15.92
$14.58
$13.73
$16.20
$15.91
$14.61
Change
17.9%
15.8%
6.3%
18.2%
16.1%
6.4%
17.9%
15.8%
6.4%
Net Present Value
($1000)
Data
$654
($1,346)
($1,114)
($41)
($2.804)
($4,770)
($4,543)
($3,481)
$6,704
$4,668
$4,906
$5,989
Change
-305.8%
-270.4%
-106.3%
-270.1%
-262.0%
-224.1%
-30.4%
-26.8%
-10.7%
Internal Rate
of Return
Data Change
9.5%
5.1% -45.8%
5.6% -40.8%
7.9% -16.8%
1.1%
-3.2% -385.0%
-2.7% -341.2%
-0.6% -156.0%
22.3%
17.1% -23.4%
17.6% -20.9%
20.6% -7.7%
Years of
Production
Data
20
17
17
18
18
15
15
16
22
20
20
21
Change
-15. OX
-15.0%
-10. OX
-16. 7X
-16.7%
-11.1%
-9.1%
-9.1%
-4.5%
Note: BOE represents barrels-of-oil-equivalent.
Source: ERG estimates.
-------
TABLE 7-23
NSPS POLLUTION CONTROL OPTIONS FOR PRODUCED WATER
MODEL PROJECT IMPACTS - SENSITIVITY ANALYSIS
GRANULAR FILTER COSTS
GULF OF MEXICO - GULF 12 PROJECT - OIL AND GAS PRODUCTION
Sensitivity Regulatory
Analysis Scenario
Baseline
$15/bbl
$32/bbl
Baseline
Zero Discharge
Onshore Shallow
Filtration
Baseline
Zero Discharge
Onshore Shallow
Filtration
Baseline
Zero Discharge
Onshore Shallow
Filtration
Pollution Control Costs
Capital
$1.598
$1,976
$990
$1,598
$1,976
$990
$1,598
$1,976
$990
O&M
$115
$94
$97
$115
$94
$97
$115
$94
$97
Annual i zed
$242
$260
$171
$248
$267
$174
$238
$255
$169
PV of Total
Production (BOE)
Data
9.611,069
9,611,069
9,611.069
9.611.069
9.539,096
9,539.096
9.539.096
9.539.096
9,671.105
9,655,652
9,655,652
9,655.652
Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
-0.2X
-0.2X
-0.2X
Corporate Cost
per BOE
Data
$18.23
$18.56
$18.61
$18.45
$15.01
$15.34
$15.40
$15.23
$23.85
$24.17
$24.22
$24.06
Change
1.8X
2.1X
1.2X
2.2X
2.6X
1.5X
1.3X
1.6X
0.9X
Production Cost
per BOE
Data
$8.95
$9.20
$9.22
$9.13
$8.92
$9.17
$9.19
$9.09
$9.02
$9.25
$9.27
$9.18
Change
2.8X
3. OX
2.0X
2.8X
3. OX
2.0X
2.6X
2.8X
1.8X
Net Present Value
($1000)
Data
$33,610
$31,883
$31,735
$32,401
$4,942
$3,247
$3.093
$3.759
$83,863
$82,109
$81,966
$82.631
Change
-5. IX
-5.6X
-3.6X
-34.3X
-37.4X
-23.9X
-2.1X
-2.3X
-1.5X
Internal Rate
of Return
Data
20. IX
19.3X
19. 2X
19. 6X
9.9X
9.3X
9.2X
9.5X
35. 6X
34. 6X
34. 5X
35. OX
Change
-3.8X
-4.3X
-2.5X
-6.8X
-7.5X
-4.8X
-2.7X
-3. IX
-1.7X
Years of
Production
Data
19
19
19
19
17
17
17
17
22
21
21
21
Change
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
-4.5X
-4.5X
-4.5X
Note: BOE represents barrels-of-oil-equivalent.
Source: ERG estimates.
-------
TABLE 7-24
NSPS POLLUTION CONTROL OPTIONS FOR DRILLING FLUIDS, DRILL CUTTINGS, AND PRODUCED WATER
IMPACTS OF SELECTED COMBINATIONS OF REGULATORY OPTIONS
GULF OF MEXICO - GULF 1b AND GULF 12 OIL AND GAS PROJECTS
--J
I
ui
Project
Gulf 1b
Gulf 12
Combined Options
Drilling Fluid/
Produced Uater
Baseline
4-Mile Barge/ G-Filter
4-Mile Barge/ M-Filter
4-Mile Barge/ G-Zero Discharge
4-Mile Barge/ M-Zero Discharge
4-Mile Barge/ BPT
Baseline
4-Mile Barge/ G-Filter
4-Mile Barge/ M-Filter
4-Mile Barge/ G-Zero Discharge
4-Mile Barge/ M-Zero Discharge
4-Mile Barge/ BPT
PV of T
Productio
Data
1.159.301
,153.130
.153,130
,146.742
.148.742
.159.301
9.611.069
9,611,069
9.611,069
9,611.069
9.611.069
9.611,069
ota I
n (BOE)
Change
-0.5X
-0.5X
-0.9X
-0.9X
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Corporate Cost
per BOE
Data
$21.16
$22.25
$21.79
$24.64
$23.88
$21.23
$18.23
$18.48
$18.38
$18.59
$18.44
$18.26
Change
5.2X
3. OX
16. 4X
12. 9X
0.3X
1.4X
0.8X
2. OX
1.2X
0.2X
Production Cost
per BOE
Data
$13.71
$14.67
$14.36
$16.26
$15.75
$13.81
$8.95
$9.17
$9.11
$9.25
$9.15
$9.00
Change
7. OX
4.7X
18. 6X
H.9X
0.7X
2.5X
1.8X
3.4X
2.2X
0.6X
Net Present Value
($1000)
Data
$654
($119)
$134
($1.421)
($1.005)
$579
$33,610
$32,090
$32,560
$31,573
$32,280
$33,300
Change
-118.2X
-79.5X
-317.3X
-253. 7X
-11. 5X
-4.5X
-3. IX
-6.1X
-4. OX
-0.9X
Internal Rate
of Return
Data
9.5X
7.7X
8.3X
5. OX
5.8X
9.3X
20. IX
19.4X
19. 7X
19. 2X
19. 5X
19. 9X
Change
-18. 9X
-12. 6X
-47. 4X
-38. 9X
-2. IX
-3.5X
-2. OX
-4.5X
-3. OX
-1.0X
Years of
Production
Data
20
18
18
17
17
20
19
19
19
19
19
19
Change
-10. OX
-10. OX
-15. OX
-15. OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Notes: G refers to granular filter technology costs for injection and filtration.
M refers to nenbrane filter technology costs for injection and filtration.
BOE represents barrels-of-oi(-equivalent.
Source: ERG estimates.
-------
This relationship means that the effects of the combined pollution control
options (one for drilling fluids and drill cuttings with one for produced
water) on any of the projects can be determined by adding the appropriate
entries provided earlier in this section.2 Impacts will not exceed those for
the Gulf Ib, and are 'likely to resemble or be less than those for the Gulf 12.
When the combined impacts are analyzed for a typical sized Gulf 12
project, the net present value decreases by no more than 6.1 percent and the
internal rate of return decreases by no more than 4.5 percent under any
combination of options. The corporate and production costs per BOE increase
by about 40 cents under the most expensive combination of options. Under the
combination of 4-Mile Barge; 1,1 Other requirements for drilling waste and
filtration costs for produced water, the Gulf 12 shows no more than a 5
percent decline in net present value or the internal rate of return and a 25
cent increase in the corporate cost per BOE. Under the same combination of
costs, the net present value for the Gulf Ib turns negative if granular filter
costs are assumed but remains positive if membrane filter costs are assumed.
Components may not sum precisely due to independent rounding.
7-32
-------
SECTION EIGHT
IMPACTS ON REPRESENTATIVE COMPANIES
This section evaluates the financial impact of BAT effluent guidelines
limitations and NSPS standards on (1) drilling fluids and drill cuttings and
(2) production wastes from the offshore oil and gas industry. Impacts are
considered three ways: (1) on the industry as a whole, (2) on a "typical"
major oil company, and (3) on a "typical" independent oil company. The
balance sheets and income statements for "typical" majors and independents are
developed in Section Three. The compliance costs associated with regulations
are presented in Section Six.
8.1 DRILLING FLUIDS AND DRILL CUTTINGS
The American Petroleum Institute conducts an annual survey on
exploration, development, and production expenditures by the oil and gas
industry. The data for 1986 and 1985 are presented in Table 8-1. The effects
of the oil crash in 1986 are evident; exploration and development expenditures
are approximately one-half of 1985 levels. Any comparison of annual
compliance costs to 1986 expenditures is a conservative approach because of
the low level of 1986 expenditures.
To examine the full range of potential impacts of increased pollution
control costs, the Agency considered four alternative scenarios:
$21/bbl - restricted development
$21/bbl - unrestricted development
$32/bbl - unrestricted development
$15/bbl - restricted development
The baseline ("best estimate") impacts are represented by the cost borne under
the first scenario ($21/bbl - restricted development). The third scenario
($32/bbl - unrestricted development) represents the upper estimate of impacts,
while the fourth scenario ($15/bbl - restricted development) represents the
8-1
-------
spend.uk1
TABLE 8-1
OIL AND GAS EXPLORATION AND DEVELOPMENT EXPENDITURES
1986 AND 1985 DATA
Parameter
Exploration
Drilling & Equipping
Acquiring Undeveloped Acreage
Land dept., leasing & Scouting
Geological & Geophysical
Lease Rents
Test Hole Contributions
Other*
Total Exploration Expenditures
Development
Drilling & Equipping
Lease Equipment
Fluid Inj. & Impr. Recov.
Other*
Total Development Expenditures
Total Exploration & Development
Expenditures
Total
S3, 048
$1 ,335
$301
$1,244
S383
$125
$2,032
$8,468
$9,257
$3,526
$1,140
$2,431
$16,354
$24,822
1986
Onshore
$1,904
$1,016
$291
$882
$300
$117
-
$4,510
$6,460
$1,455
$875
-
$8,790
$13,300
($Million:
Offshore
$1,149
$270
$7
$306
$65
$4
-
$1,801
$2,148
$1,032
$61
-
$3,241
$5,042
I
Alaska
($5)
$49
$3
S56
$18
$4
-
$125
$649
$1,039
$204
-
$1,892
$2,017
Total
$9,297
$4,040
$381
$2,392
$541
$16
$2,732
$19,399
$17,411
$5,029
$1,822
$2,974
$27,236
$46,635
1985
Onshore
$6,796
$2,522
$355
$1,787
$444
$4
-
$11,908
$14,076
$2,004
$1,372
-
$17,452
$29,360
($Million)
Offshore
$2,154
$1,478
$16
$430
$69
$10
-
$4,157
$2,822
$1,569
$77
-
$4,468
$8,625
»
Alaska
$347
$40
$10
$175
$28
$2
-
$602
$513
$1,456
$373
.
$2,342
$2,944
* Other includes direct overhead
** Current dollars.
Source: 1986 API Survey on Oil &
and G&A overhead; this category is not allocated among regions.
Gas Expenditures, American Petroleum Institute, December 1987.
8-2
-------
lower estimate. The tables throughout Section 8.1 refer to these three
scenarios as "baseline," "upper," and "lower," respectively.
8.1.1 Impacts on the General Offshore Oil and Gas Industry
Under the baseline case, the annual compliance costs for the regulatory
options on drilling fluids and drill cuttings range from $1 million to $224
million in 1986 dollars. Compared to the expenditures allocated to offshore
efforts for 1986 (see Table 8-1), the compliance costs would range from 0.02
percent to 4.4 percent of these expenditures. In comparison with 1985 data,
the annual costs of compliance range from 0.01 percent to 2.6 percent of total
offshore exploration and development expenditures.
8.1.2 Impacts on "Typical" Oil Companies
The costs of compliance borne by the industry will be financed by the
oil and gas companies operating in the offshore areas. The financial impact
of these expenditures for a given company depends on the size of the
expenditures required and the current financial condition of the company.
Since the price that a company can command for its oil is set by the world oil
price and not domestic costs, the Agency assumes no increase in oil price to
offset the cost of compliance.
To measure the impact of the cost of compliance on a representative
major oil company, it is first necessary to estimate the portion of the annual
costs that it would bear. The API survey on expenditures also presents the
expenditures of the 19 largest companies, all but one of which are major oil
companies. Unfortunately, the data are not subdivided by both "largest
companies" and region, so it is not possible to obtain the expenditures by the
largest companies in the offshore region. Table 8-2 presents the exploration
and development expenditures in 1986 by the 19 largest companies. Each major
oil company accounted for an average of $688 million out of a total of $24,822
million, or 2.77 percent of the national total exploration and development
expenditures for the oil and gas industry.
In 1985, a "typical" independent oil company spent $69 million for
domestic exploration and development, including both offshore and onshore
efforts (see Table 3-27). (As mentioned in Section Three, it was not possible
8-3
-------
sostX.wlcl
TABLE 8-2
EXPLORATION AND DEVELOPMENT EXPENDITURES BY MAJOR OIL COMPANIES IN 1986
(BOTH OFFSHORE AND ONSHORE)
Parameter Total
Exploration
Expenditures $8,468
Development
Expenditures $16,354
SLID of Exploration
and Development
Expend i tures $24 , 822
Average Expenditure
For a Large
Company
19
Largest
Companies
$4,275
$8,793
$13,068
$688
Remaining
Companies
$4,193
$7,561
$11,754
Note: All expenditures in millions of current dollars.
Source: 1986 Survey on Oil & Gas Expenditures, American Petroleum
Institute, December 1987.
8-4
-------
to update the income statement and balance sheet for 1986 for independents
because of the take-over of Inexco by Louisiana Land & Exploration in mid-
1986.) Thus a typical independent accounted for $69 million out of a total of
$46,635 million or 0.15 percent of total domestic exploration and development
expenditures in 1985 (see Table 8-1).
A typical major was assumed to bear 2.77 percent of the compliance costs
while a typical independent would bear 0.15 percent of the costs. Table 8-3
lists the cost borne by a typical major and independent for each of the four
scenarios analyzed.
The company is assumed to raise the entire amount at one time to finance
compliance. Two financing alternatives were considered:
All expenditures are financed by long-term debt.
All expenditures are financed by working capital.
Tables 8-4 and 8-5 show the impact on the balance sheet of a typical
major of financing effluent guidelines limitations and standards costs through
long-term debt or working capital, respectively. The balance sheet for the
unregulated case is developed in Section Three.
Table 8-6 lists the changes in working capital, current ratio, long-term
debt-to-equity ratio, and debt-to-capital ratio caused by the cost of
compliance. For the 1,1 All and 5,3 All options, no changes are seen for any
of the parameters. For the options that require barging within 4 miles of
shore, no changes are seen for three of the parameters, while working capital
is reduced by 0.2 percent or less. Under the Zero Discharge option, working
capital is reduced by 1.2 percent or less, while the other three parameters
incur changes of 0.2 percent or less.
Dropping Inexco from the data set for 1986 would have left too few
companies for aggregation. Therefore, to obtain a balance sheet for a
"typical" independent for 1986, the change in the consumer price index was
used to inflate the 1985 balance sheet to 1986 dollars. Tables 8-7 and 8-8
show the updated balance sheet and the impacts of financing the cost of
compliance by working capital and long-term debt, respectively.
Table 8-9 lists the changes in working capital, current ratio, long-term
debt-to-equity ratio, and debt-to-capital ratio caused by the cost of
compliance. No change occurs to the current ratio, long-term-debt-to-equity,
and debt-to-capital for a typical independent under the 1,1 All and 5,3 All
8-5
-------
TABLE 8-3
ANNUAL COST OF POLLUTION CONTROL OPTIONS
DRILLING FLUIDS AND DRILL CUTTINGS
MILLIONS OF DOLLARS, 1986 DOLLARS
Regulatory Options
Zero Discharge
Scenario
$21/bbl -
$21/bbt -
$32/bbl -
$15/bbl -
CO
1
Total
Annual
Restricted $224
Unrestricted (283
Unrestricted $344
Restricted $197
Typical
Major
Portion
$6.20
$7.85
$9.53
$5.46
Typical
Independent
Portion
$0.34
$0.42
$0.52
$0.30
4-Mile Barge; 1
Typical
Total Major
Annual Portion
$30 $0.83
$50 $1.38
$60 $1.65
$26 $0.73
,1 Other
Typical
Independent
Portion
$0.04
$0.07
$0.09
$0.04
4-Mile Barge; 5,3 Other
Typical
Total Major
Annual Portion
$23 $0.63
$43 $1.18
$51 $1.41
$20 $0.56
Typical
1 ndependent
Portion
$0.03
$0.06
$0.08
$0.03
1.1 All
Typical
Total Major
Annual Portion
(9 $0.25
$11 $0.29
$14 $0.40
$8 $0.21
Typical
I ndependent
Portion
$0.01
$0.02
$0.02
$0.01
5,3 All
Typical
Total Major
Annual Portion
$1 $0.03
$2 $0.05
$4 $0.12
$1 $0.02
Typical
1 ndependent
Portion
$0.00
$0.00
$0.01
$0.00
Source: ERG estimates.
-------
TABLE 8-4
EFFLUENT GUIDELINES IMPACTS ON TYPICAL MAJOR OIL COMPANY
COMPLIANCE COSTS FINANCED IT WORKING CAPITAL
DRILLING FLUIDS AND DRILL CUTTINGS
f MILLIONS. 1986 DOLLARS
Rtgutatory Option
CO
1
-J
Parameter*
Regulatory Cost Borne by Major
Assets
Current Assets
Property. Plant, and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
Long- tern Debt
Other Liabilities (a)
Total Liabilities
Shareholders' Equity
Total liabilities
and Net Worth
1986
Dollar*
S8.337
124,799
*2,758
$35,893
(7.536
(5.443
(7.600
$20.579
$15.314
$35,893
Zero 01 (charge
lasel in*
to. 20
S8.33I
$24.799
12.758
S35.888
$7.536
$5,443
17,600
J20.579
115, JOS
$35,887
Upper
$9.53
$8.327
124, 799
12,758
135,884
S7.5J6
$5.44J
17,600
120,579
115.304
135,883
lower
15.46
$8,332
*2*.799
12.758
S3S.889
17,536
15.443
17,600
120,579
115.309
115,888
4-Mll* large; 1,1
Basel Ine
M. 83
18.336
124.799
12.758
135.893
17.536
15.443
17.600
120.579
115,313
$35.892
Upper
11.65
18,335
$24,799
12,758
135,892
$7,536
15,443
(7,600
$20.579
115,312
$35.891
Other
Lower
M.73
18,336
$24.799
$2,758
$35.891
$7.536
$5,443
$7,600
$20.579
$15,313
$35,892
4-Mile Barge; 5,3
Baseline
$0.63
$8.336
$24,799
$2.758
$35.893
$7.536
$5.443
17,600
120,579
$15.313
$35,892
Upper
$1.41
18,336
$24.799
12.758
$35,893
$7,536
$5,443
$7,600
120,579
$15,313
(35.892
Other
lower
(0.56
$8,336
$24.799
$2,758
$35,893
$7.536
$5.443
$7,600
(20,579
$15,313
$35,892
liseline
(0.25
18.337
(24.799
(2.758
(35.894
(7.536
(5.443
(7,600
(20,579
(15,314
(35,893
1,1 All
upper
(0.40
(8.337
(24.799
(2,758
(35,894
(7,536
(5,443
(7,600
(20,579
(15,314
(35,893
Lower
(0.21
$8.337
(24,799
$2.758
(35.894
(7,536
(5,443
(7.600
(20,579
(15,314
(35.893
Basel ine
10.03
18,337
(24.799
12.758
(35,894
(7.536
(5,443
(7.600
(20.579
$15,314
(35.893
5,3 All
Upper
(0.12
18.317
124.799
12.758
115.894
(7.536
15,443
17,600
120,579
115.314
135.893
1 oucr
(0.02
18.117
124,799
12.758
135.894
17.51t
(5.443
If. 600
120.5/9
115, 314
155.891
Note:(a) Other liabilities include: deferred federal and foreign income
Baseline refers to *21/tabl Restricted.
Upper refers to $32/bbl - Unrestricted.
Lower refers to tlVbbt - Restricted.
Entries may not sun due to independent rounding.
Source: ERG estimates.
taxes, deterred revenue, production payments, and other medium-term comai totems.
-------
TABLE 85
EFFLUENT GUIDELINES IMPACTS ON TYPICAL MAJOR OIL CONPANT
COMPLIANCE COSTS FINANCED IT LONG-TERN DEBT
DRILLING FLUIDS AND DRILL CUTTINGS
t Mill IONS, 1916 DOLLARS
Regulatory Option
CD
1
CD
Paranetera
Regulator/ Cost Borna by Major
Assets
Current Assets
Property, Plant, and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
long- tern Debt
Other Liabilities (>
Total Liabilities
Shareholders' Equity
Total Liabilities
and Net Worth
1986
Dollars
(8.337
(24.799
(2.758
(35.893
(7.536
15.443
(7.600
(20.579
(15. 3U
(35.893
Zero Discharge
Basel ine Upper
(6.20 (9.53
(8,337 (8,337
(24.799 (24,799
(2,758 (2.758
(35.894 (35.894
(7,536 (7,536
(5.449 (5.453
(7.600 (7,600
(20.585 (20,589
(15,308 (15,304
(35,893 (35,893
Nole:(a) Othe liabilities include: deterred Federal and foreign income
Base ine refers to (21/bbl - Restricted.
Uppe refers to (32/bbl - Unrestricted.
loue refers to (15/bbl - Restricted.
Entr es may not sun due to independent rounding.
Source: ERG sttmates.
Lower
(5.46
(8.337
(24,799
(2,758
(35,894
(7,536
(5,448
(7,600
(20,584
(15.309
(35,893
4-Mlle Barge; 1,1
Baseline
(0.83
(8,337
(24,799
(2.758
(35,894
(7,536
(5,444
(7.600
(20,580
(15,313
(35.893
Upper
(1.65
(8.337
(24,799
(2,758
(35,894
(7,536
(5,445
(7.6OO
(20,581
(15,312
(35,893
Other 4-Mile Barge; 5.3
Lower Baseline Upper
(0.73
(8.337
(24,799
(2,758
(35,894
(7,536
(5,444
(7,600
(20.580
(15,313
(35.893
taxes, deferred revenue, production payments
(0.63 (1.41
(8,337 (8.337
(24,799 (24,799
(2.758 (2.758
(35.894 (35.894
(7.536 (7.536
(5.444 (5,444
(7,600 (7.600
(20,580 (20,580
(15,313 (15,313
(35.893 (35,893
, and other mcdiu
Other
Lower
(0.56
(8,337
(24,799
(2.758
(35,894
(7,536
(5.444
(7.600
(20,580
(15,313
(35,893
ra- term con
Baseline
(0.25
(8,337
(24,799
(2.758
(35.894
(7.536
(5.443
(7.600
(20.579
(15.314
(35.893
mi tments.
1,1 All
Upper
(0.40
(8.337
(24,799
(2.758
(35,894
(7,536
(5.443
(7.600
(20.579
(15.314
(35,893
Lower
(0.21
(8,337
(24,799
(2,758
(35,894
(7.536
(5.443
(7.600
(20.579
(15.314
(35.893
5.3 All
Baseline Upper loucr
10.03 (0.12 10.01
(8.337 (8.33/ 18.33?
(24.799 (24. 799 124.799
12,718 (2,718 12. />&
(35,894 (35,894 135,894
(7,536 (7,536 W.iio
(5,443 (5.443 (5.443
(7,600 (7,600 (7,600
(20,579 (20.579 (20.579
(15,314 (15.314 (15.314
(35.893 (35.893 (S5.8V3
-------
TABU B-6
CHANGES IN FINANCIAL MHOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
DRILLING FLUIDS AND DRILL CUTTINGS
00
I
VO
No
Regulation
Parameters 1986 Dollars Scenario
Working Capital (a) (WO
Current Ratio (a)
Long-tern Debt to Equity (b) (X)
Debt to Capital (b) (X)
MOT laseline
Upper
Lower
1.11 Baseline
upper
Lower
15. 5X laseline
Upper
Lower
23. BX laseline
Upper
Lower
Regulatory Option
Zero Discharge *-Hile large; 1
Parameter X
*795
»791
$796
1.11
1.11
1.11
15.6k
1S.6X
J5.6X
2J.9X
21. n
21. 9X
Change
-o.ax
-1.2X
-0.7X
-0.1X
0.1X
0.1X
0.2X
0.2X
0.1X
0.1X
0.2X
0.1X
1,1 Other 4-Nile Barge; 5,1 Other
WOO
1799
WOO
1.11
1.11.
1.11
15. SX
J5.6X
35. SX
23. ax
21. ex
23. BX
-0.1X
0.2X
0.1X
-O.OX
-O.OX
-O.OX
O.OX
O.OX
o.ox
o.ox
o.ox
o.ox
S800
MOO
two
1.11
1.11
1.11
35. 5X
15. 6X
15. 5X
23. BX
23. 8X
21. ax
I Change
-0.1X
0.2X
-0.1X
O.OX
-O.OX
o.ox
o.ox
o.ox
o.ox
o.ox
o.ox
o.ox
1,1 All
Parameter X Change
W01
$801
>B01
1.11
1.11
1.11
35. 5X
35. 5X
15. 5X
21. ax
21. ax
21. ax
-o.ox
-o.ox
-o.ox
o.ox
o.ox
-o.ox
o.ox
o.ox
o.ox
o.ox
o.ox
o.ox
5,1 All
Parameter X Change
M01
M01
M01
1.11
1.11
1.11
35. 5X
35. 5X
35. 5X
23. BX
21. 8X
23. BX
-O.OX
-o.ox
o.ox
-o.ox
-o.ox
-o.ox
o.ox
o.ox
o.ox
o.ox
o.ox
o.ox
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Baseline refers to tZI/bbl - Restricted.
Upper refers to S32/bbl - Unrestricted.
lower refers to S15/bbl - Restricted.
Source: ERG estimates.
-------
TABLE 6-7
EFFLUENT GUIDELINES IMPACIS ON TYPICAL INDEPENDENT OIL COHPANT
COMPLIANCE COSTS FINANCED BY WORKING CAPITAL
DRILLING FLUIDS AND DRILL CUTTINGS
t MILLIONS. 1986 DOLLARS
Regulatory Option
1985 1986
Parameters Dollars Dollars 81
Regulatory Cost Borne by Independent
Assets
Current Assets $53 $55
Property, Plant, and $528 $547
Equipment (Net)
Other Assets $3 $3
CO
| Total Assets $583 $605
O Liabilities
Current liabilities $49 $51
Long-term Debt $268 $278
Other Liabilities (a) $108 $112
Total Liabilities $424 $441
Shareholders' Equity $159 $165
Total liabilities $583 $604
and Net Worth
Notes: (a) Other labilities Include: deferred Federal
1985 doll a » inflated to 1986 dollars by 3.65X
Upper refe s to $32/bbl - Unrestricted.
lower refe s to 115/bbl - Restricted.
Zero Discharge
seline
$0.34
$55
$547
$3
$605
$51
$278
$112
*441
$164
$605
Upper Lower
$0.52 $0.30
$54
$547
$3
$605
$51
$278
$112
$441
$164
$605
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
and foreign income taxes,
based on change in Consumer
4-Mile targe; 1,1 Other
Baseline
$0.04
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
Upper
$0.09
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
lower
$0.04
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
deferred revenue, production
Price Index.
4-Mile Barge; 5,3 Other
Baseline
$0.03
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
payments, and
Upper
$0.08
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
lower
$0.03
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
other medium- term coc
1
Basel ine
$0.01
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
nnitments.
1 All
Upper
$0.02
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
Lower
$0.01
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
5
Basel ine
$0.00
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
3 All
Upper Lower
$0.01 $0.00
$55 $55
$547 $547
$3 $3
$605 $605
$51 $51
$278 $278
$112 $112
$441 $441
$165 $165
$605 $605
Entries may not sun due to independent rounding.
Source: ERG estimates.
-------
TABU 8-8
EFFLUENT GUIDELINES IMPACTS ON TTPICAL INDEPENDENT OIL COMPANY
COMPLIANCE COSTS FINANCED BT LONG-TERM DEBT
DRILLING FLUIDS AND DRILL CUTTINGS
t MILLIONS, 1986 DOLLARS
Regulatory Option
00
1
F-"
"
Parameters
Regulatory Cost Born* by 1
Assets
Current Assets
Property, Plant, and
Equipment (Net)
Other Assets
Total Assets
liabilities
Current Liabilities
Long-term Debt
Other liabilities (a)
Total liabilities
Shareholders' Equity
Total Liabilities
and Net Uorth
1985
Dollars
ndependent
$53
$528
13
1583
$49
$268
$108
$424
$159
$583
1986
Dollars
$55
$547
$3
$605
$51
$278
$112
$439
$165
1605
Zero Discharge
Baseline
$0.14
$55
$547
$3
$605
$51
$278
$112
$441
$164
$605
Upper
$0.52
$55
$547
$3
$605
$51
$278
$112
$441
$164
$605
Lower
10.30
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
4-Mile Barge; 1,1 Other
Baseline
$0.04
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
Upper
$0.09
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
Lower
$0.04
$55
$547
$1
$605
$51
$278
$112
$441
$165
$605
4-Mile Barge; 5,3 Other
Baseline
$0.01
$55
1547
11
$605
$51
$278
$112
$441
$165
$605
Upper
$0.08
$55
1547
13
$605
$51
1278
1112
$441
$165
$605
Lower
10.03
155
1547
1)
$605
$51
$278
$112
$441
$165
$605
1
Baseline
10.01
$55
$547
13
$605
$51
$278
$112
$441
$165
$605
,1 All
Upper
$0.02
$55
1547
13
$605
$51
$278
$112
$441
$165
$605
Lower
$0.01
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
5
Basel ine
$0.00
$55
1547
13
1605
151
1278
1112
1441
1165
$605
,3 All
Upper
10.01
155
1547
$3
1605
151
1278
1112
1441
1165
1605
Lower
10.00
155
1547
13
1605
151
1278
1112
1441
1165
1605.
Notes: (a) Other liabilities Include: deferred Federal and foreign income taxes, deferred revenue, production payments, and other medium-term coaraitments.
1985 dollars Inflated to 1986 dollars by I.65X based on change in Consumer Price Indei.
Baseline refers to 121/bbl - Restricted.
Upper refers to $32/bbl - Unrestricted.
lower refers to $15/bbl - Restricted.
Entries may not sum due to independent rounding.
Source: ERG estimates.
-------
TABLE B-9
CHANGES III FINANCIAL IAIIOS FOR A ITPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
OBI LI I NO FLUIDS AMD DRILL CUTTINGS
00
I
No
Regulation
Pit-meters 1986 Dollars
Working Capital () ($M) *4.15
Current Ratio () 1.08
Long-tern Debt to Equity (b) (X) 168. 6X
Debt to Capital (b) (X) 128. BX
Regulatory Option
Zero Discharge
Scenario
lateline
Upper
Lower
Basel ine
Upper
Lower
Baseline
Upper
lower
Baseline
Upper
Lower
Parameter
H.S1
»3.63
$3.85
1.07
1.07
1.08
169. IX
169. «X
169.0X
129.21
129.*X
129. 2X
X Chang*
-8.2X
12.5X
-7.2X
-0.6X
-0.9*
O.SX
0.3X
O.SX
0.3X
O.SX
0.«
o.n
4-Mile Barge;
Paraawter
tt.11
M.06
M.11
1.08
1.08
1.08
168.6X
168. 7X
168.6X
128. OT
128. 9X
128. M
: 1,1 Other
X Change
-1.0X
2.2x
-1.0X
-0.1X
-0.2X
0.1X
o.ox
0.1X
o.ox
o.ox
0.1X
o.ox
4-Nile Barge;
Parameter
14.12
U.07
tt.12
1.08
1.08
1.08
168. 6X
168. 7X
168.6X
128. 9X
128. 9X
128. 9X
; S.3 Other
X Change
0.7X
-1.9X
-0.7X
-0.1X
0.1X
0.1X
O.OX
0.1X
O.OX
O.OX
0.1X
O.OX
1.1 All
Parameter X
14. K
14.13
S4.U
1.08
1.08
1.08
168. 6X
168.6X
168.6X
128. 9X
128. 9X
128. 9X
Change
-0.2X
O.SX
0.2X
-O.OX
-O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
o.ox
5,3 All
Parameter X
St. IS
J4.14
14.15
1.08
1.08
1.08
168. 6%
168. 6X
168. 6X
128. 8Z
128. 9X
128. 8X
Change
O.OX
0.2X
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
o.ox
o.ox
Note: (a) The»e rat lot affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Baseline refers to $21/bbl - Restricted.
Upper refers to *32/bfcl - Unrestricted.
lower refers to tlS/bbl - Restricted.
Source: ERG estimates.
-------
options. Working capital decreases by 0.5 percent or less. For the options
where barging is required for operations within 4 miles of shore, current
ratio, long-term-debt-to-equity, and debt-to-capital change by 0.2 percent or
less. Working capital may decrease by as much as 2.2 percent. For the Zero
Discharge option, debt financing ratios may increase by 0.5 percent, while the
current ratio may decrease by 0.9 percent. Working capital may decrease by as
much as 12.5 percent for the Zero Discharge option.
8.2 PRODUCED WATER - BAT
8.2.1 Impacts on the General Offshore Industry
The annualized cost for BAT controls on produced water range from $41
million to $845 million in 1986 dollars, assuming costs for granular filter
filtration and injection. The annualized cost ranges from $13 million to $491
million in 1986 dollars for the sane set of regulatory options, but assuming
membrane filter costs for filtration and injection.
Looking strictly at the expenditures allocated to offshore efforts for
1986 (see Table 8-1), the compliance costs would range from 0.8 to 16.8
percent of the total for granular filter costs and from 0.3 to 9.7 percent for
membrane filter costs. In comparison with the total offshore exploration and
development expenditures in 1985, the annual compliance costs range from 0.5
to 9.8 percent for the granular filter costs, and from 0.2 to 5.7 percent
assuming membrane filter costs.
8.2.2 Impacts on "Typical" Oil Companies
The same balance sheets shown in Tables 8-4, 8-5, 8-7 and 8-8 for a
typical major and independent are used to evaluate the impacts of increased
BAT pollution control costs for produced water on representative companies.
As described in Section Six, there are two sets of costs for filtration and
injection, so two financial ratio analyses are presented for each company.
Table 8-10 summarizes the portion of regulatory cost borne by a typical
major and independent under both cost scenarios (granular filter and membrane
filter). Using these costs from Table 8-10, the changes in financial ratios
8-13
-------
TABLE 8-10
ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT PRODUCED WATER
MILLIONS OF DOLLARS, 1986 DOLLARS
$21/bbl
Cost Scenario
Zero Discharge
Regulatory Options
All Filter
4-Mile Filter; BPT Other
Typical Typical
Total Major Independent
Annual Portion Portion
Typical Typical
Total Major Independent
Annual Portion Portion
Typical Typical
Total Major Independent
Annual Portion Portion
Granular FiIter Costs
$845 $23.40
$1.27
$480 $13.30
$0.72
$41 $1.14
$0.06
Membrane Filter Costs
$491 $13.61
$0.74
$151 $4.18
SO. 23
$13 $0.36
$0.02
Source: ERG estimates.
8-14
-------
were calculated for a typical major (Table 8-11) and for a typical independent
(Table 8-12).
For a typical major under the 4-Mile Filter; BPT Other option, the
working capital declines by 0.1 percent or less, depending upon filtration
type (see Table 8-11). For the All Filter option, working capital declines by
1.7 percent, assuming granular filter costs and by 0.5 percent, assuming
membrane filter costs. Changes in the current, long-term debt-to-equity, and
debt-to-capital ratios are no more than 0.3 percent for the All Filter option.
If a typical major must comply with the Zero Discharge option for BAT-produced
water, working capital declines by 2.9 percent or 1.7 percent under the
granular or membrane filter costs, respectively. The current ratio declines
by no more than 0.3 percent, and the debt ratios increase by no more than 0.6
percent under the Zero Discharge option with granular filter costs.
Table 8-12 displays the impacts on a typical independent. Under the 4-
Mile Filter; BPT Other option, working capital declines by 1.4 percent and 0.5
percent assuming granular filter and membrane filter costs, respectively.
Changes in the other ratios are no more than 0.1 percent. Working capital
declines by 17.4 or 5.5 percent for granular and membrane filter costs,
respectively. Changes in the current ratio, long-term debt-to-equity, and
debt-to-capital ratios range from 0.6 to 1.3 percent for granular filter costs
and from 0.2 to 0.4 percent for membrane filter costs. Under the Zero
Discharge option, working capital declines by 30.6 percent for granular filter
costs and by 17.8 percent for membrane filter costs. Changes in the other
ratios range from 1.1 to 2.3 percent and 0.6 to 1.3 percent for the granular
and membrane filter costs, respectively.
83 PRODUCED WATER - NSPS
83.1 Impacts on the General Offshore Industry .
The annualized cost in the year 2000 for NSPS controls on produced water
ranges from $11 million to $158 million in 1986 dollars, assuming membrane
filter costs for filtration and injection. The annualized cost ranges from
$16 million to $206 million in 1986 dollars for the same set of regulatory
options, but assuming granular filter costs for filtration and injection.
8-15
-------
TABLE 8-11
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT PRODUCED WATER
Regulatory Option
00
I
M
CM
No
Regulation Cost
Parameters 1986 Dollars Scenario
Working Capital (a) ($M) $801 Granular
Membrane
Current Ratio (a) 1.11 Granular
Membrane
Long-term Debt to Equity (b) (X) 35. SX Granular
Membrane
Debt to Capital (b) (X) 23. 8X Granular
Membrane
Zero Discharge
Parameter
$778
$787
1.10
1.10
35. 8X
35. 7X
23. 9X
23. 9X
X Change
-2.9X
-1.7X
-0.3X
-0.2X
0.6X
0.3X
0.5X
0.3X
All Filter
Parameter
$788
$797
1.10
1.11
35. 7X
35. 6X
23. 9X
23. 8X
X Change
-1.7X
-0.5X
-0.2X
-0.1X
0.3X
0.1X
0.3X
0.1X
4-Mile Filter
Parameter
$800
$801
1.11
1.11
35. 6X
35. 5X
23.8%
23. 8X
; BPT Other
X Change
-0.1X
-O.OX
-O.OX
-O.OX
O.OX
O.OX
O.OX
O.OX
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing appraoch only.
Source: ERG estimates.
-------
TABLE 8-12
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT PRODUCED WATER
Regulatory Option
No
Regulation Cost
Parameters 1986 Dollars Scenar
Working Capital (a) (SM)
Current Ratio (a)
00
1
M
Long-term Debt to Equity (b) (X)
Debt to Capital (b) (X)
$4.15 Granular
Membrane
1.08 Granular
Membrane
168. 6X Granular
Membrane
128. 8X Granular
Membrane
Zero Discharge
io Parameter X Change
Filter
Filter
Filter
Filter
Filter
Filter
Filter
Filter
$2.88
$3.41
1.06
1.07
170. 6X
169. 8X
130.2X
129.6X
-30. 6X
-17.BX
-2
-1
1
0
1
0
.3X
.3X
.2X
.7X
.IX
.6X
All Filter
4-Mile Filter; BPT Other
Parameter X Change
$3.43
$3.92
1.07
1.08
169. 7X
168. 9X
129. 6X
129. 1X
-17. 4X
-5.5X
-1
-0
0
0
0
0
.3X
.4X
.7X
.2X
.6X
.2X
Parameter X Change
$4.09
$4.13
1.08
1.08
168. 7X
168. 6X
128.9X
128. 9X
-1
-0
-0
-0
0
0
0
0
!sx
.1%
.OX
.1%
.OX
.0%
.ox
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: ERG estimates.
-------
Looking strictly at the expenditures allocated to offshore efforts for
1986 (see Table 8-1), the compliance costs would range from 0.3 to U.I percent
of the total for granular filter costs and from 0.2 to 3.1 percent for
membrane filter costs. In comparison with the total offshore exploration and
development expenditures in 1985, the annual compliance costs range from 0.2
to 2.4 percent for the granular filter costs, and from 0.1 to 1.8 percent
assuming membrane filter costs.
83.2 Impacts on "Typical" Oil Companies
Table 8-13 lists the portion of NSPS-produced water pollution control
costs borne by a typical major and independent under three cost scenarios.
The "baseline" scenario assumes $21/bbl, restricted development, and membrane
filter costs, and represents the most reasonable estimate of projection costs.
The "upper" cost scenario, representing the high estimate of projected costs,
assumes $32/bbl and unrestricted development with granular filter costs. The
"lower" cost scenario assumes $15/bbl with restricted development and membrane
filter costs.
Table 8-14 summarizes the change in financial ratios for a typical
major. The largest change is seen in working capital under the $32/bbl oil
price scenario; the change, however, is only 1.3 percent. The financial ratio
analysis for a typical independent is given in Table 8-15. Current ratio,
long-term debt-to-equity, and debt-to-capital all change by no more than 1
percent under any of the options. Working capital shows a large range in
response, declining by no more than 2 percent under the 4-Mile Filter; BPT
Other option and from 5 to 14 percent under the Zero Discharge option.
8.4 COMBINED EFFECTS OF SELECTED REGULATORY OPTIONS
8.4.1 Impacts on the General Offshore Oil and Gas Industry
Six combinations of regulatory options were analyzed. Table 8-16
presents the combinations and their costs. Two sets of costs are provided,
depending upon whether development is restricted or unrestricted. The oil
price in both cases is assumed to be $21/bbl.
8-18
-------
TABLE 8-13
ANNUAL COST Of POLLUTION CONTROL OPTIONS
NSPS PRODUCED WATER
MILLIONS OF DOLLARS, 1986 DOLLARS
$21/bbl
Cost Scenario
Zero Discharge
Regulatory Options
All Filter
4-Mile Filter; BPT Other
Typical Typical
Total Major Independent
Annual Portion Portion
Typical Typical
Total Major Independent
Annual Portion Portion
Typical Typical
Total Major Independent
Annual Portion Portion
Baseline
Upper
Lower
$158
$375
$135
$4
$10
$3
.39
.40
.74
$0
$0
$0
.24
.56
.20
$62
$168
$53
$1.70
$4.66
$1.46
$0.09
$0.25
$0.08
$11
$51
$8
$0.30
$1.42
$0.22
$0.02
$0.08
$0.01
Notes: Baseline refers to $21/bbl - Restricted u/ menbrane filter costs.
Upper refers to $32/bbl - Unrestricted w/ granular filter costs.
Lower refers to $15/bbl - Restricted u/ membrane filter costs.
Source: ERG estimates.
8-19
-------
TABLE 8-14
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
NSPS PRODUCED WATER
09
to
o
Regulatory Option
No
Regulation
Parameters 1986 Dollars
Working Capital (a) ($M) $801
Current Ratio (a) 1.11
Long-term Debt to Equity (b) (X) 35. 5X
Debt to Capital (b) (X) 23. 8X
Cost
Scenario
Baseline
Upper
Lower
Baseline
Upper
Lower
Baseline
Upper
Lower
Baseline
Upper
Lower
Zero Discharge
Parameter
$797
$791
$797
1.11
1.10
1.11
35. 6X
35. 6X
35. 6X
23. 8X
23. 9X
23. 8X
X Change
-0.5X
-1.3X
-0.5X
-0.1X
-0.1X
-O.OX
0.1X
0.3X
0.1X
0.1X
0.2X
0.1X
All Filter
Parameter
$799
$796
$800
1.11
1.11
1.11
35. 6X
35. 6X
35. 6X
23. 8X
23. 8X
23. 8X
X Change
-0.2X
-0.6X
-0.2X
-O.OX
-0.1X
-O.OX
O.OX
0.1X
O.OX
O.OX
0.1X
O.OX
4-Mile Filter;
Parameter
$801
$800
$801
1.11
1.11
1.11
35. 5X
35. 6X
35. 5X
23. 8X
23. 8X
23. 8X
BPT Other
X Change
-O.OX
-0.2X
-O.OX
-O.OX
-O.OX
-O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
O.OX
Notes: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Baseline refers to $21/bbl - Restricted w/ membrane filter costs.
Upper refers to $32/bbl - Unrestricted w/ granular filter costs.
Lower refers to $15/bbl - Restricted w/ membrane filter costs.
Source: ERG estimates.
-------
TABLE 8-15
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
NSPS PRODUCED WATER
oo
I
to
Regulatory Option
No
Regulation
Parameters 1986 Dollars
Working Capital (a) ($M) $4.15
Current Ratio (a) 1.08
Long-term Debt to Equity (b) (X) 168.6X
Debt to Capital (b) (X) 128.8X
Zero Discharge
Scenario
Baseline
Upper
Lower
Baseline
Upper
Lower
Baseline
Upper
Lower
Baseline
Upper
Lower
Parameter
$3.91
S3. 58
$3.95
1.08
1.07
1.08
168.9%
169.5X
168.9X
129. IX
129.4X
129. IX
X Change
-5.7X
-13. 6X
-4.8X
-0.4X
-1.0X
O.AX
0.2X
0.5X
0.2X
0.2X
0.5X
0.2X
All Filter
Parameter
$4.05
$3.89
$4.07
1.08
1.08
1.08
168.7X
169. OX
168. 7X
128. 9X
129. IX
128. 9X
X Change
-2.2X
-6. IX
-1.9X
-0.2X
-0.5X
-0.1X
0.1X
0.2X
0.1X
0.1X
0.2X
0.1X
4-Mile Filter;
Parameter
$4.13
$4.07
$4.14
1.08
1.08
1.08
168.6X
168. 7X
168.6X
128. 9X
128. 9X
128.9X
BPT Other
X Change
-0.4X
-1.9X
-0.2X
-O.OX
-0.1X
-O.OX
O.OX
0.1X
O.OX
O.OX
0.1X
O.OX
Notes: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Baseline refers to $21/bbl - Restricted w/ membrane filter costs.
Upper refers to $32/bbl - Unrestricted w/ granular filter costs.
Lower refers to $15/bbl - Restricted w/ membrane filter costs.
Source: ERG estimates.
-------
TABLE 8-16
COMBINED COST OF SELECTED REGULATORY PACKAGES
SHILLIONS, 1986 DOLLARS
oo
I
to
K>
Restricted Development
Regulatory
Package Effluent
A
B
C
D
E
F
Dri 11 ing Fluid
Produced Water
Produced Water
Combined Cost
Drilling Fluid
Produced Water
Produced Water
Combined Cost
Drilling Fluid
Produced Water
Produced Water
Combined Cost
Drilling fluid
Produced Water
Produced Water
Combined Cost
Drilling Fluid
Produced Water
Produced Water.
Combined Cost
Drilling Fluid
Produced Water
Produced Water
Combined Cost
and Dri 11 Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
and Drill Cuttings
- BAT
- NSPS
Effluent
Control
Opt i on
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
4-Mile Barge; 1,1 Other*
All Filter
All Filter
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1,1 Other*
BPT All
BPT All
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other -Hem
4-Mile Filter; BPT Other -Mem
Total Portion Borne by
Anr-u i*kl
HI II lUd I
Cost
$30
$41
$16
$88
$30
$845
$206
$1,081
$30
$480
$95
$605
$30
$151
$62
$242
$30
$0
$0
$30
$30
$13
$11
$54
Typical
Major Independent
$0.83
$1.14
$0.46
$2.43
$0.83
$23.40
$5.71
$29.94
$0.83
$13.30
$2.63
$16.75
$0.83
$4.18
$1.70
$6.71
$0.83
$0.00
$0.00
$0.83
$0.83
$0.36
$0.30
$1.48
$0.04
$0.06
$0.02
$0.13
$0.04
$1.27
$0.31
$1.62
$0.04
$0.72
$0.14
$0.91
$0.04
$0.23
$0.09
$0.36
$0.04
$0.00
$0.00
$0.04
$0.04
$0.02
$0.02
$0.08
Unrestricted Development
Total
Annua 1
Cost
$50
$41
$27
$118
$50
$845
$275
$1,170
$50
$480
$128
$657
$50
$151
$81
$282
$50
$0
$0
$50
$50
$13
$17
$80
Portion Borne by Typical
Major Independent
$1.38
$1.14
$0.75
$3.28
$1.38
$23.40
$7.62
$32.40
$1.38
$13.30
$3.53
$18.21
$1.38
$4.18
$2.24
$7.80
$1.38
$0.00
$0.00
$1.38
$1.38
$0.36
$0.47
$2.21
$0.07
$0.06
$0.04
$0.18
$0.07
$1.27
$0.41
$1.75
$0.07
$0.72
$0.19
$0.99
$0.07
$0.23
$0.12
$0.42
$0.07
$0.00
$0.00
$0.07
$0.07
$0.02
$0.03
$1 >
Notes: All produced Mater control options assume the use of granular filter technology except options D & F, which assume the use of membrane filter technology.
Entries may not sum due to independent rounding.
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging requirement, but must comply with the 1,1 All restrictions.
Source: ERG estimates.
-------
Under the restricted development assumption, total compliance costs
range from $30 million to $1,081 million (1986 dollars). This cost represents
0.6 to 21.4 percent of the industry expenditures for offshore exploration and
development in 1986 (see Table 8-1). The total costs represent 0.4 to 12.5
percent of offshore expenditures in 1985.
Assuming unrestricted development, the total compliance costs range from
$50 million to $1,170 million (1986 dollars), approximately 1 to 23 percent of
the 1986 offshore expenditures. Compared to offshore expenditures in 1985,
compliance costs range from 0.6 to 13.6 percent of the total.
8.4.2 Impacts on "Typical" Oil Companies
Table 8-17 summarizes the impacts of pollution control packages on a
typical major oil company. If working capital is used to finance the
increased pollution control costs, a decline of 0.1 to 3.7 percent in working
capital is expected (assuming restricted development). The 3.7 percent
decline is seen under regulatory package B (4-Mile Barge; 1,1 Other for
drilling wastes; Zero Discharge for produced water). The current ratio
decreases by no more than 0.4 percent. The financial ratios affected by debt-
financing increase by no more than 0.7 percent under any of the regulatory
packages assuming restricted development. Working capital for a typical major
declines by no more than 4 percent under the unrestricted development scenario
in any package. All other ratios change by less than 1 percent. For
regulatory package F (4-Mile Barge; 1,1 Other for drilling fluids and 4-Mile
Filter; BPT Other for produced water), all financial ratios for a typical
major change by no more than 0.3 percent.
Table 8-18 summarizes the changes in financial ratios for a typical
independent oil company under the six regulatory packages. The greatest
impacts occur when working capital is used to finance the additional pollution
control costs. Assuming restricted development, working capital declines by
39.1 percent under package B, 21.9 percent under package C, and between 1.1
and 8.8 percent for the other packages. The current ratio declines by 3.0
percent under package B and 1.7 percent or less under the other packages. The
financial ratios affected by debt-financing increase by 1.6 percent and 1.3
percent under package B for the long-term debt-to-equity and debt-to-capital
ratios, respectively. Under the other packages, the ratios increase by no
more than 0.8 percent. Impacts for package F (4-Mile Barge; 1,1 Other for
drilling wastes and 4-Mile Filter; BPT Other for produced water) show only a 2
8-23
-------
TABLE 8-17
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
SELECTED COMBINATIONS OF REGULATORY OPTIONS
oo
to
Change in Financial Ratios
Parameters
Working Capital (a) ($M>
Current Ratio (a)
Long-term Debt to Equity (b) (X)
Debt to Capital (b) (X)
No
Regulation Regulatory
1986 Dollars Package
$801 A
B
C
D
E
F
1.11 A
B
C
D
E
F
35.5X A
B
C
D
E
F
23.8X A
B
C
D
E
F
Restricted
Parameter X
$799
$771
$784
$794
$800
$800
.11
.10
.10
.11
.11
.11
35. 6X
35. 8X
35. 7X
35. 6X
35.5X
35. 6X
23.8X
24. OX
23. 9X
23.9X
23. OX
23.8X
Unrestricted
Change
-0.3X
-3.7X
-2. IX
-0.8X
-0.1X
-0.2X
-O.OX
-0.4X
-0.2X
-0.1X
-O.OX
-O.OX
0.1X
0.7X
0.4X
0.2X
O.OX
O.OX
0.1X
0.7X
0.4X
0.2X
O.OX
O.OX
Parameter
$798
$769
$783
$793
$800
$799
.11
.10
.10
.11
.11
.11
35. 6X
35. 8X
35. 7X
35. 6X
35. 6X
35. 6X
23. 8X
24. OX
23. 9X
23. 9X
23. 8X
23.8X
X Change
-0.4X
-4. OX
-2.3X
-1.0X
-0.2X
-0.3X
-O.OX
-0.4X
-0.2X
-0.1X
-O.OX
-O.OX
0.1X
o.ax
0.5X
0.2X
O.OX
0.1X
0.1X
0.7X
0.4X
0.2X
O.OX
0.1X
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: ERG estimates.
-------
TABLE 8-18
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
SELECTED COMBINATIONS OF REGULATORY OPTIONS
oo
l
to
Change In Financial Ratios
Parameters
Working Capital, (a) <$M)
Current Ratio (a)
Long- tern Debt to Equity (b) (X)
Debt to Capital (b) (X)
No
Regulation Regulatory
1986 Dollars Package
$4.15 A
B
C
D
E
F
1.08 A
B
C
D
E
F
168.6X A
B
C
D
E
F
128.8X A
B
C
D
E
F
Restricted
Parameter X
$4.01
$2.52
S3. 24
(3.78
$4.10
$4.07
.08
.05
.06
.07
.08
.08
168. 8X
171. 2X
170.0X
169. IX
168.6X
168.7X
129.0X
130.6X
129. 8X
129. 2X
128. 9X
128. 9X
Unrestricted
Change
-3.2X
-39. 1X
-21. 9X
-8.8X
-1.1X
-1.9X
-0.2X
-3. OX
-1.7X
-0.7X
-0.1X
-0.1X
0.1X
1.6X
0.9X
0.4X
O.OX
0.1X
0.1X
1.3X
0.8X
0.3X
O.OX
0.1X
Parameter
$3.97
$2.39
$3.16
$3.72
$4.07
$4.03
1.08
1.05
1.06
1.07
1.08
1.08
168. 8X
171. 4X
170. 2X
169. 2X
168. 7X
168. 7X
129. OX
130. 7X
129.9X
129.3X
128. 9X
129. OX
X Change
-4.3X
-42.3X
-23.8X
-10. 2X
-1.8X
-2.9X
-0.3X
-3.2X
-1.8X
-0.8X
-0.1X
-0.2X
0.2X
1.7X
1.0X
0.4X
0.1X
0.1X
0.1X
1.5X
0.8X
0.3X
0.1X
0.1X
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: ERG estimates.
-------
to 3 percent decline in working capital, depending on the assumed level of
development. All other ratios change by no more than 0.2 percent for this
regulatory package.
The more expensive regulatory packages have the potential to
substantially impact the working capital for a typical independent oil
company. It must be questioned, however, whether a typical independent would
choose to fund all of these expenditures out of working capital or whether
some mix of working capital and debt would be used.
8-26
-------
SECTION NINE
IMPACTS ON PRODUCTION
The incremental costs of additional pollution control potentially can lead
to a loss in production due to early closure of projects or to projects not being
undertaken. This section presents the methodology used to evaluate the potential
loss in production under the different regulatory options.
9.1 METHODOLOGY
The basic approach is to use the change in the present value of production
due to incremental pollution control costs to estimate the potential loss in
production. We begin by estimating "baseline" production1 -- that is, the
present value of production from all projects before any incremental costs. To
obtain baseline production, production by project is calculated by multiplying
the present value of production for a particular project by the number of such
projects. This number is aggregated over all projects to provide total estimated
production.
Production is then recalculated using the present value of production under
the different regulatory options. Production is set to zero if a project begins
with a positive net present value but has a negative net present value under a
regulatory option. Under these circumstances, the project would either not be
undertaken (NSPS) or would close rather than make the additional investment
(BAT). The recalculated production estimate, then, takes into consideration
early curtailment of projects, immediate project shutdown (BAT), or projects not
undertaken (NSPS).
'Production is expressed in terms of BOE (barrels-of-oil equivalent) in
order to compare both oil and gas production on a common basis. The conversion
factor is based on the heating value of the product. A barrel of oil is 5.8
million BTU and an MMCF of gas is 1,021 million BTU. An MMCF of gas is
equivalent to 176.03 BOE.
9-1
-------
9.2 DRILLING FLUIDS AND DRILL CUTTINGS
No change is seen in the present value of production under any of the
options for drilling fluids and drill cuttings. Nor do the impacts appear so
severe that projects would not be undertaken. Minimal impacts on production are
estimated for this set of effluent guidelines.
93 PRODUCED WATER - BAT
For existing structures, ERG began by comparing the oil and gas production
in barrels-of-oil equivalent (BOE) as estimated by the BAT model projects with
the actual production in 1986. Table 9-1 lists the number of each type of
structure and its associated mid-life production before any additional costs of
pollution control. The approximately 557 million barrels of oil and 3 tcf of gas
are equivalent to approximately 1.09 billion BOE. Offshore production in 1988
was approximately 321 million barrels and 4.3 tcf, or approximately 1.08 billion
BOE (MMS 1989). The estimated amount of energy produced is within 1 percent of
actual production.
Table 9-2 shows the potential loss of production under the various
regulatory options. The Zero Discharge option leads to about a 4.1 percent and
a 4.9 percent decrease in production with membrane and granular filter costs,
respectively. The All Filter option has an associated loss of 1.1 to 1.8
percent. The 4-Mile Filter; BPT Other option has an associated potential loss
ranging from 0.0 to 0.1 percent.
9.4 PRODUCED WATER - NSPS
Table 9-3 shows the potential loss in production from incremental pollution
controls on produced water for new projects.
Under the most reasonable estimate (the $21/bbl - restricted scenario -
membrane filter costs) the impacts on production range from a 0.0 percent loss
under the 4-Mile Filter; BPT Other option to a 0.2 percent loss under the Zero
Discharge and All Filter options. In fact the only situation where a potential
loss in production exceeds 0.2 percent is when injection is required, restricted
development is assumed, and the price of oil averages $15/bbl during the 1986-
2000 time period. The Zero Discharge option, $15/bbl oil price scenario, results
in a large loss in production because the net present value for the Gulf 24 gas-
only projects turns negative with the additional costs. That is, all Gulf 24
9-2
-------
10
I
U)
bat_prd.wk1
TABLE 9-1
ESTIMATED 1988 PRODUCTION FROM BAT STRUCTURES
Project
Oil - only
Gulf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 50
Oil and Gas
Gulf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 50
Pacific 16
Pacific 40
Pacific 70
Gas-only
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific 16
Gulf Production
Pacific Production
TOTAL PRODUCTION
Hunter
f\4
UT
Structures
64
10
41
18
22
5
1
0
220
95
111
126
218
196
2
0
8
6
12
390
250
164
157
104
39
1
Per-Project
Oil (bbl)
75,008
54,020
198,998
298,278
626.340
948,051
1,572,128
68,985
49,640
183.960
275,940
579,620
876.438
1,454,160
1.727,180
4,121,799
8.628.600
Production
Gas (MHCF)
115
83
307
460
967
1.465
2.429
920
2.192
4.577
766
548
2.044
2.847
6,570
9,855
16,863
Production
Oil (bbl)
4.800.480
540,200
8.158,918
5,369,004
13,779,480
4,740,255
1,572,128
15,176,700
4,715.800
20,419,560
34,768.440
126,357,160
171.781,848
2.908,320
13,817,440
24,730,794
103,543.200
415.088.293
142,091,434
557,179.727
Regional
Gas (HMCF) Equivalent (BOE)
25,300
7,885
34,077
57,960
210,806
287,140
4.858
7.360
13,152
54,924
298,740
137,000
335.216
446.979
683.280
384.345
16.863
2.989.022 941.259.235 87X
16.863 145.059.903 13X
3,005.885 1.086,319.138
Source: ERG estimates.
-------
TABLE 9-2
POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
(1986-2000 TIME FRAME)
BAT PRODUCED WATER
Scenario
Total PV of
Product!on
(Millions of BOE)
Potential Loss in Production
(Millions of BOE)
Data
Percent
Baseline
3,946
Zero Discharge Granular Filter Costs 3,754
Membrane Filter Costs 3,786
192
160
-4.9%
-4.1%
All Filter Granular Filter Costs 3,876
Membrane Filter Costs 3,904
70
42
-1.8%
-1.1%
4-Mile Filter; Granular Filter Costs 3,943
BPT Deep
Membrane Filter Costs 3,945
-0.1%
-0.0%
Source: ERG estimates.
9-4
-------
TABLE 9-3
POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
(1986-2000 TIME FRAME)
NSPS PRODUCED WATER
Option
Baseline
Zero Discharge
All Filter
4-Mile Filter;
BPT Deep
Total PV
of
Production
Scenario (Millions of BOE)
S21/bbl
$21/bbl
$21/bbl
S21/bbl
S15/bbl
$32/bbl
$21/bbl
S21/bbl
S21/bbl
$21/bbl
$15/bbl
$32/bbl
$21/bbl
$21/bbl
*21/bbl
$21/bbl
$1S/bbl
$32/bbl
$21/bbt
$21/bbl
$21/bbl
S21/bbl
$15/bbl
*32/bbl
- Restricted
- Restricted (membrane)
- Unrestricted
- Unrestricted (membrane)
- Restricted
- Unrestricted
- Restricted
- Restricted (membrane)
- Unrestricted
- Unrestricted (membrane)
- Restricted
- Unrestricted
- Restricted
- Restricted (membrane)
- Unrestricted
- Unrestricted (membrane)
Restricted
- Unrestricted
- Restricted
- Restricted (membrane)
- Unrestricted
- Unrestricted (membrane)
- Restricted
- Unrestricted
7,776
7,776
9,376
9,376
6,638
12,109
7,759
7,759
9,359
9,359
5,632
12,105
7.759
7.773
9.359
9.373
6,635
12,106
7,775
7.775
9,375
9,375
6,637
12,109
Potential Loss
(Millions
Data
17
17
17
17
1006
4
17
3
17
3
2.9
3.8
0.7
0.7
0.7
0.7
0.7
0.5
in Production
of BOE)
Percent
-0.2X
-0.2X
-0.2X
0.2X
-15. 2X
-O.OX
0.2X
-O.OX
-0.2X
-O.OX
-O.OX
-O.OX
-O.OX
O.OX
-O.OX
-O.OX
O.OX
-O.OX
Note: All scenarios assume granular filter costs except those which state "(membrane)".
Source: ERG estimates.
9-5
-------
gas-only projects are assumed not to be undertaken under these circumstances.
9.5 COMBINED EFFECTS OF SELECTED REGULATORY OPTIONS
Six combinations of options were selected for investigation.
regulatory packages are:
These
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other2
4-Mile Filter; BPT Other
(granular filter costs)
4-Mile Filter; BPT Other
(granular filter costs)
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other1
Zero Discharge
(granular filter costs)
Zero Discharge
(granular filter costs)
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other1
All Filter
(granular filter costs)
All Filter
(granular filter costs)
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other1
All Filter
(membrane filter costs)
All Filter
(membrane filter costs)
Drilling Fluids and Drill Cuttings: 4-Mile Barge; 1,1 Other1
Produced Water - BAT: BPT All
Produced Water - NSPS: BPT All
Drilling Fluids and Drill Cuttings:
Produced Water - BAT:
Produced Water - NSPS:
4-Mile Barge; 1,1 Other1
4-Mile Filter; BPT Other
(membrane filter costs)
4-Mile Filter; BPT Other
(membrane filter costs)
They are referred to as regulatory packages A through F, respectively.
Table 9-4 summarizes the combined impacts on production for the $21/bbl
restricted scenario. The potential loss in production under regulatory package
2Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
9-6
-------
TABLE 9-4
POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
1986-2000 TIME PERIOD
IMPACTS OF COMBINED REGULATORY PACKAGES
$21/bbl - RESTRICTED ACTIVITY
Regulatory
Package Effluent
Effluent
Control
Option
Total PV of
Production
Potential Loss in Production
Data Percent Change
Baseline
Drilling Fluid and Drill Cuttings
Produced Water BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
11.732
11.719
-O.OX
vo
I
-j
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
11.513
209
-1.8X
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter
All Filter
11,636
87
-0.7X
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter - Meafcrane
All Filter - Meabrane
11.677
45
-0.4X
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1.1 Other*
BPT All
BPT All
11,722
O.OX
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other - Membrane
4-Mile Filter; BPT Other Membrane
11,720
-O.OX
Notes:
Under the 4-Mile Barge; 1.1 Other option, Alaska is exempt from the barging
requirement, but must comply with the 1,1 All restrictions.
All produced water control options assume the use of granular filter technology
except options D & F, which assune the use of membrane filtration technology.
Source: ERG estimates.
-------
F is negligible: less than one-tenth of one percent of total production.
Table 9-5 summarizes the same information for the $21/bbl unrestricted
scenario. The potential loss in production under regulatory package F is
negligible: less than one-tenth of one percent of total production.
9.6 REFERENCES
MMS 1989. Federal Offshore Statistics: 1988. Minerals Management Service, MMS
89-0082.
9-8
-------
TABLE 9-5
POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
1986-2000 TIME PERIOD
IMPACTS OF COMBINED REGULATORY PACKAGES
$21/bbl - UNRESTRICTED ACTIVITY
Regulatory
Package Effluent
Effluent
Control
Option
Total PV of
Production
Potential Loss in Production
Data Percent Change
Baseline
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
13.322
13.319
-O.OX
vo
VO
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
4-Mile Barge; 1.1 Other*
All Filter
All Filter
13,113
13.235
209
87
-1.6X
-0.7X
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
13,277
45
-0.3X
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1.1 Other*
BPT All
BPT All
13,322
O.OX
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other - Membrane
4-Mile Filter; BPT Other - Membrane
13,320
-O.OX
Notes:
Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement, but must comply with the 1,1 All restrictions.
All produced water control options assume the use of granular filter technology
except options D 4 F, which assume the use of membrane filtration technology.
Source: ERG estimates.
-------
SECTION TEN
SECONDARY IMPACTS OF BAT AND NSPS REGULATIONS
Although the costs and economic impacts of BAT and NSPS regulations would
fall primarily on the major and independent oil companies, secondary effects
in other sectors of the economy would also occur. In this section, ERG
reviews the potential effects of regulatory costs on Federal revenues, State
revenues, the balance of trade, and support industries. The average annual
cost of the regulations is developed in Section Six.
The impacts are investigated for six packages of regulatory options:
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NPS
4-Mile Barge; 1,1 Other1
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
Drilling Fluids and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other1
Zero Discharge
Zero Discharge
Drilling Fluids and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other1
All Filter
All Filter
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water NSPS
4-Mile Barge; 1,1 Other1
All Filter - Membrane
All Filter - Membrane
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other1
BPT All
BPT All
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other1
4-Mile Filter; BPT Other
Membrane
4-Mile Filter; BPT Other
Membrane
They are referred to as regulatory packages A through F, respectively.
'Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the
barging requirement but must comply with the 1,1 All restrictions.
10-1
-------
10.1 IMPACTS ON FEDERAL REVENUES
Offshore oil and gas activity generates revenue for the Federal government
from sources such as income taxes paid by developers, leasing payments, and
royalties. All of these revenue sources could be affected by effluent
guidelines limitations costs.
It is assumed that companies involved in offshore oil and gas production
have over $100,000 of net income annually, and that their marginal tax rate is
therefore 34 percent. Thus, any expenditure or depreciation item generates a
tax savings of 34 percent of its face value. The Federal government,
therefore, loses 34 percent of the cost of compliance through tax savings to
the company.
Developers could possibly reduce the impact of the "remaining regulatory
costs" (i.e., 66 percent of all costs) by reducing their lease bonus bids.
Since the costs of effluent guidelines limitations and standards can reduce
the return on offshore oil and gas projects, it is logical that operators
would pay less for the right to explore offshore areas. Under the $21/bbl
scenario with restricted activity, an estimated 91 percent of projected
development is allocated to Federal waters (see Table 10-1); therefore, ERG
assumes 91 percent of the remaining costs could be recouped by the company
through lower lease bids on Federal areas.
Table 10-2 lists these potential impacts on Federal revenues. For
example, under regulatory package F (4-Mile Barge; 1,1 Other for drilling
wastes and 4-Mile Filter; BPT Other for produced water) the total annual cost
of the regulation is $54 million (1986 dollars). Revenue lost to the Federal
government through tax savings is $54 x .34 or $18 million. Losses from tax
savings range from $10 million to $367 million under the various regulatory
packages.
There may also be a potential loss of Federal revenue through lower lease
bids. This loss is equal to 91 percent of the remaining cost. For example,
under regulatory package F the potential loss due to lower lease bids equals
($54 minus $18) x .91 or $32 million. Companies may or may not choose to
reduce their bonus bids by the full amount available. Hence, entries in this
column are labeled "potential" losses. The potential losses shown in Table
10-2 are the maximum bid reductions that recoup all cost increases remaining
after the tax savings. The potential losses range from $18 to $649 million
10-2
-------
TABLE 10-1
RATIO OF FEDERAL-TO-STATE PRODUCTION
PROJECTED PRODUCTIVE DEVELOPMENT WELLS IN OFFSHORE REGION (1986-2000)
$21/bbl - RESTRICTED ACTIVITY
Region
Gulf
Pacific
Atlantic
Alaska
Total
Percent of Total
Number of
State Wells
538
0
0
69
607
8.8X
Number of
Federal Wells
5.915
382
0
29
6,326
91. 2X
Total Number
of Productive Wells
6,453
382
0
98
6,933
Note: These counts compare with Table 4-7b for the Gulf and Alaska regions
and with Table 4-16 for the Pacific region.
No activity is assumed for the Atlantic.
10-3
-------
TABLE 10-2
POTENTIAL LOSS OF FEDERAL REVENUES (MILLIONS, 1986 DOLLARS)
IMPACTS OF COMBINED REGULATORY PACKAGES
$21/bbl - RESTRICTED ACTIVITY
Regulatory
Package
Effluent
Effluent
Control
Option
Revenue Loss Potential
Due to Revenue Loss
Total Annual Tax Effects of Due to
Cost Effluent Guidelines Lower Lease Bids
Total Potential
Revenue Loss to
Federal Government
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - MSPS
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
$88
$30
$53
$82
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
$1,081
$367
$649
$1,017
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter
All Filter
$605
$206
$363
$569
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter - Membrane
All Filter - Membrane
$242
$82
$145
$228
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
BPT All
BPT All
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other -Mem
4-Mile Filter; BPT Other -Mem
$30
$54
$10
$18
$18
$32
$28
$50
Notes:
Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt from the barging
requirement but must comply with the 1,1 All restrictions.
All produced water control options assume the use of granular filter technology
except options D & F, which assume the use of membrane filtration technology.
Source: ERG estimates.
-------
dollars. The total potential revenue loss to the Federal government ranges
from $28 million to $1,017 million.
Table 10-3 lists the results of recent OCS sales. In 1986, only $187
million was received in bonuses in two lease sales in the Gulf. This was the
lowest level of bonus receipts for several years. Interest picked up again in
1987, when two lease sales in the Gulf brought in $535 million in apparent
high bids. In 1988, OCS sales brought in $1,209 million in bonuses. The
potential loss in Federal revenues due to lower lease bids and tax savings to
the companies (from Table 10-2) ranges from 2 to 84 percent of the 1988
bonuses. These losses, however, are only potential losses; that is, companies
may choose not to recoup all cost increases through lower bonus bids.
The third source of potential loss is the loss of royalties due to early
closure of projects or projects not undertaken. This source would be
reflected as a loss of royalties due to a potential loss in future production.
Section Nine investigates potential loss of future production. Assuming
$21/bbl and restricted development, the potential loss in production from
regulatory package F is negligible. Similarly, impacts on royalties would be
expected to be negligible.
10.2 IMPACTS ON STATE REVENUES
Industry could reduce the impacts of the cost of compliance with new
regulations by reducing lease bonus bids on State tracts. The well
projections estimate that 9 percent of future offshore activity will take
place in State waters (see Table 10-1). Potential loss in revenue for the
states is calculated as the cost of the regulatory package times the
percentage borne by the industry (i.e., not including the 34 percent tax
savings) times the portion of development that takes place in State waters.
Under regulatory package F, the calculation is $54 x .66 x .09 or $3 million
(1986 dollars). Table 10-4 summarizes these costs, which range from $2 to $64
million.
These losses are only potential; companies may not choose to recoup all
cost increases through lower lease bids. In addition, the potential losses,
should they occur, would be spread among several states. New wells are
projected for Alaska, the Pacific, and the Gulf of Mexico. Under the $21/bbl
restricted development scenario, the only drilling that occurs in California
State waters is on existing leases. California, then, would not suffer any
10-5
-------
TABLE 10-3
RECENT DCS LEASE SALES
Sale
104
105
110
112
97
113
109
115
92
116
Date
April 1986
August 1986
April 1987
August 1987
March 1988
March 1988
May 1988
August 1988
October 1988
November 1988
Region
Central Gulf of Mexico
Western Gulf of Mexico
Central Gulf of Mexico
Western Gulf of Mexico
Beaufort Sea, Alaska
Central Gulf of Mexico
Chukchi Sea, Alaska
Western Gulf of Mexico
N. Aleutian, Alaska
Eastern Gulf of Mexico
Bonuses
Accepted
((Million)*
$130.3
S56.8
S292.6
$242.8
$114.6
$388.7
$478.0
$125.4
$95.4
$6.4
Annual
Total
($Million)»
$187.1
$535.4
$1,208.5
* Current dollars.
Source: KHS, 1989.
10-6
-------
TABLE 10-4
POTENTIAL IMPACT OF COMPLIANCE COSTS ON STATE REVENUES
SMILLIONS. 1986 DOLLARS
$21/bbl - RESTRICTED ACTIVITY
Regulatory
Package Effluent
Effluent
Control
Option
Total Annual
Cost
Potential
Revenue Loss
Due to
Lower Lease Bids
Drill ing Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mlle Barge; 1,1 Other*
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
Zero Discharge
Zero Discharge
$1,081
S64
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
All Filter
All Filter
$605
$36
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1.1 Other*
All Filter - Membrane
All Filter - Membrane
$242
$14
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other*
BPT All
BPT All
4-Mile Barge; 1,1 Other*
4-Mile Filter; BPT Other -Membrane
4-Mile Filter; BPT Other -Membrane
$30
$54
$2
$3
* Under the 4-Mile Barge; 1,1 Other option, Alaska is exempt fro» the barging
requirement but must comply with the 1,1 All restrictions.
Notes: All produced Mater control options assume the use of granular filter technology
except options D ( F, which assume the use of aienbrane filtration technology.
Entries may not sin due to independent rounding.
Source: ERG estimates.
-------
loss of bonus revenue due to increased pollution controls. Affected states
could include Alaska, Texas, Louisiana, Mississippi and Alabama.
The example of Texas illustrates the potential impacts on State income.
In 1985, Texas produced 2.175,630 bbl of oil and 108,130,195 Mcf of gas from
offshore State wells. In the same year, the other major producing state in
the Gulf of Mexico, Louisiana, produced 23,747,805 bbls of oil and 229,971,735
Mcf of gas from offshore State wells (MMS, 1986). These figures convert to
21,210,361 barrels-of-oil equivalent (BOE) for Texas and 64,230,760 BOE for
Louisiana. Texas therefore generated 25 percent of State offshore production
in the Gulf of Mexico in 1985, while Louisiana produced the remaining 75
percent.
Table 10-5 shows the calculation to estimate the potential revenue loss
through lower bonus bids. The estimated loss is the product of four factors:
Proportion of cost not shielded by tax savings on expensed and
depreciated items.
Portion of project occurring in State waters.
Portion of State water activity occurring in the Gulf of Mexico.
Portion of Gulf of Mexico State water activity occurring in Texas.
The last parameter is the proportion of 1985 Gulf of Mexico State water
production occurring in Texas State waters. The potential loss ranges from
$0.4 to $14,2 million (1986 dollars).
Table 10-6 presents total income to Texas from oil and gas bonuses and
from all sources for 1984 through 1989. Texas received $25 million in lease
bonus revenues in 1986 and more in 1988. Potential losses range from 2 to 56
percent of 1986 bonuses. Total State revenues for 1986 are $17,952 million;
compared to total State revenues, the impact of the most expensive regulatory
package is less than 0.01 percent.
Tables 10-7 and 10-8 repeat the calculations for Louisiana, whose fiscal
year runs from 1 July to 30 June. The potential loss in revenue ranges from
$1.2 to $42.7 million. Louisiana's income from bonuses fell from $60 million
in fiscal year 1984-1985 to $26.0 million in 1985-1986 to $12 million in 1986-
1987, due, in part, to the crash in oil prices. The data from the most recent
two years indicate how this sector of the economy has begun to recover.
10-8
-------
TABLE 10-5
POTENTIAL IMPACT OF COMPLIANCE COSTS ON TEXAS STATE REVENUES
SMILLIONS, 1986 DOLLARS
$21/bbl -RESTRICTED
Regulatory
Package
A
B
C
D
E
F
Effluent
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Effluent
Control
Option
4-Mile Barge; 1,1 Other
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
4-Mile Barge; 1,1 Other
Zero Discharge
Zero Discharge
4-Mile Barge; 1,1 Other
All Filter
All Filter
4-Mile Barge; 1,1 Other
All Filter - Membrane
All Filter - Membrane
4-Mile Barge; 1,1 Other
BPT All
BPT All
4-Mile Barge; 1,1 Other
4-Mile Filter; BPT Other -Mem
4-Mile Filter; BPT Other -Mem
Proportion
of Cost Not
Total Shielded by
Annual Federal Tax
Cost Savings
$88 0.66
$1,081 0.66
$605 0.66
$242 0.66
$30 0.66
$54 0.66
Portion of
Projected
Development
in State
Waters
0.09
0.09
0.09
0.09
0.09
0.09
Portion of
State Water
Development
in Gulf of
Mexico
0.89
0.89
0.89
0.89
0.89
0.89
Portion of
GOM State
Water
Development
in Texas Water
0.25
0.25
0.25
0.25
0.25
0.25
Potential
Revenue Loss
Due to
Lower
Lease Bids
$1.2
$14.2
$8.0
$3.2
$0.4
$0.7
Note: Entries may not sum due to independent rounding.
Source: ERG estimates.
-------
TABLE 10-6
TOTAL TEXAS STATE REVENUES AND BONUS REVENUES
Year
1985
1986
1987
1988
1989
Bonus Revenues*
(SMill ion)
$60.3
$25.4
$18.4
$26.0
$24.3
Total State Revenues*
(Will ion)
$16,980
$17,952
$17,524
$20,357
$21,479
* Current dollars.
Source: Plaut, 1990.
10-10
-------
TABLE 10-7
POTENTIAL IMPACT OF COMPLIANCE COSTS ON LOUISIANA STATE REVENUES
SMILLIONS. 1986 DOLLARS
*21/bbl -RESTRICTED
Regulatory
Package
Effluent
Effluent
Control
Option
Proportion Portion of Portion of Portion of Potential
of Cost Not Projected State Water COM State Water Revenue Loss
Total Shielded by Development Development Development in Due to
Annual Federal Tax in State in Gulf of Louisiana Lower
Cost Savings Waters Mexico Water Lease Bids
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other
4-Mile Filter; BPT Other
4-Mile Filter; BPT Other
$88
0.66
0.09
0.89
0.75
$3.5
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1.1 Other
Zero Discharge
Zero Discharge
$1,081
0.66
0.09
0.89
0.75
$42.7
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other
All Filter
All Filter
$605
0.66
0.09
0.89
0.75
$23.9
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1,1 Other
All Filter - Membrane
All Filter - Membrane
$242
0.66
0.09 0.89
0.75
$9.6
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
Drilling Fluid and Drill Cuttings
Produced Water - BAT
Produced Water - NSPS
4-Mile Barge; 1.1 Other $30
BPT All
BPT All
4-Mile Barge; 1,1 Other $54
4-Mile Filter; BPT Other -Mem
4-Mile Filter; BPT Other -Mem
0.66
0.66
0.09 0.89
0.09 0.89
0.75
0.75
$1.2
$2.1
Note: Entries may not sum due to independent rounding.
Source: ERG estimates.
-------
TABLE 10-8
TOTAL LOUISIANA STATE REVENUES AND BONUS REVENUES
Year
1984-1985
1985-1986
1986-1987
1987-1988
1988-1989
Bonus Revenues*
(Million)
$59.7
$26.0
$12.1
$27.7
$U.7
Total State Revenues*
(Million)
$8,804
$8,800
$9,306
$9,105
$10,186
* Current dollars.
Source: Hoppenstedt, 1990.
10-12
-------
Bonuses were $28 million in 1987-1988 and $15 million in 1988-1989. For some
of the regulatory packages, the potential loss in revenues exceeds actual
bonus revenues for some years. For package F, the potential revenue loss
represents about 17 percent of bonus revenues for 1986-1987 (the lowest bonus
revenue of the series). The impact of the most expensive regulatory package
(package B) on total State revenue for 1985-1986 (the lowest total revenue in
the series), however, is still less than 0.5 percent.
The second source of potential loss is the loss of royalties and severance
taxes due to early closure of projects or projects not undertaken. This
source would be reflected as a loss of royalties due to a potential loss in
future production. Section Nine investigates the potential loss of future
production. The potential loss in production from regulatory package F is
negligible; thus, impacts on royalties would be expected to be negligible as
well.
10 J IMPACT ON BALANCE OF TRADE
The United States is rapidly approaching the time when we are a nation
that imports more oil than it produces. The Department of Energy projects
this time to arrive in 1994 (DOE, 1989), but is already happening sporadically
on a monthly basis. For example, in January 1990, the United States imported
54 percent of our domestic demand for oil and gas (OGJ, 1990a). The recent
increase in oil prices due to the Mideast crisis is also not expected to
prevent a decline in domestic oil production. A shortage of trained personnel
and workover rigs are factors cited as limiting any near-term sizable increase
in domestic production (OGJ, 1990b; OGJ, 1990c; and OGJ, 1990d). In other
words, unless domestic demand for oil is curbed, the United States will
continue to import a growing percentage of its domestic oil consumption. This
phenomenon is occurring in absence of any incremental pollution control costs.
The potential loss in production is investigated in Section Nine. Even
under regulatory package B with the highest projected costs, production
declines over the entire 15-year period do not exceed 1.8 percent. This is a
small percentage compared to the estimated annual decline in domestic
production of about 3 percent seen in the DOE projections (DOE, 1989). In
other words, the change in the balance of trade expected from this regulatory
effort will not be significant compared to changes caused by outside factors.
10-13
-------
10.4 IMPACTS ON SERVICE INDUSTRIES
In addition to major and independent oil companies, a third group of
companies provides a variety of specialized services to the offshore oil and
gas developers. These firms construct, own, and operate mobile drilling rigs;
fabricate and install offshore platforms; provide geophysical, drilling mud,
and well logging services; build and install pipelines to transport oil and
gas from platforms to onshore terminals; and own and operate boat and
helicopter fleets that provide support services to offshore drilling rigs and
platforms.
Regulatory costs can be incurred through increased barite costs, barging
of spent drilling fluids and cuttings, or capital and annual operating costs
required for the disposal of produced water. Drilling fluid suppliers are
assumed to operate in a competitive market and will, therefore, pass on any
cost increases that occur with the use of "clean" barite. Since the well
operators are the ones who purchase the drilling fluid and disposal equipment,
they will ultimately bear the cost. The Agency also assumes that whatever
cost is incurred in the barging of drilling wastes is paid for by the
operators.
All costs, then, are assumed to be passed through to the operator. Under
these conditions, no negative impacts are incurred by the service industries.
Sections Seven and Eight examine the impacts on individual projects and
representative companies, respectively. In addition, when the regulations
become effective, activity for the service industry will increase due to the
need to retrofit existing facilities. In this respect, the regulations could
lead to a temporary positive impact on the service industry.
10.5 IMPACTS ON INFLATION
The regulations can lead to higher costs to the operators. When
evaluating this effect on typical companies, ERG did not assume that they
could raise prices to recover these costs. This is because the price that the
companies will receive for their product is determined by the world oil price
and not domestic costs. Given our nation's continued growth in demand, supply
(and therefore price) is still largely controlled by the behavior of the OPEC
members (see DOE, 1989 and Harvard, 1988). Because of the inability of the
companies to raise prices in response to increased costs, we do not see
10-14
-------
substantial impacts on inflation from increased cost of pollution controls on
offshore oil and gas effluents. We investigated the impacts on the companies
(Section Eight) and the impacts on production (Section Nine) under this set of
assumptions.
10.6 REFERENCES
DOE 1989. Annual Energy Outlook: Long-term Projections 1989. Department of
Energy, Energy Information Agency, DOE/EIA-0383(89), January 1989.
Harvard 1988. Lower Oil Prices: Mapping the Impact. Harvard University,
Energy and Environmental Policy Center, 1988.
Hoppenstedt 1990. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and David Hoppenstedt, Louisiana State Budget
Office, Baton Rouge, LA, March 8, 1990.
MMS 1986. Gulf of Mexico Summary Report/Index. November 1984 - June 1986.
Minerals Management Service, MMS 86-0084, Tables 17 and 18.
MMS 1989. Federal Offshore Statistics: 1988. Minerals Management Service, MMS
89-0082, Table 2.2
OGJ 1990a. "OGJ Newsletter," Oil and Gas Journal. February 19, 1990.
OGJ 1990b. "Despite Output Push, U.S. Probably Cannot Avoid Oil Production
Decline in 1991", Oil and Gas Journal. September 17, 1990, pp.21-24.
OGJ 1990c. "W. Coast Best Potential for Output Hike Soon", Oil and Gas
Journal. October 1, 1990, pp.38-42.
OGJ 1990d. "U.S. Oil Flow Hike Unlikely Outside W. Coast", Oil and Gas
Journal. October 15, 1990, pp. 32-36.
Plaut 1990. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and Tom Plaut, Economic Analysis Department, Texas
Comptroller's Office, Austin, TX, March 8, 1990.
10-15
-------
SECTION ELEVEN
SINGLE WELL STRUCTURES IN THE GULF OF MEXICO
The smallest project examined in the analysis is a structure with a
single well. ERG developed two economic models for single well structures --
those which do not have production equipment and those which do. The models
are called "Gulf la" and "Gulf Ib," respectively. (Single well structures
currently exist only in the offshore Gulf of Mexico.) Gulf la structures are
assumed to share production equipment and increased pollution control costs
with three other structures. Gulf Ib structures are assumed not to.be able to
share costs. For example, each Gulf Ib structure is assumed to bear the
entire cost of an injection well under the Zero Discharge option.
Because of its small size, the Gulf Ib is the most vulnerable of
economic models to the impacts of additional pollution control costs. It is
the only project for which the net present value (NPV) has the potential to
change from positive in the baseline case to negative when incremental costs
of additional pollution controls on produced water are added (see Section
Seven).1 This change is modeled as a complete shut-down of the project for
the analysis of the impacts on production (see Section Nine). That is,
existing projects are assumed to shut down rather than undertake the capital
investments of added pollution control, and new projects are considered not to
go into production. The change in the sign of the NPV, however, occurs only
for the Gulf Ib (a single well structure with its own production equipment)
and only in limited circumstances.
Examining Tables 7-9 and 7-16, the Gulf Ib shuts down in the following
cases:
BAT
Zero Discharge
Offshore, both granular and membrane costs
Onshore, granular costs
'Even under the Zero Discharge option for drilling fluids and drill
cuttings, the net present value of the Gulf Ib project remains positive. The
discussion, then, focuses on pollution controls for produced water.
11-1
-------
. NSPS
Zero Discharge
Offshore, both granular and membrane costs
Onshore, granular costs
Filtration
Granular filter costs only
In other words, no shutdowns are projected under the 4-Mile Filter; BPT Other
option for BAT structures, regardless of the costing assumptions. For NSPS
structures, shutdowns are projected only under the higher costs associated
with granular filter technology. No shutdowns are projected under membrane
.cost assumptions. Projects may still be undertaken but may have a shorter
economic lifetime due to increased annual operating costs. Potential losses
from projects with curtailed lifetimes are examined in Section Nine and are
minimal for the 4-Mile Filter; BPT Other option.
Even though the Gulf Ib structures undergo closure or are not undertaken
only in a limited set of circumstances, and these circumstances .are not the
preferred option in the rulemaking, this section examines the:
Number of Gulf Ib structures.
Estimated production from Gulf Ib structures.
Relative contribution from Gulf Ib structures to total production
from Federal offshore leases and to total U.S. production (onshore
and offshore).
We also examined the ownership of the existing structures as it appears in the
March 1988 version of the MMS Platform Inspection System, Complex/ Structure
data base.
The purpose of the examination is to evaluate the potential loss of
production from these structures. An exemption for such structures would not
be made to encourage the proliferation of single-well structures for the sole
purpose of avoiding additional pollution control costs. The purpose of the
exemption would be to allow the economic recovery of oil and gas from small
fields that can adequately be drained by a single well. For example, if
information for a particular field indicates that the reserves are greater
than originally thought, and that a second well could be added to drain the
reservoir, the first well could be required to tie into the pollution control
equipment of the second well for the field since the field was no longer in
the "single well size" category.
11-2
-------
11.1 BAT STRUCTURES
The number of structures in production in the Gulf of Mexico is taken
from the MMS Platform Inspection System, Complex/Structure data base as of
March 1988. Table 11-1 summarizes this information. Appendix H describes the
data cleaning and categorization processes used to develop these counts from
the MMS data base. There were approximately 2,233 structures in production in
the Gulf, of which 355 or about 16 percent were classified as Gulf Ib
structures. The estimated production in the Gulf is approximately 415 million
barrels of oil and 3 tcf of gas (see Table 11-2). Production from Gulf Ib
structures is estimated to be approximately 5.3 million barrels of oil and 145
bcf of gas.
Table 11-3 compares the production from all Gulf Ib structures with the
estimated production in the Gulf, the actual 1988 production from Federal
offshore leases, and the total 1988 U.S. production (both onshore and
offshore). Production from Gulf Ib structures corresponds to 1.3 and 4.8
percent of the estimated oil and gas production for the Gulf, respectively.
The Gulf of Mexico produces nearly all the gas and most of the oil from
Federal offshore leases (see Table 11-2 and MMS 1989). Estimated production
from Gulf Ib structures is approximately 2 and.3 percent of actual 1988
production from Federal offshore leases. Total 1988 U.S. production was 3
billion barrels of crude oil (API 1990, Section IV, Table 3a) and 17.8 tcf of
gas (DOE 1989, Table 3). Production from Gulf Ib structures is less than 1
percent of total U.S. production.
About 25 percent of the Gulf Ib structures are connected to another
structure by at least a catwalk.2 Our assumption that these structures would
serve only "one well" fields is therefore conservative. The MMS Complex/
Structure data base also contains the operator of the structure. The 1988
U.S.A. Oil Industry Directory was used to identify major and independent oil
companies (PennWell 1988). Combining the information from these two sources,
ERG identified about two-thirds of these structures as having major oil
2In the MMS data base, a complex may be made up of one or more structures
as long as the structures are connected by some means, e.g., a catwalk. Each
complex has a unique identification number given by the MMS. In addition to the
complex identification number, each structure in the complex is given a number,
beginning with "1". Of the 355 Gulf Ib structures, 89 have structure numbers
higher than one. This means that the single well structure is connected to at
least one other structure in some manner.
11-3
-------
TABLE 11-1
EXISTING STRUCTURES BY REGION
08-Feb-91
NUMBER Of STRUCTURES
Structure
Type
Oil Only Oil Only
<= 4 miles > 4 miles
Oil and Gas
<= 4 miles
Oil and Gas
> 4 miles
Gas Only
<= 4 miles
Gas Only Total Total
> 4 miles <= 4 miles> 4 miles
Total
33333333S33S33SS33SS32222333333S5S323333332SS3333333333333===333333:22S332SSSSS333S33533333333==33=23SS3SS3S3=S32
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Gulf Totals
26
1
23
0
0
0
0
0
50
38
9
18
18
22
5
1
0
111
27
13
10
2
3
8
0
0
63
193
82
101
124
215
188
2
0
905
53
22
8
1
0
0
0
0
84
337
228
156
156
104
39
0
0
1,020
106
36
41
3
3.
8
0
0
568
319
275
298
341
232
3
0
674
355
316
301
344
240
3
0
197 2,036 2,233
Pacific
Pacific
Pacific
Pacific
16
40
70
Totals
0
0
0
0
Atlantic
Alaska
Totals
0
0
0
0
No existing
7
0
4
11
facilities
No facilities that do not
50
111
74
1
6
8
15
already re- inject
920
0
0
0
0
produced
84 1,
1
0
0
1
water
021
7
0
4
11
208
2
6
8
16
2,052
9
6
12
27
2,260
Note: Structures in the Gulf of Mexico have been classified according to the number of producing wells.
Structures in the Pacific have been classified according to the number of wellslots.
Source: MMS, 1988; CCC, 1988; SAS printout kre_bat6.out; SAS runs dated July 1990.
11-4
-------
bat_prd.wk1
TABLE 11-2
ESTIMATED 1988 PRODUCTION FROM BAT STRUCTURES
Project
Oi 1 - only
Gulf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 50
Oi I and Gas
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 50
Pacific 16
Pacific 40
Pacific 70
Gas-only
Gulf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific 16
Gulf Production
Pacific Production
TOTAL PRODUCTION
Number
nf
UT
Structures
64
10
41
18
22
5
1
0
220
95
111
126
218
196
2
0
8
6
12
390
250
164
157
104
39
1
Per-Project
Oil (bbl)
75,008
54,020
198,998
298.278
626,340
948,051
1,572,128
68,985
49,640
183,960
275,940
579,620
876,438
1,454,160
1,727,180
4,121,799
8,628,600
Production
Gas (HMCF)
115
83
307
460
967
1.465
2,429
920
2,192
4,577
766
548
2,044
2,847
6,570
9,855
16,863
Production
Oil (bbl)
4,800,480
540,200
8.158,918
5,369,004
13,779,480
4,740,255
1,572,128
15,176,700
4,715,800
20,419,560
34,768,440
126,357,160
171,781,848
2,908.320
13.817,440
24,730,794
103.543.200
415.088,293
142.091,434
557.179.727
Regional
Barrels-of -oi I
Gas (MMCF) Equivalent (BOE)
25,300
7.885
34,077
57,960
210,806
287, 140
4,858
7,360
13,152
54,924
298,740
137.000
335.216
446.979
683,280
384,345
16.863
2,989.022 941,259,235 87X
16.863 145,059,903 13%
3,005.885 1,086,319,138
Source: ERG estimates.
-------
TABLE 11-3
COMPARISON OF PRODUCTION FROM BAT GULF 1B STRUCTURES TO REGIONAL AND U.S. PRODUCTION
Parameter
Oi I Gas
(Millions (Trillions
of Barrels) of Cubic Feet)
Percentage
Oi I Gas
Estimated Production from all Gulf 1b Structures
5.3
O.H5
Estimated Production from Gulf Structures 415.1
1988 Production from Federal Offshore Leases (Actual) 320.7
1988 U.S. Onshore and Offshore Production (Actual) 2,979.0
3.0
4.3
17.8
1.3X
1.6X
0.2X
4.8X
3.4X
0.8X
Estimated Production from Gulf 1b Structures
within 4 miles of Shore
0.7
0.013
Estimated Production from Gulf Structures 415.1
1988 Production from Federal Offshore Leases (Actual) 320.7
1988 U.S. Onshore and Offshore Production (Actual) 2.979.0
3.0
4.3
17.8
0.17X
0.22X
0.02X
0.43X
0.30X
0.07X
Sources: ERG estimates; MMS, 1989; API, 1990; and DOE, 1989.
-------
companies as operators in March 1988. The majority of the operators, then,
are large major oil companies.
One option under consideration is to require that structures within 4
miles of shore filter produced water before discharge. In the data set
examined, only 36 Gulf Ib structures are located within 4 miles of shore. Of
these, 31 structures are not connected to another structure and are therefore
unlikely to be able to share costs. As in the general Gulf Ib population,
about two-thirds of the Gulf Ib structures within 4 miles of shore are
operated by major oil companies.
The estimated production from this subset of Gulf Ib structures is about
700 thousand barrels of oil and 13 bcf of gas. These amounts represent about
0.2 percent and 0.4 percent of the estimated Gulf oil and gas production,
respectively (see Table 11-3, lower half). Compared to actual 1988 production
from Federal offshore leases, the estimated production from Gulf Ib structures
is 0.2 percent and 0.3 percent for oil and gas, respectively. Estimated
production from this subset of Gulf Ib structures accounts for less than 0.1
percent of total U.S. production in 1988.
In other words, assuming that all Gulf Ib structures within 4 miles of
shore shut down rather than incur the costs of additional pollution control,
the potential production loss is less than 0.5 percent of Federal offshore
production. Compared to overall U.S. production, the potential loss from Gulf
Ib structures is less than 0.1 percent (0.02 percent loss for oil and 0.07
percent loss for gas). In other words, comparatively little production would
be protected by an exemption for single well structures within 4 miles of
shore.
Exempting Gulf Ib structures under the 4-Mile Filter; BPT Other option
would decrease the cost of that option by $1.7 million, from $12.9 million to
$11.2 million dollars; a decrease of 13 percent. These are membrane filter
costs. For granular filter costs, exempting Gulf Ib structures under the same
option would decrease the cost by $3.2 million, from $41.2 million dollars to
$38 million dollars. This is an 8 percent decrease in the cost of the option.
11-7
-------
11.2 NSPS STRUCTURES
In the $21/bbl oil price, restricted development scenario, 755
structures are projected for the Gulf of Mexico during the 1986-2000 time
period (Table 11-4) including 76 Gulf Ib structures. There are no oil-
producing Gulf Ib structures projected within 4 miles of shore.3 Therefore,
an exemption for Gulf Ib structures within 4 miles would show no savings in
oil production.
There are 23 Gulf Ib gas-only structures projected within 4 miles of
shore. These structures are assumed to have a peak production rate of 4
MMcf/day or 1.46 bcf/year. If all 23 structures went into production in the
same year, the first year's production would total 33.6 bcf. This is less
than 1 percent of the 1988 gas production Federal offshore leases and less
than 0.2 percent of total 1988 U.S. gas production. No more than two
structures within 4 miles of shore are assumed to go into production in any
year during the 1986-2000 time frame, so impacts are probably an order of
magnitude less.
Exempting Gulf Ib structures under the 4-Mile Filter; BPT Other option
would decrease the cost of that option by $0.8 million, from $10.7 million to
$9.9 million dollars. This is based on membrane filter costs and represents a
decrease of 8 percent. Assuming granular filter costs for the same option,
exempting Gulf Ib structures would decrease the cost by $1 million, from $16.5
million dollars to $15.5 million dollars. This is a 6 percent decrease in the
cost of the option.
113 COMBINED EFFECTS
The cost for regulatory package F is $54 million in 1986 dollars. This
package combines the 4-Mile Barge; 1,1 Other option for drilling wastes with
the 4-Mile Filter; BPT Other option for produced water. The cost of the
package is based on membrane filter technology costs. Exempting Gulf Ib
structures from pollution control measures beyond current permit requirements
for produced water would decrease the cost of the option by about $2.5 million
or about 5 percent. No severe adverse impacts were seen for this regulatory
'This is not to say that there will be no new single well structures within
4 miles of shore. They are assumed to share production equipment and are
included in the projections of 4-well structures for the purposes of estimating
impacts.
11-8
-------
TABLE 11-4
NSPS STRUCTURE ALLOCATIONS
RESTRICTED ACTIVITY
$21/bbl SCENARIO
All Platforms
Region
Gulf
Pacific
Atlantic
Alaska
Model
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 40
Pacific 70
Pacific Totals
Atlantic 24
Cook Inlet 12
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms - All Regions
Total
76
235
123
180
114
27
755
3
4
7
0
1
1
2
4
766
Oil
12
89
34
84
62
27
308
3
4
7
0
0
1
2
3
318
Gas
64
146
89
96
52
0
447
0
0
0
0
1
0
0
1
448
Within 4-Miles
Total
23
60
43
14
0
0
140
0
0
0
0
0
0
2
2
142
Oil
0
27
15
14
0
0
56
0
0
0
0
0
0
2
2
58
Gas
23
33
28
0
0
0
84
0
0
0
0
0
0
0
0
84
Beyond 4-Miles
Total
53
175
80
166
114
27
615
3
4
7
0
1
1
0
2
624
Oil
12
62
19
70
62
27
252
3
4
7
0
0 '
1
0
1
260
Gas
41
113
61
96
52
0
363
0
0
0
0
1
0
0
1
364
Oil only; all other projects are assumed to produce oil and casinghead gas.
11-9
-------
package in the preceding sections. A 5 percent reduction in total cost would
not significantly change impacts already examined. In addition, the effect on
production is already minimal for this option (see Section Nine), and
exempting the Gulf Ib structures would.not affect this result.
11.4 REFERENCES
API 1990. Basic Petroleum Data Book. American Petroleum Institute, Volume X,
Number 3, September 1990.
CCC 1988. Oil and Gas Activities Affecting California's Coastal Zone.
California Coastal Commission,2nd edition,December 1988.
DOE 1989. Natural Gas Annual 1988: Volume 1. Department of Energy, Energy
Information Agency, DOE/EIA-0131(88)/1, October 1989.
MMS 1988. Platform Inspection System, Complex/Structure data base, developed
and maintained by the Minerals Management Service, magnetic media,
files dated March 1988.
MMS 1989. Federal Offshore Statistics: 1988. Minerals Management Service,
OCS Report, MMS 89-0082.
PennWell 1988. U.S.A. Oil Industry Directory 1988. PennWell Directories,
PennWell Publishing Company, Tulsa, OK, January 1988.
11-10
-------
SECTION TWELVE
SMALL BUSINESS ANALYSIS
Public Law 96-354, known as the Regulatory Flexibility Act, requires EPA
to determine if a significant impact on a substantial number of small
businesses occurs as a result of proposed regulations. If there is a
significant impact, the act requires that alternative regulatory approaches
that mitigate or eliminate economic impacts on small businesses be examined.
Various definitions of small businesses are used by Federal agencies in
procurement activities and regulatory analysis (47 CFR 121.3). These
standards are based on number of employees or sales volume. Employee
standards of 100, 200, 250, and 500 have been used. Sales standards of
$100,000, $1,000,000, $2,500,000 and $7,500,000 have also been employed. The
Small Business Administration uses a standard of 250 employees for the oil and
gas extraction point-source category (SIC 1311).
Production companies would incur the direct regulatory impact of BAT and
NSPS. As previously established in Section Three, production companies are
generally large corporate or large independent firms. Revenues for a typical
independent oil company were $160 million in 1985 while in 1986, revenues for
a typical major are estimated at $35.3 billion. Large majors and large
independents each typically employ well over 500 people. Both these measures
indicate that energy production companies are not small businesses. Therefore
a formal Regulatory Flexibility Analysis (RFA) is not required.
12-1
-------
APPENDIX A
SELECTION OF OFFSHORE OIL AND GAS PROJECTS
Offshore oil and gas platforms vary by size, volume of production, type of
production, and geographic location. Platform sizes range from one well, in
Gulf of Mexico installations, to approximately 100 wells at artificial islands
off the northern coast of Alaska. The volume of production on a platform
ranges from several barrels a day to over 100,000 barrels per day. A given
platform may produce oil, both oil and gas, or only gas. Platform locations
include the Gulf of Mexico, the Pacific, and Cook Inlet, Alaska. Production
began from artificial islands in 1987 in the Beaufort Sea region of Alaska.
Future production may occur in other Arctic regions and off the Atlantic
Coast.
The economics of oil and gas production and pollution control differ among
platforms because of this variability of platform features. To capture these
differences, representative model projects have been developed for the various
geographical areas. The projects reflect variations in three parameters:
Geographic region
Size (number of wellslots)
Type of production (oil, gas, or both)
The model projects have been reviewed and updated from those described in
Economic Impact Analysis of Proposed Effluent Limitations and Standards for
the Offshore Oil and Gas Industry (ERG, 1985).
A.1 GENERAL PARAMETER CATEGORIES
The model projects presented below reflect three key factors: geographic
region, size, and.production type. In all, 34 model projects are presented.
They characterize the range of platform types expected to be installed during
the study period.
A-l
-------
A. 1.1 Geographic Region
Offshore oil and gas deposits are known or are posited for:
Atlantic - North, Mid- and South Atlantic
Gulf of Mexico - offshore Florida, Alabama, Mississippi, Louisiana, and
Texas
Pacific - California, Oregon and Washington
Alaska - Beaufort Sea, Chukchi Sea, Hope Basin, Norton Basin, St.
Matthew Hall, Navarin Basin, Aleutian Basin, Bowers Basin, Aleutian
Arc, St. George Basin, North Aleutian Basin, Cook Inlet, Shumagin,
Kodiak, and Gulf of Alaska
These areas are shown in Figures A-l and A-2.
These four regions -- Atlantic, Gulf, Pacific, and Alaska -- differ
significantly with respect to the principal factors affecting offshore
economics (geology, depth, weather, productivity, etc.). They are also
geographically separate. Accordingly, models are developed for each of the
four regions. Within Alaska, weather and geologic conditions vary from region
to region, so projects are developed for four separate areas of the state --
Cook Inlet, Beaufort Sea, Norton Basin, and Navarin Basin.
A.1.2 Number of Well Slots
Platform size is the second key variable. Model projects within the
regions are designed to reflect the different sizes of existing and planned
structures.
For the Gulf, the selection of model structure sizes is based on the
information in the MMS Platform Inspection System, Complex/Structure Data Base
as of March 1988. Table A-l summarizes the number of structures in the Gulf
of Mexico by the number of available wellslots. The most predominant is a
single wellslot structure where four out of five have no production equipment.
Given the large number of these structures we model a "Gulf la" as a single
well structure with no production equipment and a "Gulf Ib" as a single well
structure with production equipment. Other projects chosen to represent the
region are structures with 4, 6, 12, 24, 40, and 58 wellslots. The larger
structures are expected to become more prevalent in the deeper waters.
A-2
-------
130' 11*
r/
110' !!» 110' I0»' 100- » io» » to-
/ OCS PLANNING AREAS
Figure A-l. OCS Planning Areas: Lower 48 States
Source. 5-Year Leasing Program Mid-1987 to M_id-_199_2, Minerals Management Service, April 1987.
-------
X
156' ISO* 144- 138* »32* ,26* >2°"
OCS PLANNING AREAS
J>o"
38°
Figure A-2U OCS Planning Area: Alaska.,
Source: 5-Year Leasing Program Mid-1987 to Mid-1992, Minerals Management Service, April 1987.
-------
gulfUf.wk!
TABLE A-1
NUMBER OF STRUCTURES BY THE NUMBER OF WELLSLOTS AVAILABLE
GULF Of MEXICO, MARCH 1988
Number of
Ual 1 c 1 rtt e
Wcl I S IOL5
Avai I able
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
18
19
20
21
22
23
24
25
26
27
28
30
32
35
36
40
58
62
Missing
TOTAL
Ul VI^Af* f\f
nunDer OT
Structures
1,283
207
143
203
37
181
31
79
80
31
12
287
32
20
29
33
152
2
9
23
5
3
121
6
5
3
9
2
5
1
3
6
1
1
52
3,097
Production
Yes
20. OX
34. 8X
49. 7X
60.6X
75. 7X
82.3%
90. 3X
94. 9X
93. 8X
96. 8X
100. OX
92. 3X
100. OX
95. OX
89. 7X
97. OX
95. 4X
100. OX
77. 8X
91. 3X
80. OX
100. OX
95. 9X
66. 7X
80. OX
100. OX
100. OX
100. OX
o.ox
100. OX
100. OX
100. OX
100. OX
100. OX
Equipment
No
80. OX
65. 2X
50. 3X
39. 4X
24. 3X
17. 7X
9.7X
5. IX
6.3X
3.2X
O.OX
7.7X
O.OX
5. OX
10. 3X
3. OX
4.6X
O.OX
22. 2X
8.7X
20. OX
O.OX
4.1X
33. 3X
20. OX
O.OX
O.OX
O.OX
100. OX
O.OX
O.OX
O.OX
O.OX
o.qx
Note:
Blanks indicate no structures with intermediate
numbers of wellslots.
Source: MMS Platform Inspection System, Complex/Structure
Data Base, March 1988.
A-5
-------
Table A-2 summarizes the number of wellslots per platform in Pacific OCS
waters. Existing and planned structures range from 15 to nearly 100
wellslots, with an average of 55 wellslots per platform (MMS, 1986a). Three
structures of varying sizes are chosen to model the Pacific region. The
associated number of wellslots are 16, 40, and 70.
In the Atlantic and in most regions of Alaska, there are no existing
platforms. The size and configuration of platforms in these regions will
evolve as successful discoveries are made and developed. As a result, there
is no basis upon which to define a variety of platform sizes in the Atlantic
and the Alaskan regions. In each region, one typical size is selected based
on available projections or engineering studies. For example, the number of
wells projected for Arctic projects is based on the information in OTA 1985.
The selected platform sizes are:
Atlantic - 24 wellslots
Cook Inlet - 12 or 24 wellslots depending on type of production
Beaufort Sea - 48 wellslots
Norton Basin - 34 wellslots
Navarin Basin - 48 wellslots
In the Beaufort Sea, two configurations are modeled: a gravel island and a
platform. (See Section A.2.4 for further description of these configurations.)
Based on the six regions and the size categories within each region, a
total of 17 region/size categories are defined. These are shown in the left-
hand column of Table A-3.
A.13 Type of Production
The type of production is the third variable in defining the model
projects. Crude oil, natural gas, or both may be produced at a platform
depending on the reservoir and the economics of recovery. The options are:
oil-only, oil and gas, and gas-only.
In the Gulf, the MMS data indicate that, where the type of production is
known, very few (under 5 percent) of the structures produce only oil. We
maintain oil-only versions of the Gulf models to evaluate the costs of BAT
regulations because the composition of the effluent differs between oil-only
A-6
-------
-------
TABLE A-3
DISTRIBUTION OF OIL, OIL/GAS, AND GAS PRODUCING PLATFORMS
BY REGION AND SIZE
PRODUCTION TYPE
REGION AND
WELLSLOT SIZE
Gulf la*
Gulf lba
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Atlantic 24
Pacific 16
Pacific 40
OIL
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
OIL/GAS
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
GAS COMMENTS
Yes
Yes
Yes
Yes
Yes
Yes
No No gas-only platforms among large Gulf
platforms .
No No gas-only platforms among large Gul|tt
platforms . ^P
Yes
Yes
No No gas-only platforms among large Gulf
Atlantic 24
Pacific 16
Pacific 40
Pacific 70
Cook Inlet 12/24
Beaufort Sea 48
- Gravel island
- Platform
Norton Basin 34
Navarin 48
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
Yes
Yes
No
No
Yesb
No
No
No
No
No gas-only platforms among large Gulf
platforms .
No gas -only platforms among large Gulf
platforms .
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
Source: ERG model project configurations based on typical projects reported in the
Department of the Interior Mineral Management Service platform
inspection system, complex/structure database, and the literature.
"The Gulf la shares production equipment with three other single-well stucnures
while the Gulf Ib has its own production equipment.
bThe gas-only case is modeled as 12 wells.
A-8
-------
and oil-and-gas production. For the projected platforms, all Gulf platforms
that produce oil are assumed to have associated gas as well. There are no
gas-only platforms among large Gulf platforms. Only small projects (less than
40 wellslots) are assumed to produce only gas.
The same pattern is found in the Pacific, where the large projects produce
oil with gas (but not gas-only) and small.projects produce oil-with-gas or
gas-only. Telephone conversations with W. Guerard, California Department of
Conservation, indicates that as an oil field gets older, it produces less gas
but that all oil fields produce some gas (Guerard, 1989). All projected
platforms that produce oil are assumed to have associated gas as well for
evaluating the pollutant removals from produced water effluent guidelines.
In the Atlantic. the 24-wellslot platform is assumed to produce oil with
gas or only gas. In Alaska, projects in the Cook Inlet are assumed to produce
oil with gas or only gas. For the Arctic regions, there is no infrastructure
to deliver gas from these regions to the Lower 48 States nor is such
infrastructure planned for the next ten years, so just oil-only projects are
proposed for these regions.
A.2 DESCRIPTION OF MODEL PROJECTS
A.2.1 Gulf of Mexico Model Projects
Gulf 1. 4 and 6-Well Platforms
Small platforms in the Gulf either have their own production facilities or
are simple superstructures (i.e., well protectors) that ship produced
hydrocarbons (before water separation) to a central onshore or offshore
production facility. Platforms in the latter category are referred to as
satellite facilities. By servicing several platforms, centralized facilities
offer economies of scale in oil and gas production over small platform
structures with their own production equipment. Satellite platforms cannot be
used in all situations, however. If the platform is in a remote location so
that the cost of additional pipelines outweighs the cost advantage of central
processing, or the production from the platform is transported via
intercompany pipelines that do not accept crude unless it is already
separated from the produced water, then the production facility is located
directly on the specific platform.
A-9
-------
The MMS Platform Inspection System provides information on the number of
wellslots per OCS platform and whether platforms have their own production
equipment. Table A-l summarizes the data in the 1988 MMS files. Two models
are used for a single wellslot structure in the Gulf, one without production
equipment and one with production equipment. These are referred to as the
Gulf la and Gulf Ib models, respectively. The majority of 4- and 6-wellslot
structures have their own production equipment and are modeled as such in this
report.
Gulf 12-Well and 24-Well Platforms
These two model projects represent typical medium-sized production
structures common in the Gulf (see Table A-l). The DOI-MMS Platform
Inspection System Reports are used to define representative features of the
12- and 24-wellslot platforms (Tables A-4 and A-5). The typical 12-wellslot
steel jacket platform occurs in 0 to 200 feet of water (67 feet in the model
project), 0 to 10 miles offshore (6 miles in the model project). Of the 12
slots, an average of 10 are in use for production at any one time (10 in the
model project). The typical 24-wellslot steel-jacket platform occurs in 50-
500 feet of water (100 feet in the model project) and 5 to 50 miles offshore
(20 in the model project). Of the 24 slots, an average of 18 are in use for
production at any time (18 in the model project).
Gulf 40 Well Platform. The Gulf 40-well case represents those platforms
expected to produce large reservoirs in water depths averaging 200 feet and of
distances from shore averaging 50 miles. A selection of existing structures
in this size range is described in Table A-6. Again, ERG uses the MMS
Platform Inspection System Reports to define representative features of this
model project. Platforms in this case are expected to be constructed on the
far offshore tracts now being leased. No gas-only platforms are expected to
be in this category. Of the 40 wellslots, an average of 32 are in use for
production at any time.
Gulf 58 Well Platform. The largest model project in the Gulf is based on
platforms Cognac and Bullwinkle. Both are 60-slot steel jacket platforms.
Cognac, with an overall length of 1,265 feet, was installed in 1978 in
Mississippi Canyon while the 1,615-foot Bullwinkle is scheduled to be
installed in Green Canyon this year. Cognac and Bullwinkle are set
approximately 15 and 90 miles offshore at depths of 1,023 and 1,353 feet,
A-10
-------
TABLE A-4
SAMPLE 12-WELL STRUCTURES USED
IN SELECTING 12-WELL MODEL PROJECT
AREA
West Cameron
East Cameron
South Timbalier
Main Pass
Main Pass
East Cameron
West Delta
West Cameron
Matagorda Island
Ship Shoal
BLOCK
513
222
161
042
043
033
095
522
665
168
WATER
DEPTH
(FEET)
170
110
117
30
27
42
150
177
74
58
MILES
FROM
SHORE
93
67
32
11
10
8
27
95
15
27
WELL-
SLOTS
12
12
12
12
12
12
12
12
12
12
SLOTS
IN
USE
8
12
9
12
12
10
9
6
7
8
YEAR
INSTALLED
1974
1973
1964
1965
1967
1972
1968
1978
1979
1973
Source: Department of the Interior, Mineral Management Service, Offshore
Inspection System, Complex/Structure List, April 23, 1987.
A-ll
-------
TABLE A-5
SAMPLE STRUCTURES USED
IN SELECTING 24-WELL MODEL PROJECT
AREA BLOCK
High Island
East Cameron
Grand Isle
Vermilion
Eugene Island
South Marsh Island
South Pass
South Timbalier
South Timbalier
South Timbalier
Ship Shoal
Vermilion
Vermilion
Mississippi Canyon
Grand Isle
349A
322
081
023
256
128
037
026
026
026
225
247
321
311
022
WATER
DEPTH
(FEET)
278
230
177
36
137
225
108
60
55
60
146
139
205
425
55
MILES
FROM
SHORE
115
95
38
6
53
75
7
8
8
8
54
65
87
46
8
WELL-
SLOTS
24
18
24
25
18
24
24
18
26
24
21
24
24
24
24
SLOTS
IN
USE
9
16
17
4
7
' 18
13
18
26
18
18
14
22
19
23
YEAR
INSTALLED
1979
1975
1971
1977
1977
1975
1962
1971
1971
1979
1971
1972
1972
1978
1957
Source: Department of the Interior, Mineral Management Service, Offshore
Inspection System, Complex/Structure List, April 23, 1987.
A-12
-------
TABLE A-6
SAMPLE STRUCTURES USED
IN SELECTING 40-WELL MODEL PROJECT
AREA
Main Pass
South Marsh Island
South Marsh Island
South Marsh Island
South Marsh Island
West Delta
The Elbow
East Breaks
South Pass
South Pass
South Pass
BLOCK
153
130
130
130
130
080
331
160
070
070
065
WATER
DEPTH
(FEET)
290
215
215
215
216
102
241
935
290
264
300
MILES
FROM
SHORE
14
82
82
82
82
13
80
110
9
9
9
WELL-
SLOTS
32
36
40
36
36
30
35
40
40
40
32
SLOTS
IN
USE
32
36
31
36
36
23
35
2
40
40
32
YEAR
INSTALLED
1970
1975
1978
1974
1975
1971
1972
1981
1977
1974
1969
Source: Department of the Interior,'Mineral Management Service, Offshore
Inspection System, Complex/Structure List, April 23, 1987.
A-13
-------
respectively (Offshore 1986, MMS Offshore Inspection System). Information on
the Gulf projects is summarized in Table A-7.
A.2.2 Atlantic Model Projects
Platform configurations for the Atlantic are speculative since no economic
petroleum discoveries have been made to date (MMS, 1986b). Based on the
physical environments, the mid- and South Atlantic platforms can be expected
to be similar to California production platforms. The North Atlantic
platforms will probably be modified North Sea-type platforms. In the final
EIS for their 5-year leasing program, the MMS projects from 23 to 35
production wells per Atlantic platform (MMS, 1987). A 24-wellslot platform is
therefore expected to be representative of economically feasible projects in
the Atlantic. The model project water depth (300 feet) and distance from
shore (100 miles) are based on the location of exploratory wells in Georges
Bank and the Baltimore Canyon (MMS, 1981, and MMS, 1983). Information on the
Atlantic projects are summarized in Table A-8.
A.2.3 Pacific Model Projects
Most of the platform development in the Pacific is expected to occur off
the coast of Southern California. The California offshore area is
characterized by several old, fully developed fields and by high-potential
areas in the Santa Maria Basin, the Santa Barbara Channel, and off Long Beach.
Most of the current production is oil; in 1986 the oil/gas ratio was 531
ft3/bbl. There are only 21 nonassociated gas wells currently producing
offshore California; 6 of these wells are in state waters. Habitat, the Pitas
Point platform with 12 wells producing in 1986, is the only nonassociated gas
producer to date. Virtually all future production is expected to be oil
(California, 1987). Platform types in newly discovered fields are used as the
basis for the Pacific model projects. Most of these are in the peak
production range of 20,000 to 72,000 barrels oil per day (bopd).
Platforms producing from smaller reservoirs are represented by the 16-
wellslot model project that is patterned after the 6,000 bopd Platform Gina.
The larger reservoirs are represented by the 40-wellslot project patterned
after Platform Gail or the 70-wellslot project patterned after Platform Edith.
The number of producing wells expected with each project are 14, 33 and 60,
respectively. This information is summarized in Table A-9.
A-14
-------
TABLE A-7
PROJECT DESCRIPTIONS
GULF OF MEXICO
GULF OF MEXICO PROJECTS
PARAMETER
Platform typewell
Location
- state waters
- Federal OCS waters
Distance from shore
- mi
- km
Water depth
- ft
- m
Number of wellslots
Number of producing wells
GULF
1
well
pro-
tector
yes
yes
3
4.8
33
10
1
1
GULF
4
steel
jacket
yes
yes
3
4.8
33
10
4
4
GULF
6
steel
jacket
yes
yes
3
4.8
33
10
6
6
GULF
12
steel
jacket
yes
yes
6
9.7
66
20
12
10
GULF
24
steel
jacket
yes
yes
20
32.0
100
30
24
18
GULF .
40
steel
jacket
no
yes
50
80.4
200
60
40
32
GULF
58
steel
jacket
no
yes
100
161
590
180
58
50
Source: ERG estimates.
A-15
-------
TABLE A-8
PROJECT DESCRIPTION
ATLANTIC REGION
PARAMETER
ATLANTIC 24
Platform type
Location
- state waters
- Federal DCS waters
Distance from shore
- mi
- km
Water depth
- ft
- m
Number of wellslots
Number of producing wells
tension leg platform
no
yes
100
161
300
90
24
20
Source: ERG estimates.
A-16
-------
TABLE A-9
PROJECT DESCRIPTIONS
PACIFIC REGION
PARAMETER
Platform type
Location
- state waters
- Federal OCS waters
Distance from shore
- mi
- km
Water depth
- ft
- m
Number of wellslots
Number of producing wells
PACIFIC 16
steel jacket
no
yes
5
8.0
300
90
16
14
PACIFIC 40
steel jacket
yes
yes
3
4.8
300
90
40
33
PACIFIC 70
steel
no
yes
5
8.0
1,000
300
70
60
jacket
Source: ERG estimates.
A-17
-------
A.2.4 Alaskan Model Projects
The Alaskan offshore area is quite diverse. Platform designs range from
conventional platforms in Cook Inlet to severe weather structures in the
Arctic areas. Model projects are selected to span a range of conditions in
the Alaskan offshore areas.
Cook Inlet. This model project represents the platform types expected to
be used in southern Alaska, that is Cook Inlet/Shelikpf Strait, Bristol Bay,
and Gulf of Alaska. This region is free of Arctic ice and has moderate
environmental conditions. Accordingly, conventional platform designs similar
to existing Cook Inlet structures, including the recently installed Steelhead
platform, define the model projects.
Southern Alaska platforms may be expected to produce oil, gas or both.
Table A-10 lists information about existing platforms in Cook Inlet (Alaska,
1984 and Ocean Industry, 1987b). Although these are in the Coastal
subcategory, they do provide some information for future offshore projects in
Alaska. There are 15 platforms with a total of 326 drilled wells. For oil
and gas projects, a 24-well platform with 20 producers is proposed. A 12-
wellslot model project with 10 producing wells is selected to represent gas-
only projects in the region. Both the 24-wellslot and 12-wellslot structures
are assumed to be in 50 meters of water and 20 miles offshore.
Arctic Alaska Model Projects
The first Arctic offshore production began at the end of 1987. The
Endicott field lies 10 miles northeast of Prudhoe Bay in the State waters of
the Beaufort Sea. The field was discovered in 1978 and production began in
October 1987 (Alaska, 1988). This project forms the basis for the Beaufort
Sea gravel island project described below. The other Arctic projects are
based on the 1985 report from the Office of Technology Assessment entitled Oil
and Gas Technologies for the Arctic and Deepwater (OTA, 1985).
Beaufort Sea Gravel Island. The plan to develop the Endicott field
includes a 5-mile cause.way into the shallow waters of the Beaufort Sea linking
two artificial gravel islands. The islands are located some 2-1/2 miles off
the coast in 4 to 12 feet of water. Some 80 to 120 development wells are
A-18
-------
TABLE A-10
PLATFORMS IN COOK INLET
N. Cook Inlet (gas-only)
Granite Point
Trading Bay
McArthur River
Middle School Ground
Total
YEAR
INSTALLED DRILLED
A Platform
Bruce
Anna
Granite Point
Spark
TSA
Monopod
King Salmon
Grayling
Dolly Vardin
Steelhead
Baker
A
C
Dillon
WELLS
1968
1966
1966
1966
1968
1968
1966
1967
1967
1967
1987
1965
1964
1964
1965
FIE1
12
17
26
17
7
9
31
24
37
36
36
20
24
16
14
32
Source: Johnson, 1988.
A-19
-------
planned. The ERG project is a single island with 48 wells, that is half the
size of the Endicott project (Alaska, 1988; Drilling Contractor, 1987).
Beaufort Sea Platform. The Beaufort Sea platform is assumed to be located
20 miles offshore in 50 feet of water. This location has extremely low
temperature conditions and is covered with ice 10 months out of the year. The
OTA report lists this project as being developed from a gravel island but also
notes that alternatives such as concrete, steel, hybrid structures built as
caissons, or complete bottom-mounted units may be preferable, depending on
site-specific conditions. The OTA scenario has seven island/platforms with a
total of 271 wells; a footnote indicates that the number of wells is probably
a minimum. The ERG project is a single 48-wellslot structure with 40
producing wells.
Norton Basin. The Norton Basin has a more "moderate" climate than the
Beaufort Sea; ice coverage is only 8 months out of the year- On the other
hand, platform designs must address strong bottom currents and storm surges.
As with the Beaufort Sea scenario, the OTA report initially lists development
as a set of four gravel islands with a total of 136 wells. The same footnote
listing platform alternatives to the gravel island is given for the Norton
Basin. The ERG model project assumes a 34-wellslot platform 40 miles from
shore in 50-foot water with 28 producing wells.
Navarin Basin. The Navarin Basin has light-to-moderate conditions with
5-month coverage. In contrast to moderate ice conditions and temperature, the
Navarin Basin is also marked by severe storms, wind-driven waves, spray-icing,
and the potential for soft soil. The OTA report projects either a gravity
platform or a steel, pile-founded structure depending on site conditions. The
scenario is located 400 to 700 miles offshore in 450 feet of water. The OTA
scenario consists of seven production platforms and two service platforms with
a minimum of 271 wells. The ERG project is a single structure with 48
wellslots and 40 producing wells.
Table A-11 summarizes the information for the Alaska projects.
AJ REFERENCES
Alaska 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation
Commission, n.d.
A-20
-------
TABLE A-ll
PROJECT DESCRIPTIONS
ALASKA
PARAMETER
Platform type
Location
- state waters
- Federal OCS
waters
Distance from
shore
- mi
- km
Water depth
- ft
- m
Number of
wellslots
Number of
producing wells
COOK
INLET
OIL,
OIL/GAS
steel
jacket
yes
yes
3
5
50
15
24
20
COOK
INLET
GAS
steel
jacket
yes
yes
5
8
50
15
12
10
BEAU-
FORT
GRAVEL
ISLAND
gravel
island
yes
yes
3
5
15
5
48
40
BEAU-
FORT
PLATFORM
steel
structure/
caisson
no
yes
20
32
50
15
48
40
NORTON
BASIN
steel
structure/
caisson
no
yes
40
64
50
15
34
28
NAVARIN
BASIN
gravity
plat-
form
no
yes
400-
700
640-
1,130
450
137
48
40
Source: ERG estimates.
A-21
-------
Alaska 1988. 5-Year Oil and Gas Leasing Program. Alaska Department of Natural
Resources, January 1988.
California 1987. 72nd Annual Report of the State Oil and Gas Supervisor.
California Department of Conservation, 1987.
Drilling Contractor 1987. "Endicott oilfield development is on schedule,"
Drilling Contractor. August/September 1987, pp. 25-26.
ERG 1985. Economic Impact Analysis of Proposed Effluent Limitations and
Standards for the Offshore Oil and Gas Industry, prepared for the U.S.
Environmental Protection Agency by Eastern Research Group, Inc., EPA
440/2- 85-003, July 1985.
Guerard 1989. Personal communication between Maureen F. Kaplan, Eastern
Research Group, and William Guerard, California Department of
Conservation, 12 May 1989.
Johnson 1988. Individual well production printouts sent to Maureen F. Kaplan,
Eastern Research Group, Inc., by Elaine Johnson, Alaska Oil and Gas
Conservation Committee, 25 February 1988.
MMS 1981. U.S. Department of the Interior, Minerals Management Service,
North Atlantic Summary Report. U.S. Geological Survey Open-file Report 81-
601.
MMS 1983. U.S. Department of the Interior, Minerals Management Service,
Mid-Atlantic Summary Report. October 1983.
MMS 1986a. U.S. Department of the Interior, Minerals Management Service,
Pacific Summary Report/Index November 1984-May 1986. MMS 86-0060.
MMS 1986b. U.S. Department of the Interior, Minerals Management Service,
Atlantic Summary Report/Index January 1985-June 1986. MMS 86-0071.
MMS 1987. U.S. Department of the Interior, Minerals Management Service,
Proposed 5-Year Oil and Gas Leasing Program Mid-1987 to Mid-1992. Final
Environmental Impact Statement, MMS 86-0127, January 1987.
Ocean Industry 1982. "Offshore Construction Report," Ocean Industry.
March 1982.
Ocean Industry 1983. "Offshore Construction Report," Ocean Industry.
March 1983.
Ocean Industry 1986. "1986 Platform Survey," Ocean Industry. March 1986,
pp. 29-34.
Ocean Industry 1987a. "1987 Platform Survey," Ocean Industry. March 1987,
pp. 64-68.
Ocean Industry 1987b. "Steelhead brings new life to aging Cook Inlet
field," Ocean Industry. November 1987, pp. 35-36.
Offshore 1986. "The Gulf of Mexico," Offshore. February 1986, pp. 38-45.
OTA 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of
Technology Assessment, Washington, D.C.
A-22
-------
APPENDIX B
BASE CASE TIMING OF PROJECT DEVELOPMENT
B.I PHASES OF PROJECT DEVELOPMENT
In developing the economic models for the 39 model projects, ERG assumes
that there are four phases of project development: exploration, delineation,
development, and production. The exploration phase is the time from the lease
sale through exploration well drilling. After a discovery, additional wells
may be drilled to delineate the extent of the reservoir. This occurs during
the delineation phase. The development phase includes planning, building, and
installing the platform, and drilling development wells. The production phase
of the project is the time during which oil and/or gas is being produced. ERG
assumes that the exploration and delineation phases of the model projects are
discrete in time and that the development phase overlaps the production phase.
Six wells are drilled each year on platforms with up to 12 wellslots (one
drilling rig operating) and 12 per year are drilled on larger platforms (two
drilling rigs operating). Five-sixths of these wells are production wells and
one-sixth are service wells. Production wells are in full production the year
they are drilled.
B.2 DURATION OF PROJECT DEVELOPMENT PHASES
The geographic region (climate) in which the project is located, the size
of the platform, water depth, distance from shore, and any previous oil and
gas development in the area are important determinants of project timing.
Length of time for project development varies from 1 year between lease sale
and start of production for a single well structure in the Gulf of Mexico
(located close to shore in 40 feet of water and in a highly developed area) to
12 years for the Beaufort Sea 48-well platform (located in extremely severe
climate conditions). The data sources for each region are discussed
separately below.
B-l
-------
B.2.1 Gulf of Mexico
For the Gulf of Mexico, project timing is developed from a series of MMS
and industry sources (MMS, 1982; MMS, 1986a; and MMS, 1986b). Exploratory
drilling is assumed.to begin within a year of the lease sale. Figure B-l
shows the time to first spud date (i.e., time when drilling begins on the
first exploratory well) for all DCS sales held from 1975 through 1984. The
average annual time to first spud is less than half a year for this time
period, although the times for any given sale range from a few weeks to 11
months.
No delineation wells are proposed for the small Gulf projects (Gulf 1,
Gulf 4, and Gulf 6) so no time accrues between the start of exploration and
the start of delineation for these projects. For the Gulf 12, Gulf 24 and
Gulf 40 projects, exploratory wells are drilled within a year of lease sale.
An additional year is spent in exploratory drilling for the Gulf 58 project.
One year is assumed to occur by the start of development in the Gulf 4 and
Gulf 6 projects. No additional time is assumed to pass between the start of
delineation and the start of development for the Gulf 12, Gulf 24 and Gulf 40
projects. Two years between the start of delineation and the start of
development is assigned to the Gulf 58 project.
For the time between the start of the development to the start of
operation, one year is assigned to the Gulf 1, Gulf 4, and Gulf 2x5 projects;
2 years to the larger oil and oil/gas projects; and 3 years to the Gulf 24
gas-only project.
The timing assumptions are summarized in Table B-l for the Gulf of Mexico
projects. Figure B-2 shows the time from lease sale to initial production for
the 1975 to 1984 period. Times range as short as 5 months to over 3 years.
Since Figure B-2 shows the time to earliest production, and we are developing
"typical projects," our time frame should be and is at the higher end of the
range. The 6-year schedule for the Gulf 58 project is based on Shell's
Bullwinkle project - a 60-slot platform to be installed in 1989 on a tract
leased in OCS Sale 72 in 1983 (OGJ, 1988c). The time from lease sale to the
start of operation ranges from 2 to 6 years. This is consistent with the
information in (1) MMS 1986b, where tracts leased in the April 1984 sale were
in production by mid-1986, but not tracts leased in July 1984 or later sales;
(2) MMS 1987a, where projects in federal waters are assumed to take 4 years
for the central Gulf, 5 years for the western Gulf, and 8 years for the
B-2
-------
00
I
Ul
Time to spud.
1st lease drt1 led
per sale
5
1975
1976
1977
197B
1979
1980
19B1
19B2
1983
1984
Sale 37
Sale 41
Sale 47
Sale 45
Sale 58A
Sale A62
Sale A66
Sale 67
Sale 6911
Sale 79
Sale 3B
Sale 44
Sale 51
Sale 58
Sale 62
Sale 66
Sale 691
Sale 72
Sale 84
Sale 38 A
Sale 65*
Sale 74
Sale 81
Average time to
1st spud, for all
sales held in that
year
(None drilled)
\\\
(Off the scale:
11.0)
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
Figure B-1.'. Gulf of Mexico: Time From l.uasu Sale to FiruL Spud UaU:.
Source: MMS 1986a..
-------
TABLE B-l
PROJECT TIMING
GULF OF MEXICO
MODEL PROJECTS
OIL AND OIL/GAS GAS ONLY
GULF GULF GULF GULF GULF GULF GULF GULF GULF GULF GULF
TIMING 1 4 6 12 24 40 58 4 2x5 12 24
Years between lease 0 000000 000 0
sale and start of
exploration
Years between start 0 001112 001 1
of exploration and
start of delineation
Years between start 0 110002 110 0
of delineation and
start of development
Years between start 1 112222 112 3
of development and
start of operation
Total years between 1 223336 223 4
lease sale and
start of operation
Source: ERG estimates.
B-4
-------
DO
in
(0
Average time to
production, all
sales hold In year
ine to production.
let lease per sale
W//////X
Sale 38A
1975 Sale 37
1976 Sale 44
1977 Sola 47
1978 Sale 45
Sale 38
Sale 41
1979 Sale 58A
I960 Sale A62
1981 Sale A66
1982 Sale 67
Sale 58
Sale 62
Sale 66
Sale 69 I
1983 Sale 72
1984 Sale 81
Sale 69 11*
Sale 79*
Sale 74*
Sale 84*
(No production to date)
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
Figure B-2U Gulf of Mexico: Time From Lease Sale to Initial Production.
Source: MMS 1986a.
-------
eastern Gulf; and (3) OTA 1985, where production lead times of 2 years are
proposed for the Gulf area.
B.2.2 Pacific
The Pacific region required updating from the 4 to 5 years allowed from
base sale to start of operation in ERG 1985. Table B-2 summarizes the project
timing for several recent and projected platforms. The time from lease sale
to start of operation ranges from 6 to 20 years. Changing environmental
regulations and litigation are credited with a 5-year delay between platform
installation and production for the Hondo A platform and a 15-year delay in
confirmation drilling on Tract P-0205 (Ocean Industry, 1986, and 1987a).
Platform Gail was launched on Tract P-0205 in April 1987. While Gail was
enroute from its construction in Japan, the California Coastal Commission
ruled that it was built to too-strict environmental and safety standards. The
platform was towed and then beached until the project was deemed suitable
(Ocean Industry, 1987a, and 1987d).
In light of these developments, timing for the Pacific projects has been
revised from that given in ERG 1985. Figure B-3 shows the time from lease
sales to first spud date in the Pacific. The times range from less than 1
month to 17 months. We therefore allocate 1 year between lease sale and the
start of exploration for the Pacific model projects.
Table B-2 indicates that discovery wells typically occurred 2 to 3 years
after lease sale. The time between the start of exploration and the start of
delineation when the discovery would occur is therefore 1 to 2 years.
Platforms have been set 4 or more years from the lease sale, or from 1 to 4
years after the start of delineation. Production usually occurs within 1 to 3
years after the platform has been set depending on how much other construction
is required. For example, at the end of 1987, platforms Harvest and Hermosa
had had wells drilled but were waiting for onshore processing facilities to be
completed prior to going into production (Rau, 1987).
This information is summarized in Table B-3. The time from lease sale to
start of operation now ranges from 5 to 10 years. The revised project timing
also agrees with the information in Figure B-4 on the time from lease sale to
initial production. The range in project timing corresponds well to that in
the U.S. for the 5-year leasing plan (MMS, 1987a) where West Coast projects
B-6
-------
0)
I
TABLE B-2
PROJECT TIMING FOR RECENT PACIFIC COAST PLATFORMS
SANTA MARIA
Water depth
- # slots
- # slots drilled
Lease sale
Discovery
Platform set
Initial production
Peak production
- oil bopd
- gas MMcfd
- year
Years before lease to
production
PT
HARVEST
670
50
42
1979
1982
1985
1988
72,000
1989
10
. ARGUELLO
HERMOSA
602
48
40
1979
1981
1985
1988
27,000
25
1996
9
HIDALGO
430
56
45
1981
1987
1988
20,000
10
1996
15
BASIN FIELDS
PT.
PEDER-
NALES
IRENE
242
72
43
1981
1985
1986
20,000
13.3
1987
6
SAN
MIGUEL
JULIUS
478
70
1981
1983
1989
1990
40,000
9
ROCKY SOCK-
POINT EYE
HACIENDA GAIL
300740 1,207
4836 60
25
1981 1968
1984 1970
1987
1988
--
--20
SANTA BARBARA
CHANNEL FIELDS
HONDO
HARMONY
1,004
60
1968
1992
50.000-
60,000
40-50
PES-
CADO
HERITAGE
1968
1992
50,000-
60,000
70-100
Note: -- means information not available.
Source: Ocean Industry, 1986, 1987a,b,c; MMS, 1986c; Offshore, 1987a.
-------
IB'
15-
12-
9^
(No vails drilled
to date)
w 1963 1964 1966
SALE PI P2 P3
1966
P4
1975
35
1979
48
1981
53
1982 1982
68 RS53
1983
73
1984
80
Loaca ealac and yoar* hold
Figure B-3. Pacific Region: Time from lease sale to first spud date.
Source: MMS 1986a.
B-8
-------
TABLE B-3
PROJECT TIMING
PACIFIC REGION
PACIFIC
TIMING
Years between lease sale and start
of exploration
Years between start of exploration
and start of delineation
Years between start of delineation
and start of development
Years between start of development
and start of operation
Total years between lease sale and
start of operation
16
1
1
1
2
5
OIL AND
OIL/GAS
PACIFIC PACIFIC
40 70
1 1
2 2
3 5
2 2
8 10
GAS
ONLY
PACIFIC
16
1
1
2
2
6
Source: ERG estimates.
B-9
-------
/u-
60-
50-
I"0'
* 30-
20-
10-
SALES
1963 1964
PI P2
^
17. SB
s^
1966
P3
^
^
1968
P4
^S
B1.20
^
\x
^
1975
35
1979 1981 1982 1983 1984
48 53 RS53 & 68 73 80
Laaea colas and yaare hold
Figure B-4. Pacific Region: Time from lease sale to initial production.
Source: MMS 1986a.
B-10
-------
take from 5 to 10 years from lease sale to initial production. For deepwater
projects off California, OTA 1985 estimates a production lead time of 10 years,
The delays are having an effect on whether the projects are economical.
Platforms Independence and Heather appear to have been cancelled (Ocean
Industry, 1987b) . ARCO filed lawsuit in October 1987 seeking compensation
from the State Lands Commission and Santa Barbara County for an unlawful
taking of property by denying ARCO's permit for development until the
cumulative effect of oil drilling offshore California can be thoroughly
studied. ARCO's plan of exploration was approved in 1980 (Ocean Industry,
1987d).
B.2J Atlantic
There has been no development to date in the Atlantic OCS region.
Estimates of project timing, therefore, are hypothetical. The 7- to 9-year
span developed in ERG 1985 corresponds well with the 6- to 9-year range
developed in MMS 1987a (Table IV.A.1-1) for the 5-year leasing schedule. In
MMS 1987, one year is allotted for the time from lease sale to start of
exploration and production is assumed to occur in the same year as the
platform is set. Given the delays seen between platform installation and
production seen in Pacific OCS platforms (see Section B.2.2), we prefer to
allocate 2 to 4 years to that part of the project. Table B-4 summarizes
project timing for platforms in the Atlantic.
B.2.4 Alaska
Project timing varies greatly in Alaska depending upon where the project
is located. For the Cook Inlet projects, the area is relatively free of
severe climatic conditions and the region is mature in terms of oil and gas
development, so many facilities are already in place. The platforms that
exist in Cook Inlet are in the coastal subcategory. Information about these
platforms can be used to estimate timing for model projects in a relatively
ice-free area in offshore Alaskan waters. The Beaufort Sea/North Slope region
now has the trans-Atlantic pipeline in place, while the Bering Sea is
undeveloped. Project timing, then, is shortest in the Cook Inlet area and
longer for the Arctic regions.
B-ll
-------
TABLE B-4
PROJECT TIMING
ATLANTIC REGION
TIMING
OIL AND
OIL/GAS
ATLANTIC 24
GAS ONLY
ATLANTIC 24
Years between lease sale and start
of exploration
Years between start of exploration and
start of delineation
Years between start of delineation
and start of development
Years between start of development and
start of operation
Total years between lease sale and
start of operation
Source: ERG estimates.
B-12
-------
35
30
25
20
: 15
10
5
1978 1977 1978 1979 1960 1981 1982 1983
SALE 39 CI 8F 53 80 71 70 57
alM and y«ar« h«ld
Figure B-5. Alaska Region: Time from lease sale to first spud date.
Source: MMS 1986a.
B-13
-------
months. We allocate 1 year to the time between lease sale and the start of
exploration for the Cook Inlet projects and 2 years for projects in other
areas.
The Steelhead platform is the first platform to be installed in Cook Inlet
since 1968. The jacket was installed in mid-1986 and production was expected
to begin by the end of 1987. On this basis, 2 years are allocated for the
years between the start of development and the start of production for the
Cook Inlet projects (MMS, 1987b and Ocean Industry, 1987e).
In the Endicott field in the Beaufort Sea region, the final permits for
development were issued in January 1985. By the end of 1986, the gravel
project was completed and by the end of 1987 the equipment sealift was
completed and initial production begun (Drilling Contractor 1987a and 1987b) .
On this basis, 3 years are allocated to the time from the start of development
to the start of operation for the Beaufort gravel island, and platforms in the
Beaufort Sea, Norton Basin, and Navarin Basin.
The Endicott field was discovered in 1978 and is coming into production by
1987 (Drilling Contractor, 1987b). A range of 7 to 10 years is allocated for
the time between the start of exploration and start of operation for the
Beaufort Sea gravel island projects. The Beaufort Sea platform is assumed to
take one year longer than the Beaufort Sea gravel island because it is located
further offshore and in deeper water. A total of 5 years is allocated to this
period for the Cook Inlet projects.
Project timing assumptions for Alaska projects are summarized in Table B-
5. The time span ranges from 6 years for projects in Cook Inlet to 12 years
for projects in the Beaufort Sea. The project lead times for platforms in the
Norton Basin (9 years), Navarin Basin (11 years), and the Beaufort Sea (12
years) correspond to those presented in OTA, 1985. This range is somewhat
broader than that proposed in the EIS for the 5-Year Leasing Plan where Alaska
projects take 9 to 12 years from lease sale to first development (MMS 1987a)
to allow for more variation in the analysis. It is unlikely that projects in
the well-developed Cook Inlet area would have a 9-year project lead time.
B3 References
Drilling Contractor 1987a. "Arctic: Poor economics delay prospecting,"
Drilling Contractor. February/March 1987, pp. 17-19.
B-14
-------
TABLE B-5
PROJECT TIMING
ALASKA
TIMING
MODEL PROJECT
OIL
OIL/
GAS
GAS
BEAU-
FORT
COOK GRAVEL BEAUFORT NORTON NAVARIN COOK COOK
INLET ISLAND PLATFORM BASIN BASIN INLET INLET
Years between lease sale 1
and start of exploration
Years between start of 1
exploration and start
of delineation
Years between start of 2
delineation and start
of development
Years between start of 2
of development and
start of operation
Total years between 6
lease sale and
start of operation
11
12
9 11
Source: ERG estimates.
B-15
-------
Drilling Contractor, 1987b. "Endicott oilfield development is on schedule,"
Drilling Contractor. August/ Sept ember 1987, pp. 25-26.
ERG 1985. Economic Impact Analysis of Proposed Effluent Limitations and
Standards for the Offshore Oil and Gas Industry, prepared for the U.S. EPA
by Eastern Research Group, EPA 440/2-85-003, July 1985.
MMS 1982. U.S. Department of the Interior, Minerals Management Service,
Draft Regional Environmental Impact Statement. Gulf of Mexico, August
1982.
MMS 1986a. U.S. Department of the Interior, Minerals Management Service, PCS
National Compgnri-ji^. MMS 86-0017, May 1986.
MMS 1986b. U.S. Department of the Interior, Minerals Management Service,
Gulf of Mexi^" S""pmar Report/Index November 1984-June 1986. MMS 86-0084.
MMS 1986c. U.S. Department of the Interior, Minerals Management Service,
Pacific Summary Report/Index. November 1984-May 1986. MMS 86-0060.
MMS 1987a. U.S. Department of the Interior, Minerals Management Service,
Proposed 5-Year Outer Continental Shelf Oil and Gas Leasing Program. Mid-
1987 to Mid- 1992. Final Environmental Impact Statement. MMS 86-012?!
January 1987.
MMS 1987b. U.S. Department of the Interior, Minerals Management Service,
Alaska Summary Index: January 1986 -December 1986. MMS 87-0016.
Ocean Industry 1986. "Activity moves ahead off California coast," Ocean
Industry. October 1986, pp. 24-27.
Ocean Industry 1987a. "Chevron's Gail platform launched. . .finally, " Ocean
Industry. May 1987, p. 11.
Ocean Industry 1987b. "1987 Platform Survey," Ocean Industry. March 1987,
pp. 64-68.
Ocean Industry 1987c. "Chevron skirts obstacle, will drill from Gail early
next year . " Ocean Industry . December 1987, p. 9.
Ocean Industry 1987d. "Giant fields set to boost California, Alaska output,"
Ocean Industry. October 1987, pp. 72.
Ocean Industry 1987e. "Steelhead brings new life to aging Cook Inlet field,"
Ocean Industry. November 1987, pp. 35-36.
Offshore 1987a. "Field developers proceed cautiously in recovery," Offshore.
November 1987, pp. 30-36.
OGJ 1988. "Oil and gas production to build on 5-year-old leases in Gulf,"
Oil and Gas Journal. 4 January 1988, pp. 15-18.
OTA 1985. Office of Technology Assessment. Oil and Gas Technologies for the
Arctic and Deepwater. Washington, DC, May 1985.
Rau, Denny 1987. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and Denny Rau, Minerals Management Service, Pacific
Office, Ventura District, 15 December 1987.
B-16
-------
APPENDIX C
LEASE PRICES
The lease price for each model project is a function of four factors:
Lease Price - Price per X Exploratory Wells
Tract Discovery Well
X Ratio of Expected / Platforms
Production / Discovery Well
The price per tract is the average price paid for tracts in that region in
1986. These prices are described in Section C.I. The ratio of the number of
successful exploratory wells ("discovery well") to all exploratory wells is
the fraction of exploration wells that successfully discover economic oil or
natural gas. This fraction is also called the discovery efficiency and is
discussed in Section C.2. The number of platforms per discovery well is
described in Section C.3. Section C.4 describes the methodology used to scale
the lease costs by the ratio of expected production for the various model
projects to the production of a typical project for the region.
C.1 AVERAGE LEASE COST PER TRACT
Lease sales have been held annually for OCS tracts in the Gulf of Mexico
for many years. The most recent lease sales for the Atlantic, Pacific and
Alaska were held in 1983, 1984 and 1984 respectively. To estimate 1986 lease
prices for the Gulf of Mexico, we use the average cost per tract from the 1986
lease sale; see Table C-l. The Gulf of Mexico is a well-studied mature
producing region. Prices in the area will rise and fall according to market
prices. If lower prices are being paid for tracts in the Gulf of Mexico,
lower prices are assumed to be paid for tracts in other regions.
To estimate lease prices for other regions, we use the ratio of 1986/1983
prices and 1986/1984 prices for the Gulf of Mexico (see Table C-l). The price
per acre in the most recent lease sale is multiplied by the appropriate ratio
to obtain an estimated 1986 cost per acre for that region. The cost per acre
is multiplied by the average tract size in the most recent year to arrive at
the estimated price per tract. For example, the most recent lease sale in the.
C-l
-------
lease.wkl
04-Feb-91
TABLE C-1
GULF OF MEXICO LEASE PRICES*
O
K)
Year Region
1983 HAFLA
Central
Western
TOTAL 1983
1984 Eastern
Central
Western
TOTAL 1984
1986 Central
Western
Total
Number of
Tracts
Offered
7.
5,
13.
B.
6.
5.
20,
5.
«.
10.
125
050
848
023
868
502
446
816
837
887
724
Number of
Tracts
Leased
11
623
406
1,040
156
453
361
970
101
41
142
Acreage
Leased
58,
3.089,
2,246.
5.393,
897.
2.278.
1,949.
5,125.
504.
229.
734.
117
812
005
934
786
129
186
101
807
612
419
Bonus
$37.570
$3,367.606
$1,501,712
$4.906,889
$310,586
$1.323.036
$844.850
$2,478.473
$130.276
$56.817
187,094
.900
.134
,517
,551
.261
.649
.488
,398
.757
.990
.747
Tract
Size (ac)
5283
4960
5532
5186
5755
5029
5399
5284
4998
5600
5172
Average
Cost per
Tract ($)
$3.415.536
$5.405,467
$3,698,799
$4,718,163
$1,990,938
$2,920,611
$2,340.306
$2,555,127
$1,289.869
$1,385.805
$1,317,569
Cost per
Acre ($)
$646.47
$1,089.91
$668.61
$909.71
$345.95
$580.76
$433.44
$483.60
$258.07
$247.45
$254.75
1986
Price
Factor
0.28
0.53
1.00
Note: Current dollars.
Source: MMS. 1986a; HMS. 1987a.
lease.wkl
-------
Pacific was held in 1984 (see Table C-2). The cost per acre in 1984 ($543.19)
is multiplied by the 1986/1984 ratio of the Gulf of Mexico prices (0.53) to
estimate a cost per acre of $286.15 in 1986. The average tract size in 1984
was 4,972 acres. The estimated average lease price in 1986 is 4,972 x $286.15
or $1,422,814.
The same methodology was used for the Atlantic region using 1983 data; see
Table C-3. The projected tract price in 1986 dollars is $475,320.
The information for Alaska is presented in Table C-4. The 1984 prices
were used to estimate 1986 prices. For Alaska, there is also information on
sales in State waters and the prices are far lower than for the Federal
regions. The 1986 State lease prices are used for the Cook Inlet projects
while the estimated 1986 Federal lease prices are used for the Arctic
projects.
C.2 DISCOVERY EFFICIENCY
Discovery efficiency is a parameter representing the fraction of
exploration wells that successfully discover economic petroleum reserves; For
example, if 5 wells are drilled in a basin, and one is successful, the
discovery efficiency is 1/5 or 0.20. The inverse of the discovery efficiency
is the number of exploratory wells that must be drilled to obtain a single
successful well.
For this report, we choose to calculate discovery efficiencies based on
historical data, using all exploratory wells drilled as of January 1, 1985
(API 1988, Section XI, Table 7). Discovery efficiencies may be calculated on
a year-by-year basis, but since the number of offshore wells drilled in any
given year is small, we prefer to use the all-time data. This information is
presented in Table C-5. Note the effects of rounding: for the Pacific and
Gulf of Mexico, the discovery efficiency is 0.14, rounded up from the more
precise estimate of 0.135. The number of exploratory wells per discovery well
(7.41) is the inverse of the more precise figure (0.135) rather than of the
rounded figure (0.14).
C-3
-------
O
TABLE C-2
PACIFIC LEASE PRICES*
Year
1983
1984
1986
Tracts
Region Offered
Southern 137
Southern 657
Projected
Tracts Acreage Tract
Leased Leased Bonus Size (ac)
8 43,801 $16,022.336 5475
23 114,363 $62,121.252 4972
4972
Average
Cost per
Tract ($)
$2,002.792
$2.700,924
$1,422,814
Cost per
Acre ($)
$365.80
$543.19
$286.15
Notes: Current dollars.
Projected price obtained by multiplying 1984 price by ratio of 1986/1984 prices in the Gulf of Mexico;
see Table C-1.
Source: HHS. 1987a.
-------
lease.uk!
TABLE C-3
ATLANTIC LEASE PRICES*
en
Year
1983
1986
Tracts
Region Offered
Middle 4,050
South 3,582
TOTAL 1983 7,632
Projected *
Tracts Acreage Tract
Leased Leased Bonus Size (ac)
37 210,648 $68.410,240 5693
11 62.625 $13.062.040 5693
48 273.273 $81.472,280 5693
5693
Average
Cost per I
Tract ($)
$1,848,925
$1,187,458
$1,697,339
$475,320
:ost per
Acre ($)
$324.76
$208.58
$298.14
$83.49
Notes: Current dollars.
Projected price obtained by Multiplying 1983 price by ratio of 1986/1983 prices in the Gulf of Mexico;
see Table C-1.
Source: HHS. 1987a.
-------
lease.uk1
TABLE C-4
ALASKA LEASE PRICES*
O
a\
Ul«4%Ar* f\f
NuiDcr OT
Tracts
Year Region Offered
Federal
1983 Norton 418
St. George 479
TOTAL 1983 897
1984 Navarin 5,036
Beaufort Sea 1,419
TOTAL 1984 6,455
1986 Projected *
State
1986 Beaufort
Cook Inlet
TOTAL
Uin^ukr f\f
nurajer OT
Tracts
Leased
59
96
155
180
231
411
6
45
51
Acreage
Leased
335,898
540,917
876,815
1,024,772
1,230.486
2.255.258
25,488
175,866
201,354
Bonus
$317,873,372
$426,458,830
$744,332.202
$624.491.331
$871.964.327
$1.496.455.658
$396.585
$380.823
$777,408
Tract
Size (ac)
5693
5635
5657
5693
5327
5487
5487
4248
3908
3948
Average
Cost per (
Tract ($)
$5,387,684
$4.442,279
$4.802,143
$3,469,396
$3,774,737
$3,641,011
$1,918,041
$66,098
$8.463
$15,243
:ost per
Acre ($)
$946.34
$788.40
$848.90
$609.40
$708.63
$663.54
$349.55
$15.56
$2.17
$3.86
Notes: Current dollars.
Projected price obtained by multiplying 1984 price by ratio of 1986/1984 prices in the Gulf of Mexico;
see Table C-1.
Source: HMS, 1987a; Alaska, 1987.
-------
disc eff.uk!
TABLE C-5
TOTAL EXPLORATORY OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Number of
Exploratory
Discovery Wells Per
Region Oil Gas Dry Total Efficiency Discovery
Alaska
California
Oregon
Washington
Federal Pacific
TOTAL PACIFIC
Alabama
Florida
Louisiana
Texas
Federal -COM
TOTAL GULF OF MEXICO
ATLANTIC
GRAND TOTAL
20
44
0
0
0
44
0
0
267
45
0
312
0
376
7
10
0
0
0
10
2
0
349
273
0
624
0
641
73
294
8
6
38
346
0
24
3999
1732
241
5996
36
6451
100
348
8
6
38
400
2
24
4615
2050
241
6932
36
7468
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.00
0.14
3.70
7.41
7.41
na
7.34
Note: Well count includes wells in both Federal and State waters.
na = not applicable
Source: API 1988; KMS 1986b.
C-7
-------
C3 NUMBER OF PLATFORMS PER DISCOVERY WELL
The number of platforms per discovery well is a measure of the quantity of
reserves identified by that well. In the economic model, the cost of all
exploratory wells (successful and unsuccessful) is divided among the number of
platforms that tap the discovered field.
The most recent year for which we have consistent data for the number of
discovery wells and the number of platforms is 1984. As of 1 January 1985,
there were 936 discovery wells in the Gulf of Mexico (see Table C-5). At the
end of 1984, there were 3,155 platforms in Federal waters and an additional
901 in State waters (MMS 1986c). This results in a ratio of (3,155+901)/936,
or 4.3 production platforms per discovery.
For the Pacific, older offshore discoveries are produced from onshore
completions and from artificial islands; a historical analysis is unlikely to
provide a valid ratio. Based on the number of platforms installed in existing
identified fields (see Table A-l), a projected ratio of 2.0 platforms per
discovery is used in this analysis.
For the Atlantic, no historical data exist. The 5-Year Leasing Plan for
mid-1987 to mid-1992 utilizes one-platform scenarios for the Atlantic (MMS
1987b, Appendix K). A 1:1 ratio of platforms to discoveries is used here.
For Alaska, relatively few wells are projected to be drilled during the
1986-2000 period (see Section 4). Such a situation could occur if only one
platform is drilled per discovery well and that assumption is used here.
C.4 RATIO OF EXPECTED PRODUCTION
Section C.I derives the average lease cost for a project in various DCS
regions. The average lease cost should be scaled upwards or downwards
according to the size of the model project. For each region, a typical
project is chosen. The lease prices for the other projects in the region are
scaled upwards or downward depending whether the project is larger or smaller
than the typical project. The number of producing wells in the project is
used as a surrogate index to represent the expected value of reserves used by
a company in formulating a bid. This assumes that if, for example, a tract
results in a 58-well platform, the company had good reason to believe that a
very large reservoir underlay the tract prior to bidding.
C-8
-------
For the Gulf, a project with 4 producing wells is considered typical
(i.e., the Gulf 4 project). As of October 1985, there were 1,563 platforms
with 4 wells or less (see Table A-3) while there was a total of 3,155
platforms (all sizes) at the end of 1984 (MMS 1986c). A 4-well platform has a
production ratio of 1.0 and the lease price is scaled accordingly.
For the Pacific, the 40-well platform with 33 producing wells is
considered typical. The 70-well platform with 60 producing wells has a
production ratio of 1.8. Only one project is envisioned for the Atlantic, so
the production ratio must be 1.0.
Projects in Cook Inlet. Alaska, are already scaled according to expected
production (20 producing wells for oil or oil/gas, and 10 producing wells for
the gas-only project), so the production ratio is 1.0 for Cook Inlet projects.
For the Arctic projects, 40 producing wells is considered typical, thereby
giving the smaller Norton Basin project a production ratio of 0.7.
Table C-6 lists the model projects, number of producing wells, production
ratios, average lease prices, number of exploratory wells per discovery wells,
and the number of platforms per discovery. The right-hand column of Table C-6
is the model project lease price used in the economic analysis.
C.5 REFERENCES
Alaska 1987. Alaska Department of Natural Resources, Five-Year Oil and Gas
Leasing Program. January 1987.
API 1988. Basic Petroleum Data Book. American Petroleum Institute, Vol. VIII,
No. 1, January 1988.
MMS 1986a. U.S. Department of the Interior, Minerals Management Service,
Outer Continental Shelf Statistical Summary 1986. OCS Report, MMS 86-0122,
December 1986.
MMS 1986b. U.S. Department of the Interior, Minerals Management Service,
Atlantic Summary Index: January 1985 - June 1986. OCS Information Report,
MMS 86-0071.
MMS 1986c. U.S. Department of the Interior, Minerals Management Service,
Federal Offshore Statistics: 1984. OCS Report, MMS 86-0067.
MMS 1987a. U.S. Department of the Interior, Minerals Management Service,
Federal Offshore Statistics: 1985. OCS Report, MMS 87-0008.
MMS 1987b. U.S. Department of the Interior, Minerals Management Service,
Proposed 5-Year Outer Continental Shelf Oil and Gas Leasing Program. Mid-
1987 to Mid-1992. Final Environmental Impact Statement, MMS 86-0127,
January 1987.
C-9
-------
Stease.wkl
28-NOV-89
TABLE C-6
LEASE PRICES FOR MODEL PROJECTS
Number of
Model Producing Production
Region Project Wells Ratio
Gulf 1
4
6
12
24
40
58
Pacific 16
40
70
Atlantic 24
Alaska Cook Inlet
Cook Inlet-gas
Beaufort-gravel
Beaufort-plat.
Norton
Navarin
1
4
6
10
18
32
SO
14
33
60
20
20
10
40
40
28
40
0.3
1.0
1.5
2.5
4.5
8.0
. 12.5
0.4
1.0
1.8
1.0
1.0
1.0
1.0
1.0
0.7
1.0
Exploratory
Lease Wells/ Model
Price Discovery Platforms/ Project Lease
($000) Well Discovery Price ($000)
$1,318
$1,318
$1,318
$1,318
$1,318
$1,318
$1,318
$1,423
$1,423
$1,423
$0.475
$15
$15
$1,918
$1,918
$1,918
$1,918
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
10.00
3.70
3.70
3.70
3.70
3.70
3.70
4.3
4.3
4.3
4.3
4.3
4.3
4.3
2.0
2.0
2.0
1.0
1.0
1.0
1.0
1.0 '
1.0
1.0
$568
$2,271
$3,407
$5,678
$10,221
$18,170
$28,391
$2,236
$5,272
$9,585
$5
$56
$56
$7,097
$7,097
$4,968
$7,097
Note: 1986 dollars.
Source: ERG estimates.
C-10
-------
APPENDIX D
EXPLORATION COST ASSUMPTIONS
The exploration phase assumptions include geological and geophysical
expenses, discovery efficiency, drilling costs, and the number of platforms
built per successful exploration well. The data and methodology used to
develop estimates for each of these parameters are discussed in separate
sections below.
D.I GEOPHYSICAL AND GEOLOGICAL COSTS
Before a decision is made to drill, the proposed site is subjected to a
variety of geological and geophysical prospecting procedures. These may
include seismic analysis of the particular site and a study to evaluate the
geological structures with regard to known neighboring productive formations.
These costs are modeled as a percentage of the lease bid. For offshore
production in the lower 48 states, this percentage has ranged from 6.5 percent
in 1980 to 16.3 percent in 1984 to 110.5 percent in 1986 (Commerce 1982, API
1986, API 1987a). Onshore and offshore components have not been separated for
Alaska in the recent API surveys. For this region, geological and geophysical
costs have ranged from 33 percent of lease bids in 1980 to 12.6 percent in
1984 to 107.7 percent in 1986 (Commerce 1986, API 1986, API 1987a). The 1986
values are used in this analysis.
D.2 DISCOVERY EFFICIENCY
A discovery efficiency is the fraction of wells drilled that are
successful in locating economically recoverable deposits of oil and/or gas.
This parameter has been discussed in Section C.2. The discovery efficiencies
are repeated in Table D-l for convenience.
D-l
-------
disceffZ.wkl
TABLE D-1
TOTAL EXPLORATORY OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Region
Alaska
California
Oregon
Washington
Federal Pacific
TOTAL PACIFIC
Alabama
Florida
Louisiana
Texas
Federal -COM
TOTAL GULF OF MEXICO
ATLANTIC
GRAND TOTAL
Oil
20
44
0
0
0
44
0
0
267
45
0
312
0
376
Gas
7
10
0
0
0
10
2
0
349
273
0
624
0
641
Dry
73
294
8
6
38
346
0
24
3999
1732
241
5996
46
6461
Number of
Exploratory
Discovery Wells Per
Total Efficiency Discovery
100
348
8
6
38
400
2
24
4615
2050
241
6932
46
7478
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.00
0.14
3.70
7.41
7.41
na
7.35
Note: Well count includes wells in both Federal and State waters.
na = not applicable
Source: API 1988; HMS 1986a.
D-2
-------
DJ DRILLING COSTS
The drilling costs per well are based upon the data in the 1986 Joint
Association Survey on Drilling Costs (API 1987b). The number of oil or gas
wells, footage drilled, and costs for the different state and federal offshore
regions are given in Table D-2. Regional summaries are given for the Gulf of
Mexico, Pacific and Alaska. There were no offshore wells drilled in the
Atlantic in 1986. The data in Table D-2 include exploratory, delineation, and
development wells (Oshinski 1988).
Table D-3 summarizes average well depths and costs. What is apparent is
that dry holes tend to have a higher cost per foot than productive wells,
particularly in Alaska and the Pacific. These data highlight some of the
distinctive features of offshore operations. Exploratory and delineation
wells are drilled from mobile drilling rigs and this is more expensive than
drilling development wells from a fixed platform. Exploratory and delineation
wells are plugged and abandoned at the end of operations after all information
is gathered. Even if economically recoverable deposits of petroleum are
identified, exploratory wells are not turned into production wells. Dry hole
costs, then, predominantly reflect exploratory well costs. There is some
corruption by a small number of dry development wells. It is not possible to
separate these effects from the available data, but the effects are presumed
to be minor. On this basis, dry hole costs for each region are used as
exploratory well costs.
Exploratory well costs must still be estimated for the Atlantic region.
The most recent wells drilled in the Atlantic were drilled in 1984. The 1984
survey on drilling costs lists three dry exploratory wells in the Atlantic;
see Table D-4 (API 1985). We update these values to 1986 costs by multiplying
them by the 15 percent increase seen in cost/foot for all dry offshore wells
from 1984 to 1986. Total well cost is obtained by multiplying the updated
cost per foot by the average depth of the 1984 well.
D.4 NUMBER OF PLATFORMS PER DISCOVERY WELL
The cost of the lease and exploration efforts is shared by number the
number of platforms built per discovery well. This number of platforms per
discovery well is discussed in Section C.3. For convenience, the information
is reproduced here:
D-3
-------
well cost.wk!
30-NOV-89
TABLE D-2
1986 WELL COST DATA - BY WELL
TYPE
O
Region
Alaska
California
Louisiana
Texas
Fed-Alaska
Fed - Gulf
Fed-Pacific
AK- TOTAL
PAC- TOTAL
GULF -TOTAL
ALL OFFSHORE
Wells
10
47
228
7
0
34
7
10
54
269
333
Oil
Footage
108.676
323.667
2.206,577
58.765
0
393.808
47.436
108,676
371,103
2,659,150
3,138,929
C
$36,457.
$74.432.
$604,890,
$18,122,
$282,072,
$25.014,
$36.457.
$99.446,
$905,085,
$1.040,990,
ost
731
135
041
985
$0
709
462
731
597
735
063
Wells
1
2
122
69
0
13
0
1
2
204
207
Gas
Footage
7,721
12,954
1,323.456
827,623
0
128,355
0
7,721
12,954
2,279.434
2.300,109
$1,790
$9,342
$446,385
$402,712
$81,014
$1,790
$9,342
$930,112
$941.245
Cost
,891
.182
,625
.576
$0
.100
$0
,891
.182
,301
,374
Wells
2
0
219
59
3
70
5
5
5
348
358
Dry
Footage
19.323
0
2.384,433
641,928
26,605
861,091
35,316
45,928
35.316
3,887,452
3,968,696
Cost
$20,232,190
$0
$721,363,323
$241,973,709
$49,022,867
$552,048,104
$29,438,964
$69,255,057
$29,438.964
$1.515.385,136
$1,614,079,157
Note: Current dollars.
Source: API 19876.
-------
TABLE 0-3 30-NOV-89
AVERAGE WELL DEPTHS AND COSTS - 1986 DATA
O
Region
Alaska
California
Louisiana
Texas
Fed-Alaska
Fed - Gulf
Fed-Pacific
AK- TOTAL
PAC- TOTAL
GULF -TOTAL
ALL OFFSHORE
Oil
Depth Cost per
(ft) foot ($/ft)
10.868
6.887
9.678
8,395
ERR
11.583
6.777
10.868
6.872
9.885
9.426
$335.47
$229.97
$274.13
$308.40
ERR
$716.27
$527.33
$335.47
$267.98
$340.37
$331.64
Cost per
well ($)
$3.645,773
$1,583.662
$2.653.026
$2.588.998
ERR
$8,296,256
$3,573.495
$3.645.773
$1,841.604
$3,364,631
$3,126,096
Gas
Depth Cost per
(ft) foot ($/ft)
7,721
6.477
10,848
11.995
ERR
9,873
ERR
7,721
6,477
11,174
11,112
$231.95
$721.18
$337.29
$486.59
ERR
$631.17
ERR
$231 .95
$721.18
$408.05
$409.22
Cost per
well ($)
$1,790,891
$4.671,091
$3.658.899
$5,836,414
ERR
$6,231,854
ERR
$1,790,891
$4,671,091
$4,559.374
$4.547,079
Depth
(ft)
9,662
ERR
10,888
10.880
8.868
12.301
7.063
9.186
7.063
11,171
11.086
Dry
Cost per
foot ($/ft)
$1,047.05
ERR
$302.53
$376.95
$1,842.62
$641.10
$833.59
$1,507.90
$833.59
$389.81
$406.70
Cost per
well ($)
$10,116,095
ERR
$3,293,896
$4,101.249
$16.340,956
$7,886.401
$5,887.793
$13.851.011
$5.887,793
$4.354.555
$4.508.601
Depth
(ft)
10,440
6.870
10,394
11.321
8.868
11,823
6,896
10,145
6,875
10.750
10.476
Total
Cost per
foot ($/ft)
$430.89
$248.87
$299.71
$433.69
$1,842.62
$661.58
$658.03
$662.27
$329.61
$379.62
$382.27
Cost per
well ($)
$4,498,524
$1,709,680
$3,115.359
$4.909,698
$16,340,956
$7,821,666
$4,537.786
$6,718,980
$2,266,029
$4,081.100
$4,004,805
Notes: Current dollars.
ERR denotes no wells drilled in that category in 1986.
Source: API 1987b.
-------
Atl uell.wkl
30-NOV-89
TABLE D-4
EXPLORATORY WELL COSTS FOR ATLANTIC REGION
O
Region
Offshore-Dry
Atlantic-Dry
Year
1984
1986
1984
1986
Wells
1.421
358
3
Footage
14,259,153
3.968,696
45,371
Cost
$5,023,946,644
$1,614,079,157
$72,228,519
Depth
(ft)
10.035
11.086
15,124
15,124
Average
Cost per
Well ($)
$3.535,501
$4,508.601
$24,076,173
$27.791,575
Cost per
Foot ($/ft)
$352.33
$406.70
$1,591.95
$1,837.62
Ratio of
Cost per
Foot
1.15
Notes: Current dollars.
1986 well costs for the Atlantic projected by multiplying 1984 cost per foot by ratio of
1986/1984 costs per foot for offshore wells
Source: API 1985; API 1987b.
-------
Alaska - one platform per discovery
Atlantic - one platform per discovery
Gulf - 4.3 platforms per discovery
Pacific - 2 platforms per discovery.
D.5 REFERENCES
API 1986. American Petroleum Institute, 1984 Survey on Oil and Gas
Expenditures. Washington, DC, October 1986.
API 1985. American Petroleum Institute, 1984 Joint Association Survey on
Drilling Costs. Washington, DC, 1985.
API 1987a. American Petroleum Institute, 1986 Survey on Oil and Gas
Expenditures. Washington, DC, December 1987.
API 1987b. American Petroleum Institute, 1986 Joint Association Survey on
Drilling Costs. Washington, DC, November 1987.
API 1988. American Petroleum Institute, Basic Petroleum Data Book. Vol.
VIII, No. 1, January 1988.
Commerce 1982. U. S. Department of Commerce, Bureau of the Census, Annual
Survey of Oil and Gas. 1980. Current Industrial Reports, MA-13k(80)-1,
March 1982. These surveys were not continued beyond 1982 data. The
American Petroleum Institute (API) undertook its survey due to the
termination of the one by the Bureau of the Census. Efforts have been
made to maintain continuity between the surveys although less detailed
information is available in the API publications.
MMS 1986. U.S. Department of the Interior, Minerals Management Service.
Atlantic Summary/Index: January 1985 - June 1986. OCS Information Report,
MMS 86-0071.
Oshinski 1988. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and John Oshinski, Statistics Department, American
Petroleum Institute, Washington, DC, 22 February 1988.
D-7
-------
APPENDIX E
DELINEATION PHASE ASSUMPTIONS
The delineation phase of offshore oil and gas reserves involves the
collection of adequate geological and reservoir data to determine the size,
shape, and physical characteristics of the discovered energy supply. This
usually involves drilling one or more delineation wells. The two parameters
of interest for this phase are: cost per delineation well, and number of
delineation wells per project. Each parameter is discussed in a separate
section below.
E.1 COST PER DELINEATION WELL
Delineation wells differ from exploration wells in that more geologic data
are collected in the form of directional drilling and cores and logs. The
well costs presented in the Joint Association Survey on drilling costs,
however, are a composite of all wells - exploratory, delineation, and
development (Oshinski 1988). For this study, we use the same cost for
delineation wells as for exploration wells, that is, dry hole costs. The
logic behind using dry hole costs is discussed in Section D.3. The regional
delineation well costs are presented here for convenience:
. Atlantic - $27,791,575.
. Alaska - $13,851,011.
. Pacific - $5,887,793.
. Gulf of Mexico - $4,354,555.
E.2 NUMBER OF DELINEATION WELLS PER PROJECT
The OTA report on oil and gas technologies for the Arctic and deepwater
assume that 5 delineation wells will be used except for the nearshore Gulf of
Mexico where only 3 are drilled (OTA 1985, p. 118). Table E-l summarizes
information on the number of delineation wells planned or drilled for several
projects. As may be seen from this data, the OTA estimates are too high. In
E-l
-------
delin.wkl
30-NOV-89
TABLE E-1
NUMBER OF DELINEATION WELLS FOR TYPICAL OFFSHORE PROJECTS
Region
Alaska
Pacific
Gulf of
Mexico
Field
Endicott
(Sag River/
Duck Island)
Seal Island
Sandpiper
Colville Delta
Sockeye
Huesco
High Island
Vermill ion
S. Marsh Is.
Matagorda Is.
Mustang Is.
Green Canyon
Viosca Knoll
Number of
Delineation
Block Wells
A -487
A -476
76
236
487
739
21
52
60
862
3
3-4
2
4
3
1
1
1
1
1
1
2-3
2
2-4
2-3
1
References
OGJ 1984
Ocean Industry 1986a
Ocean Industry 1986a
Ocean Industry 1986a
PEI 1983
PEI 1983
Ocean Industry 1982
Ocean Industry 1982
Ocean Industry 1982
Ocean Industry 1982
Ocean Industry 1986b
Ocean Industry 1986b
Ocean Industry 1986b
Ocean Industry 1986b
Ocean Industry 1986b
Ocean Industry 1986b
E-2
-------
addition to the data in Table E-l, it should be noted that some projects in
the Gulf of Mexico proceed without delineation wells. For example, Standard
Oil is seeking in-house design approval of a platform for development of a
discovery on Ewing Bank block 826, without any mention of delineation wells
(Ocean Industry, 1986b).
On the basis of this information, ERG proposes the following number of
delineation wells per project:
No delineation wells - Gulf 1 and Gulf 4.
1 delineation well - Gulf 6.
2 delineation wells - Gulf 12, Gulf 24, Gulf 40, Gulf 58, Atlantic 24,
Pacific 16, Pacific 40, Pacific 70, Cook Inlet 24, and Cook Inlet 12.
3 delineation wells - Beaufort Sea gravel island, Beaufort Sea
platform, Bering platform and Norton platform.
E3 REFERENCES
Ocean Industry 1982. "Oil & Gas Wrapup," Ocean Industry. June 1982, pp.
113-119.
Ocean Industry 1986a. "Exploration and development continue in Beaufort Sea,"
Ocean Industry. October 1986, pp. 34-40.
Ocean Industry 1986b. "Gulf of Mexico operators respond to new challenges,"
Ocean Industry. October 1986, pp. 15-20.
OGJ 1984. "Exxon wants Big Expansion Unit on North Slope," Oil and Gas
Journal. February 20, 1984, pp. 34-35.
Oshinski 1988. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and John Oshinski, Statistics Department, American
Petroleum Institute, 25 February 1988.
OTA 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of
Technology Assessment, Washington DC, 1985.
PEI 1983. "The Pacific Coast," Petroleum Engineer International 55, December
1983, pp. 21-23.
E-3
-------
APPENDIX F
DEVELOPMENT PHASE ASSUMPTIONS
The development phase involves the construction and installation of
production structures and the drilling of development wells. The parameters
needed to define the development phase of the economic model are:
Platform/gravel island cost
Lease equipment cost (also known as deck equipment cost)
Development well cost
Number of development wells
Number of wells installed each year.
Each of these parameters is discussed in a separate section below.
F.I PLATFORM/GRAVEL ISLAND COST
The Joint Association Survey on drilling costs instructs the operator to
report expenditures through the "Christmas tree," the assembly of valves,
pipes and fittings used to control the flow of oil and gas from the
casinghead. For our project, it is instructive to quote from the instructions
for the survey:
"Do not report the cost of lease equipment such as artificial lift
equipment and downhole lift equipment, flow lines, flow tanks, separators,
etc. that are required for production...
For OFFSHORE WELLS, include costs on fixed platforms and islands. Where
facilities serve more than one well, the costs should be allocated to each
well on the basis of the operator's best current estimate of the ultimate
number of wells that will use the facility. Also include cost expirations
(depreciation and amortization) for company-owned mobile platforms,
barges, and tenders."
(API 1987a, Appendix B, p.l)
In other words, platform and island costs are included in the well costs used
in this report. Lease equipment costs, however, are not included in the well
costs and are estimated separately in Section F.2.
F-l
-------
F.2 LEASE EQUIPMENT COSTS
For the offshore production in the Lower 48 States, the average cost of
lease equipment is based on the 1986 Annual Survey of Oil and Gas Expenditures
line entry for lease equipment (API 1987b, Table III). The 1986 expenditure
for offshore lease equipment is $1,032 million. According to the JAS survey
on drilling, 898 offshore wells were drilled in 1986; 885 of these were in the
Lower 48 States. This results in an average of $1.166 million ($1,032/885) in
lease equipment per offshore well. We are indebted to John Oshinski of API
for pointing out this method of obtaining lease equipment costs (Oshinski
1988). To obtain the lease equipment costs for each project, we multiply
$1.166 million by the number of producing wells in that project; see Table F-
1.
A different procedure must be used for Alaska because the Survey does not
differentiate between onshore and offshore costs for lease equipment (API
1987b) . Several different sources of actual and estimated costs are used for
the Alaska projects.
For the Cook Inlet projects, costs are based on the recently installed
Steelhead platform. OGJ 1986 refers to a $200 million project. We use an
estimate of $200 million for the lease equipment cost for the 48-wellslot
platform. Using the same assumption as OTA 1985, that there are no economies
of scale on development costs, lease equipment costs are estimated at $100
million for the 24-wellslot platform and $50 million for the 12-wellslot
platform. This is approximately $5 million per producing well, or about four
times as expensive as for projects in the Lower 48 States offshore region.
The development cost for the Beaufort Gravel Island is based on the
figures available for the Endicott field. Offshore 1986 cites a $1.4 billion
development cost. Ocean Industry 1987b mentions that the gravel project was
completed ahead of schedule and $600 million under budget. This results in an
estimate of $800 million to develop the Endicott field. The study by the
Office of Technology considers platform and facilities to account for 65 to 70
percent of total development costs (OTA 1985, p.. 118). Since estimates for
drilling in the Endicott field will not be available until the 1987 JAS at the
earliest, we follow the OTA methodology and use the midpoint, 67.5 percent, as
the percentage of development costs not associated with drilling. This
results in an estimated $540 million in lease equipment costs. Since the
Endicott field has two islands, the estimated cost per island is $270 million,
or about $6.75 million per producing well.
F-2
-------
Equip.wk1
TABLE F-1
LEASE EQUIPMENT COSTS - GULF, PACIFIC AND ATLANTIC
Region
Gulf
Pacific
Project
1b
4
6
12
24
48
58
16
40
70
Number of
Producing
Wells
1
4
6
10
18
32
50
14
33
60
Lease Equipment
Costs (SUM 1986)
$1.166
$4.664
$6.996
$11.660
$20.988
$37.312
$58.300
$16.324
$38.478
$69.960
Atlantic 24 20 $23.320
Source: ERG estimates.
F-3
-------
The lease equipment costs for the Beaufort platform. Navarin platform and
Norton platform are based on the information in OTA 1985. For the Arctic
deepwater projects, only engineering estimates are available since there are
no such existing projects. We begin with the OTA estimated development costs
(Table F-2, righthand column), obtain the non-drilling development costs by
multiplying by 67.5 percent, and divide by the number of platforms/islands in
the scenario. The resultant 1984 costs are then deflated by 0.4 percent to
1986 costs based on the implicit price deflators for gross national product
for producers' durable equipment (Economic Report 1987, Table B-3).
Table F-2 summarizes the cost estimates for the Alaska projects. Lease
equipment costs range from $50 million in Cook Inlet to $524.4 million in the
Navarin Basin. On a per-producing-well basis, lease equipment costs range
from $5 million to $13.11 million, or 4 to 12 times the cost for offshore
wells in the Lower 48 States. As a check on these figures, we divide the
$1,039 million spent in 1986 for lease equipment (API 1987a) by the 257 wells
drilled in Alaska in 1986 (API 1987b). This is approximately $4 million per
well. If lease equipment costs are less for onshore wells in Alaska as they
are in the Lower 48 States, then the estimate falls within the range projected
for the analysis.
F3 DEVELOPMENT WELL COSTS
Development well costs are based on the costs for productive wells (see
Table F-3). These estimates must be adjusted upwards to account for dry
development wells. The regional discovery efficiencies for offshore
development wells are given in Table F-4. The composite cost for a
development well is the cost of a productive development well plus the
fraction of a dry development well. The equation used is:
Composite cost for a - Cost per development well +
development well [Number of development wells per producing well - 1)
*(dry hole cost per foot) * depth of producing well
For an oil well in the Gulf of Mexico, the composite development well cost is
$3,364,631 (+ .4 x $389.81 x 9,8885) or $4,905,866. Table F-5 summarizes
development well costs for the Gulf of Mexico. Pacific and Alaska regions.
There have been no development wells drilled in the Atlantic. As
discussed in Appendix D, exploratory well costs are higher than development
F-4
-------
$_akcon.wk1
TABLE F-2
LEASE EQUIPMENT COSTS FOR ALASKA PROJECTS
Development Non-drilling Number of
Cost Development Islands/
Project ($MM 1984) Cost ($MM 1984) Platforms
"3
en
Beaufort platform 3,162
Mavarin Basin 5,460
Norton Basin 1,038
Beaufort Gravel* 800
Cook Inlet oil*
Cook Inlet gas*
Notes: * Costs are in 1986 dollars.
1984 prices deflated by 0.4%
2,134.4
3,685.5
700.7
540.0
200.0
200.0
based on implicit
7
7
4
2
2
4
price
Cost per Cost per Producing Cost per
Platform Platform Wells per Uell
($MM 1984) ($MM 1986) Platform ($MM 1986)
$304.9
$526.5
$175.2
$270.0
$100.0
$50.0
deflators for gross
$303.7
$524.4
$174.5
$270.0
$100.0
$50.0
national
40 $7.59
40 $13.11
28 $6.23
40 $6.75
20 . $5.00
10 ' $5.00
product for producers' durable equipment.
Sources: OTA 1985; OGJ 1986; Offshore 1986; Economic Report 1987.
-------
TABLE F-3 30-NOV-89
AVERAGE WELL DEPTHS AND COSTS - 1986 DATA
Region
Alaska
Cal ifornia
Louisiana
Texas
Fed-Alaska
Fed - Gulf
Fed-Paci fie
AK- TOTAL
PAC-TOTAL
GULF -TOTAL
ALL OFFSHORE
Depth
(ft) f
10,868
6,887
9,678
8,395
ERR
11,583
6,777
10,868
6,873
9,885
9,426
Oil
Cost per
oot ($/ft)
$335.47
$229.97
$274.13
$308.40
ERR
$716.27
$527.33
$335.47
$267.98
$340.37
$331.64
Cost per
well ($)
$3,645,773
$1,583,662
$2,653,026
$2,588,998
ERR
$8,296,256
$3,573,495
$3,645,773
$1,841,604
$3,364.631
$3,126,096
Depth
(ft) f
7,721
6,477
10,848
11,995
ERR
9,873
ERR
7,721
6,477
11,174
11,112
Gas
Cost per
oot ($/ft)
$231.95
$721.18
$337.29
$486.59
ERR
$631.17
ERR
$231.95
$721.18
$408.05
$409.22
Cost per
well ($)
$1,790,891
$4,671,091
$3,658,899
$5,836,414
ERR
$6,231,854
ERR
$1,790,891
$4,671,091
$4,559,374
$4,547,079
Depth
(ft)
9,662
ERR
10,888
10,880
8,868
12,301
7,063
9,186
7,063
11,171
11,086
Dry
Cost per
foot ($/ft)
$1,047.05
ERR
$302.53
$376.95
$1,842.62
$641.10
$833.59
$1,507.90
$833.59
$389.81
$406.70
Cost per
well ($)
$10,116,095
ERR
$3,293,896
$4,101,249
$16,340,956
$7,886,401
$5,887,793
$13,851,011
$5,887,793
$4,354,555
$4,508,601
Depth
(ft)
10,440
6,870
10,394
11,321
8,868
11,823
6,896
10,145
6,875
10,750
10,476
Total
Cost per
foot ($/ft)
$430.89
$248.87
$299.71
$433.69
$1,842.62
$661.58
$658.03
$662.27
$329.61
$379.62
$382.27
Cost pei
well ($)
$4,498,524
$1,709,680
$3,115,359
$4,909,698
$16,340,956
$7,821,666
$4,537,786
$6,718,980
$2,266,029
$4,081,100
$4,004,805
a\
Notes: Current dollars.
ERR denotes no wells drilled in that category in 1986.
Source: API 1987b.
-------
dev disc
TABLE F-4
TOTAL DEVELOPMENT OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Number of
Development
Discovery Wells Per
Region
Alaska
California
A I abama
Louisiana
Texas
Federal -COM
TOTAL GULF OF MEXICO
ATLANTIC
Oil
259
3516
1
8144
104
69
8318
0
Gas
13
25
1
4283
454
19
4757
0
Dry
32
327
1
4480
700
58
5239
0
Total Efficiency Producing Well
304
3868
3
16907
1258
146
18314
0
0.89
0.92
0.67
0.74
0.44
0.60
0.71
0.00
1.12
1.09
1.40
na
Note: Well count includes wells in both Federal and State waters.
na = not applicable
Source: API, 1988.
F-7
-------
dev_cost.wk1
TABLE F-5
DEVELOPMENT WELL COST - 1986 DATA*
Number of
Development
Wells Per
Type of Producing
Region
Gulf
Pacific
Alaska
Atlantic
Production
oil,
gas
oil.
gas
oil,
gas
oil,
gas
oi I /gas
oi I/gas
oi I/gas
oil /gas
Well
1.4
1.4
1.09
1.09
1.12
1.12
Average
Depth
(ft)
9,
11,
6,
6,
10,
7,
see
885
174
872
477
868
721
text
Cost per foot
Productive
$340
$408
$267
$721
$335
$231
.37
.05
.98
.18
.47 $1
.95 $1
($/ft)
Dry
$389
$389
$833
$833
,507
,507
.81
.81
.59
.59
.90
.90
for description
Composite Cost
per
Development
Well ($)
$4
$6
$2
$5
$5
$3
$7
,905,866
,301,845
,357,117
,157,007
,612,431
,187,985
,225,810
Note: Current dollars.
Source: ERG estimates, see Table D-2.
F-8
-------
well costs because of the need to drill them from mobile rigs. It is not
appropriate, then, to use Atlantic exploratory well costs as Atlantic
development well costs. Atlantic dry hole costs are projected at
$l,837.62/foot (see Table D-4). This is comparable to the 1986 dry hole cost
of $l,842.63/foot seen for drilling in Federal waters off the Alaskan coast
(Table D-4). We project Atlantic productive well costs based on the ratio of
oil-to-dry well costs for Alaska since the environment would not be harsher in
the Atlantic. In 1986, an average Alaskan oil well cost $3,645,773 or 26
percent of a dry hole. The projected Atlantic development well cost is'0.26 x
$27,791,575 or $7,225,810.
F.4 NUMBER OF PRODUCTION WELLS PER PLATFORM
The number of production wells in use at an offshore platform will vary
widely, depending on the success of drilling programs, the size of the
reservoir, the need for injection programs to maintain production, and project
economics. The MMS Platform Inspection System Complex list shows widely
varying situations. For example, some mature 12-wellslot platforms have never
produced from more than 3, 4, or 5 wellslots while others are producing from
all 12. Based on the MMS data, the average platform in the Gulf of Mexico is
producing from 3/4 to 5/6 of its wellslots. Model projects were defined to
fall within these bounds.
F.5 RATE OF INSTALLATION OF DEVELOPMENT WELLS
ERG has used the drilling rate of 6 wells per year per drilling rig. For
platforms with more than 12 wellslots, two drilling rigs are assumed. This
means that small projects, such as the Gulf 4, are brought to peak production
in their first year. Twelve well platforms are developed within 2 years while
larger platforms, e.g., 40 to 60 wells, require a 3- to 5-year development
period. The 1- to 5-year period corresponds well with the 1- to 4-year span
seen under "most intense development and production" in the MMS EIS for the 5-
year leasing program (MMS 1987, Table IV.A.1-1).
F.6 REFERENCES
API 1987a. 1986 Joint Association Survey on Drilling: Costs. American
Petroleum Institute, Washington, DC, November 1987.
F-9
-------
API 1987b. 1986 Survey on Oil and Gas Expenditures. American Petroleum
Institute, Washington, DC, November 1987.
API 1988. Basic Petroleum Data Book. Vol. VIII, No. 1, American Petroleum
Institute, Washington, DC, January 1988.
Economic Report 1987. Economic Report of the President. 1987. Council of
Economic Advisors, Washington DC, January 1987.
MMS 1987. U.S. Department of the Interior, Minerals Management Service.
Proposed 5-Year Outer Continental Shelf Oil and Gas Leasing Program. Mid-
1987 to Mid-1992. MMS 86-0127, January 1987.
Ocean Industry 1987a. "Giant fields set to boost California, Alaska output,"
Ocean Industry. October 1987, p. 27-33.
Ocean Industry 1987b. "Endicott oilfield development is on schedule," Ocean
Industry. August/September 1987, p. 25-26.
Offshore 1986. "The World Offshore: Alaska," Offshore. July 1986, p. 11.
OGJ 1986. "New Cook Inlet platform to get drilling modules," Oil and Gas
Journal. 17 November 1986, p. 32.
Oshinski 1988. Personal communication between Maureen F. Kaplan and John
Oshinski, Statistics Department, American Petroleum Institute, Washington,
DC, 25 February 1988.
OTA 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of
Technology Assessment, Washington, DC, May 1985.
F-10
-------
APPENDIX G
PRODUCTION/OPERATION PHASE ASSUMPTIONS
The production and operation phase of an offshore project encompasses the
period of time from first oil or gas production until shutoff of all wells.
Parameters required to define this phase include:
Peak production rate.
Production decline rate.
Time at peak production.
Annual operation and maintenance costs.
Each parameter is discussed in its own section below.
G.I PEAK PRODUCTION RATES
Well performance is a complex function of the thickness of the oil zone,
geometry of the zone, effective permeability of the zone to oil, effective
drainage radius of the well, and other factors. It is not surprising, then,
that peak production rates and production decline rates are two parameters for
which it is difficult to obtain "typical values." In this study, we assume
that peak production occurs in the first year of operation. Field data, where
available, are used to estimate average initial production rates.
G.1.1 Gulf of Mexico
Recent environmental impact statements for OCS sales in the Gulf of Mexico
use "typical production profiles" per well to back-calculate the number of
wells required to develop the estimated resources in the sale. The key factor
is the cumulative amount of oil and gas produced per well and this will vary
depending upon the region considered. The typical production profile has
production climbing for 5 years, remaining at peak production for 3 to 4 years
and then declining at rates between 5 percent and 10 percent per year. Gas
wells are assumed to peak a few years later than oil wells and then decline at
rates between 5 percent and 15 percent per year (Crawford, 1988).
G-l
-------
To use the information in the EIS in this analysis, we begin by looking az
the cumulative production per well. This ranges from 470,000 bbl per ./ell to
1,579,000 bbl per well. Gas production ranges from 5.3 BCF to 10 BCF (MMS.
1986, and MMS, 1987a). Oil wells typically have a 10- to 11-year lifetime.
while gas wells have a typical lifetime of 13 to 15 years (Crawford. 1988).
The MMS "typical" well is a composite of an oil well and a gas well.
There were 8,318 oil wells and 4,757 gas wells in the Gulf as of 1 January
1985 (see Table F-4). The number of projected wells is multiplied by 63.6
percent (8,313/13,075) to obtain the number of oil wells. The remaining wells
are assumed to be gas wells (see Table G-l, columns 3 and 4). Total
cumulative oil production is divided by the estimated number of wells to
calculate the cumulative production per oil well. The same procedure is
followed to obtain the cumulative production per gas well.
Exponential decline rates are calculated for an oil well using 2 years at
peak production, 10-year lifetime, an annual decline rate of 15 percent, and
setting the cumulative production to the minimum and maximum cumulative
production per oil well (740,384 and 2,481,937 bbl; see Table G-l). Initial
production rates are back-calculated to match the production profile. The
initial production rates for oil wells in the Gulf range from 330 bopd to
1,110 bopd. We use a value of 500 bopd to allow for the production of lease
condensate by gas wells. In 1985, the Gulf of Mexico OCS region produced
321,509,934 bbl of oil and 537,402 MMcf for an average of 1.671 Mcf gas
produced for every barrel of "oil (MMS, 1987b; DOE 1986, Table 3). For an
initial production rate of 500 bopd, there would be an associated 835 Mcf of'
gas production.
The same methodology is used to fit an exponential decline function to gas
production. The production assumptions are a 20-year lifetime, a 15 percent
annual decline rate, and four years at peak production. Cumulative produccion
per well ranges from 14,483,944 Mcf to 27,485,810 Mcf (see Table G-l). Back-
calculated initial production rates range from 4,000 Mcf/day to 8,000 Mcf/day.
We use a value of 4,000 Mcf/day to allow for the production of casinghead gas
by oil wells.
G-2
-------
gulfl.ukl
TABLE G-1
CUMULATIVE PRODUCTION PER WELL -
GULF OF MEXICO ASSUMPTIONS
30-NOV-89
Lease
Sale
110
112
113
115
116
COM
Region
Central
Western
Central
Western
Eastern
of
Wells
408
276
345
630
230
426
19
76
Estimated Number of
Oil
Wells
260
176
219
401
146
271
12
48
Gas
Wells
148
100
126
229
84
155
7
28
Total Cumulative Production
Oil
(MMbbls)
260
130
220
400
110
220
30
120
Gas
(Bcf)
2,150
1.870
1.840
3,870
1,610
2,870
180
760
Cumulative Production Per Well
Oil
(bbls)
1,001,696
740,384
1,002,366
998,027
751,775
811,775
2,481,935
2,481,935
Gas
(Mcf)
14,483,944
18,622,632
14,659,099
16,884,141
19,240,067
18,517,436
26,039,189
27,485,810
I
U)
Source: MMS 1986; MMS 1987a.
-------
G.1.2 Pacific
The California Department of Conservation maintains records of oil and zas
production in Federal and State waters. W. Guerard (1988) supplied peak
production rates per well for fields that started from 1980 and after; see
Table G-2. The peak production rates range from 286 bopd in the Santa Clara
field to 2,840 bopd in the Hondo field. We use a value of 900'bopd in our
model project. To estimate the amount of associated casinghead gas, we use
the 1986 gas-to-oil ratio for offshore California wells; see Table G-3. The
average ratio is 531 ft3/bbl, so the model project would have a peak
production of 900 bopd with 478 Mcf/day. An initial production rate of 5,000
Mcf/day is used for the gas-only project. This is lower than the first-year
production from the Pitas Point field, but we also assume a longer period a:
peak production (see below).
G.1.3 Alaska
The Alaska Oil and Gas Conservation Commission supplied first-year
production data for wells in Cook Inlet and the Beaufort Sea (Johnson, 1988)
Engineering studies form the basis for the estimates for the Norton and
Navarin Basin platforms.
Cook Inlet
Table G-4 calculates the average daily first-year production for 27 wells
on platforms in Cook Inlet. The production ranges from 19 bopd to 7,004 bopd.
ERG uses a value of 1,960 bopd in this analysis. Associated casinghead gas
ranges from 7 Mcf/day to 2,256 Mcf/day. A value of 900 Mcf/day is used for
the oil with casinghead gas projects in Cook Inlet.
Arctic Alaska
The Endicott field in the Beaufort Sea began production in late 1987.
There are 16 wells that began production in October. Table G-5 summarizes the
November and December production from those wells, i.e., the first full two
months of production. Production is likely to drop from the impressive
G-4
-------
ca_pcod.wk1 30-Nov-89
TABLE G-2
PEAK PRODUCTION RATES - CALIFORNIA
Year of
Peak Peak Production
Field Production bopd or Mcf/day
OIL PRODUCTION
Beta 1981 535
Hondo 1981 2,840
Hueneme 1982 1,074
Santa Clara 1980 286
Average oil 1,184
GAS PRODUCTION
Pitas Pt. 1985 11,185
Source: Guerard 1988.
G-5
-------
ca_og.wk1 30-Nov-89
TABLE G-3
1986 GAS TO OIL RATIOS - CALIFORNIA
Region
1986
Oi I and
Condensate
Field or Area (bbl)
1986
Associated
Gas
(Hcf)
Gas to Oil
Ratio
(cf/bbl)
State
Federal
District 1
District 2
District 3
Beta
Carpinteria
Dos Cuadras
Hondo
Hueneme
Santa Clara
30,238,026
1,333,390
3,061,615
7,040,207
1,978,018
5,063,795
11,100,847
644,002
2,893,559
7,404,239
3,087,795
2,419,052
2,444,898
1,524,822
2,557,080
10,370,192
178,251
3,635,212
TOTAL
63,353,459 33,621,541
245
2316
790
347
771
505
934
277
1256
531
Source: California 1987.
G-6
-------
cook.wkl
TABLE G-4
AVERAGE FIRST-YEAR PRODUCTION FOR OIL WELLS IN COOK INLET, ALASKA
Completion
Platform Year
Dolly Varden 68
68
68
68
68
68
68
68
63
68
Grayling 68
68
68
68
68
68
68
68
68
68
68
King Salmon 68
68
68
68
68
68
Hon
3
3
4
5
5
7
7
8
10
10
1
1
2
1
4
3
8
4
5
7
12
2
1
11
3
5
7
Date
Day
5
27
19
5
21
26
3
30
14
7
1
1
19
1
2
1
23
21
28
3
5
15
4
27
23
22
2
Year Production
Oil (bbl)
1,013,373
939,231
1,311,355
1,156,454
281,638
454,628
665,112
3,585
31,288
158,005
1,421,897
989, 160
1,323,508
1,955,376
541,645
1,385,189
374,595
839,892
4,227
631,633
56,108
1,686,065
1,180,773
99,971
989,789
971,676
1,274,686
Gas (Hcf)
298,105
269,847
367,279
319,006
85,455
126,515
171,993
891
8,658
40,598
391,143
261,991
394,258
586,373
124,537
364,644
116,415
205,396
0
191,365
13,981
474,326
326,314
24,366
280,947
257,253
410,560
Average Dai ly
Production
Oil (bbl)
3,367
3,366
5,122
4,819
1,257
2,877
3,675
29
401
1,859
3,896
2,710
4,188
5,357
1,984
4,542
2,882
3,307
19
3,490
2,158
5,269
3,262
2,940
3,497
4,357
7,004
Gas (Mcf)
990
967
1,435
1,329
381
801
950
7
111
478
1,072
718
1,248
1,607
456
1,196
896
809
0
1,057
538
1,482
901
717
993
1,154
2,256
Source: Johnson, 1988.
G-7
-------
endicott.wk!
04-Feb-91
TABLE G-5
INITIAL PRODUCTION FROM ENDICOTT FIELD, BEAUFORT SEA, ALASKA
Monthly Production
Nov
Oil (bbl)Gas (Mcf)
238,603
269,964
210,326
125,502
164,240
243,696
230,273
245,612
162,298
117,291
138,905
232,460
243,017
235,009
168,092
48,265
AVERAGE
193,044
223,977
174,992
98,358
118,966
202,388
230,547
202,071
135,626
98,165
105,438
182,227
201,925
318,449
244,519
38,415
Dec
Oil (bbt)
185,341
168,940
12,612
48,223
198,145
' 181,826
142,490
223,189
215,708
206,092
206,282
209,881
217,055
208,137
115.670
30,890
Gas (Mcf)
135,456
140,306
9,771
30,082
140,770
143,815
153,769
176,437
178,112
153,383
144,965
156,141
173,498
350,650
233,215
24,438
Total
Oil (bbl)
423,944
438,904
222,938
173,725
362,385
425,522
372,763
468,801
378,006
323,383
345,187
442,341
460,072
443,146
283,762
79,155
352,752
Gas (Mcf)
328,500
364,283
184,763
128,440
259,736
346,203
384,316
378,508
313,738
251,548
250,403
338,368
375,423
669,099
477,734
62,853
319,620
Average Average
bopd Mcf per day
6,950
7,195
3,655
2,848
5,941
6,976
6,111
7,685
6,197
5,301
5,659
7,251
7,542
7,265
4,652
1,298
5,783
5,385
5,972
3,029
2,106
4,258
5,675
6,300
6,205
5,143
4,124
4,105
5,547
6,154
10,969
7,832
1,030
5,240
Source: Johnson, 1988.
G-8
-------
average of 5,783 bopd, even within the first year, but it is apparent that
Endicott will be an enormous producer like neighboring Prudhoe Bay.
Table G-6 lists the various engineering estimates for oil production in
the Arctic. These range from 1,570 bopd in the Norton Basin to 4,000 bopd in
the Beaufort Sea, Navarin Basin and St. George Basin. We use an estimate of
1,960 bopd for the oil production scenario in Arctic Alaska. There is no
infrastructure for gas transport, so no oil/gas or gas-only scenarios are
considered for the Arctic regions.
G.1.4 Atlantic
No discoveries have yet been announced in the Atlantic on which to base
oil flow rates. The most recent EIS for the Atlantic Region is for DCS Sale
111 (MMS, 1985e). Like the Gulf of Mexico studies, a "typical production
profile" is used to determine the number of development wells. Cumulative
lifetime oil and gas production ranges from 3.4 to 4.5 million barrels and
66.7 to 74.1 Bcf. Decline rates appear to be in the order of 9 to 11 percent
per year. Assuming a 20-year production life and an annual decline rate of 10
percent, initial oil production ranges from 1,100 to 1,500 bopd. A
conservative estimate of 1,000 bopd is used in this analysis. Associated
casinghead gas is assumed to be produced at a rate of 1 MMcf per barrel of
oil, based on USGS estimates of recoverable reserves (USGS, 1981).
The estimated peak gas production rates range in the EIS from 21 to 23
MMcf per day. This value appears unrealistically high in view of the dry
holes of Georges Bank and Baltimore Canyon. A value of 7.5 MMcf/day/we11 is
used for the Atlantic model projects based on the assumption that geologic
formations conducive to the presence of large productive gas fields occur off
the Atlantic coast.
Table G-7 summarizes the model assumptions for peak production rates.
G.2 PRODUCTION DECLINE RATE
The pattern of decline in a well's productivity can vary greatly due to
many factors (see Section G.I). ERG models production decline as an
exponential function, i.e., a constant percentage of the remaining reserves
produced in any given year. A general rule of thumb is that peak production
G-9
-------
TABLE G-6
ENGINEERING ESTIMATE OF PEAK PRODUCTION RATES - ALASKA
PEAK
PRODUCTION RATE
DATA SOURCE
EIS
Scenario Studies
REGION
St. George Basin
N. Aleutian Basin
Norton Basin
Norton Basin
Beaufort Sea
Norton Basin
Navarin Basin
OIL GAS
BOPD MMCF/DAY SOURCE
4
3
1
3
4
4
2
4
,000 26.3
,500 26.6
,570 10.3
,000-'
,000
,000
,000
,000
MMS 1985a
MMS 1985b
MMS 1985c
MMS 1985d
OTA 1985
OTA 1985
OTA 1985
Source: As noted.
G-10
-------
TABLE G-7
PEAK OFFSHORE PER-WELL PRODUCTION RATES
OIL AND GAS
REGION PROJECT
Gulf
Pacific
Alaska3
Cook Inlet
Beaufort Sea - Gravel
Beaufort Sea - Platform
Norton
Navarin
Atlantic
1
4
6
12
24
40
58
16
40
70
12
24
48
48
34
48
24
OIL ONLY
BOPD
500
500
500
500
500
500
500
900
900
900
1,960
1,960
1,960
1,960
1,960
1,000
BOPD
500
500
500
500
500
500
500
900
900
900
1,960
1,000
MCF/DAY
835
835
835
835
835
835
835
478
478
478
. .
900
7,500
GAS -ONLY
MCF/DAY
4,000
4,000
4-, 000
4,000
4.000
4,000
4,000
5.000
. .
15,000
Source: ERG estimates. .
"There is no infrastructure to transport produced gas from the Arctic
scenarios.
G-ll
-------
represents 10 to 15 percent of total reserves for the first 2 years and cher.
declines approximately 15 percent per year (Muskat, 1949: North, 1985). The
decline rate for the Pacific is higher. Decline rate assumptions are
summarized in Table G-8.
G.3 YEARS AT PEAK PRODUCTION
The length of time each well will remain at peak production depends upon
the rate of reservoir pressure decline, as well as other factors. All oil and
oil/gas projects are assumed to remain at peak production for 2 years.
Gas projects in the Gulf and Pacific are assumed to remain at peak
production for 4 years (Crawford, 1988). For Alaska, gas projects are assumed
to remain at peak production for 16 years. Figure G-l shows the production
history of the North Cook Inlet gas field from 1969 through 1984 to support
this assumption. There are no data for the Atlantic and an 8-year value was
chosen for years at peak gas production.
G.4 OPERATION AND MAINTENANCE COSTS (O&M)
The annual 1986 costs of operating and maintaining an offshore platform
are taken from DOE 1987. This survey includes O&M costs for a 12-wellslot
platform in 100 and 300 feet of water as well as an 18-wellslot platform in
100, 300, and 600 feet of water (Table G-9).
A breakdown of the cost for a 12-wellslot platform in 100 feet of water is
given in Table G-10. The platform is assumed to be staffed 24 hours a day
with one crew. A crew is 12 people working 12 hours on and 12 hours off, so
six people are working at any given time. In the next cost subcategory,
equipment and administration, the term "surface equipment" refers to
production equipment, flow control valves, dehydrators/line heaters (for gas
operation) located on the platform surface. The third cost subcategory is
workover costs. For a 12-wellslot platform, it is assumed that the workover
rig takes one day to travel to the platforms, two days to set up, nine days co
workover three wells, two days to tear down the equipment, and one day to move
off. In other words, six of the fifteen days are for transit, set-up, and
break-down; costs that would be borne even if working over only one well.
G-12
-------
TABLE G-8
PRODUCTION DECLINE RATES
PRODUCTION DECLINE RATES (%)
REGION
PROJECT
OIL-ONLY
OIL/GAS
GAS-ONLY
Gulf
Pacific
Alaska
Atlantic
1 15
4 15
6 15
12 15
24 15
40 15
58 15
16 33
40 33
70 33
Cook Inlet 10
Beaufort Sea - Gravel 10
Beaufort Sea - Platform 10
Norton Basin 10
Navarin Basin 10
24 15
15
15
15
15
15
15
15
22
15
15
- = Not applicable.
Source: ERG estimates.
G-13
-------
NORTH COOK INLET FIELD. TERT1RRY GflS POOL PRODUCTION
0
-TI
T)
3
D
X
I'l
m
3D
CD
CD
I
I: I i
iliji
jOlipi
mm
n
0
OJ
Cl
JJ
in
Figure G-l. North Cook Inlet Field, Alaska: gas production.
^mrc
rce: Alaska 1984.
-------
gulf_o&m.wk1 04-Dec-89
TABLE G-9
1986 OPERATION AND MAINTENANCE COSTS FOR GULF OF MEXICO PLATFORMS
Water Cost
Uellslots Depth (ft) (1986 $)
12 100 $2,366,500
12 300 (2,482,300
18 100 $2,833,400
18 300 $2,963,100
18 600 S3,268,100
Source: DOE 1987.
G-15
-------
0&M_gulf.wk1
TABLE G-10
ANNUAL OPERATING COSTS - 12-SLOT PLATFORM IN GULF OF MEXICO
100 FT WATER DEPTH (1986$)
Model Projects
Component Subcategory
Component Cost ($) Cost ($) Gulf 1 Gulf 4 Gulf 6
Labor Subcategory $1,265,200 $770 $140,578 $210,867
Labor $528,900
Supervision $79,300
Payroll Overhead $211,600
Food Expense $55,200
Labor Transportation $374,700
Communications . $15,500
Equipment & Administrative Subcategory $605,900 $50,492 $201,967 $302,950
Surface equipment $84,600
Operating Supplies $16,900
Administrative $252,200
Insurance $252,200
Workover Subcategory
Workover $495,400 $495,400 $148,620 $346,780 $396,320
SUBTOTAL COSTS $2,366,500 $2,366,500 $199,882 $689,324 $910,137
Costs for operation of remote $172,331
production platform
TOTAL COSTS $2,366,500 $2,366,500 $372,213 $689,324 $910,137
Source: DOE 1987.
G-16
-------
These assumptions make it inappropriate to use the data from the 12-
wellslot and 18-wellslot platforms, perform a regression analysis, and
extrapolate back to the smaller Gulf projects. The DOE/EIA data for each of
the cost subcategories can be scaled to estimate the annual operating costs
for the smaller Gulf projects.
Table G-ll summarizes the assumptions for the labor subcategory for the
Gulf 1, Gulf 4, and Gulf 6 projects. The Gulf 1 is essentially untended; a
crew of two inspect the structure 4 times a year. One day is assumed for each
inspection. The Gulf 4 and the Gulf 6 platforms are assumed to have a crew of
4 and 6 people, respectively, that commute to the rig on a daily basis. The
work day is assumed to be eight hours. The labor costs for these small
projects are scaled from Gulf 12 costs as a percentage of labor hours. For
example, the Gulf 4 requires 11,680 person-hours a year or 11.11 percent of
hours required for the Gulf 12 platform. The labor costs for the Gulf 4
project are (11,680/105,120) x $1,265,200 or $140,578.
The equipment and administrative costs are scaled according to the number
of wells on the project. For example, the costs for this subcategory for the
Gulf 6 is $302,950 or one-half the costs for the Gulf 12 project.
Workover costs are also scaled. Gulf 1 projects are assumed to be worked
over every two years. Each workover takes 9 days (6 for preparation and
disassembly and three for the workover itself). The proportion of the
workover cost borne each year is (9/2)/15 or 30 percent. The Gulf 4 and Gulf
6 projects are assumed to workover an average of one and a half wells and two
wells per year, respectively. The cost proportions are (6 + 4.5)/15 or 70
percent and (6 + 6)/15 or 80 percent, respectively.
One last factor needs consideration. The Gulf la is assumed to have no
production equipment and shares a production platform with three other single
well structures. The 0 & M costs for the Gulf la therefore includes one-
fourth of the annual operating costs for a Gulf 4 platform.
The DOE/EIA data can be used to estimate annual operating costs for the
larger projects in the Gulf. To project O&M cost for the model projects, a
regression analysis was fit to the data using the following equation.
Cost - a. + b (wellslots) + c (depth)
G-17
-------
0&M_gutf.Hk1
TABLE G-11
LABOR ASSUMPTIONS FOR SMALL GULF PROJECTS
Labor Component
Hours per Day
Days per Year
People per Crew
Person-hours per Year
Fraction of DOE/EIA study
DOE/EIA
Study
24
365
12
105,120
100X
Model Project
Gulf 1
8
4
2
64
0.06X
Gulf 4
8
365
4
11,680
11. 1U
Gulf 6
8
365
6
17,520
16.67X
Source: DOE 1987; Funk 1989.
G-18
-------
The values for a, b, and c are $1,286,123, $80,859, and $840, respectively.
Table G-12 shows the estimated O&M costs for platforms in the Gulf of Mexico.
For the Pacific. Cook Inlet and Atlantic projects, we use the basic
equation presented above and then adjust for regional differences (see Table
G-13). The O&M costs for California onshore oil and gas operations are
approximately 144 percent of onshore operations for Texas and Louisiana (see
Table G-14). The regional multiplier for the Pacific is therefore 1.44. The
same multiplier is used for the Atlantic region. For Cook Inlet scenarios, a
multiplier of 1.6 is used (ERG 1985).
The information in OTA 1985 forms the basis for estimating the operating
costs for Arctic Alaska scenarios; see Table G-15. The costs per scenario are
divided among the number of platforms or islands and then deflated to 1986
values.
G.S REFERENCES
Alaska 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation
Commission, n.d.
California 1987. 72nd Annual Report of the State Oil and Gas Supervision:
1986. California Department of Conservation. Division of Oil and Gas,
Publication No. PR06, 1987.
Crawford 1988. Personal communication between Maureen F. Kaplan, Eastern
Research Group, and Gerald Crawford, MMS, COM Regional Office, New
Orleans, LA, 4 March 1988 and 7 March 1988.
DOE 1986. U.S. Department of Energy. Energy Information Administration,
Natural Gas Annual 1985. DOE/EIA-0131(85), November 1986.
DOE 1987. U.S. Department of Energy. Energy Information Administration,
Costs and Indices for Domestic Oil and Gas Field Equipment and Production
Operations 1986. DOE/EIA-0185(86), September 1987.
Economic Report 1988. Economic Report of the President. Council of Economic
Advisors, Washington, DC, February 1988.
ERG 1985. Economic Impact Analysis of Proposed Effluent Limitations and
Standards for the Offshore Oil and Gas Industry, prepared for the U.S.
Environmental Protection Agency by Eastern Research Group, Inc., EPA
440/2- 85-003, July 1985.
Funk 1989. Personal communication between Maureen F. Kaplan, Eastern Research
Group, Inc. and Velton Funk, DOE Energy Information Agency, 3 April 1989.
Guerard 1988. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and William Guerard, California Department of
Conservation, 2 March 1988.
G-19
-------
gulf_o&m.wk1
TABLE G-12
OPERATING COSTS FOR GULF OF MEXICO PLATFORMS
Project
Number of
Uellslots
Water
Depth (ft)
Cost
($1986)
Gulf 1a 1 33 $372,213
Gulf 1b 1 33 $199,882
Gulf A 4 33 $689,324
Gulf 6 6 33 $910,137
Gulf 12 12 66 $2,311,861
Gulf 24 24 100 $3,310,725
Gulf 40 40 200 $4,688,455
Gulf 58 58 590 $6,471,456
Source: ERG estimates.
G-20
-------
gulf_o&m.wk1
TABLE G-13
OPERATING COSTS FOR PACIFIC, ATLANTIC, AND COOK INLET PLATFORMS
Number of
Project Uellslots
Pacific 16
Pacific 40
Pacific 70
Atlantic 24
Cook Inlet 24
Cook Inlet 12
16
40
70
24
24
12
Water
Depth (ft)
300
300
1000
300
50
50
Regional
Cost Cost
($1986) Factor
$2,831,820
$4,772,439
$7,786,100
$3,478,693
$3,268,733
$2,298,424
1.44
1.44
1.44
1.44
1.60
1.60
Estimated
Cost
($1986)
$4,077,821
$6,872,312
$11,211,984
$5,009,318
$5,229,973
$3,677,478
Source: ERG estimates.
G-21
-------
ca_cost.uk1 04-Dec-89
TABLE G-14
RATIO OF 1986 OPERATION & MAINTENANCE COSTS - CALIFORNIA AND GULF COAST
Uell 0
Depth
(ft)
2,000
4,000
8,000
10,000
Average Ratio
peration & Maintenance Cost - 10 Primary Oil Wells
California
$119,700
$162,400
$280,200
$403,700
Louisiana
$117,600
$171,700
$203,000
$252,800
West Texas
$88,300
$102,200
$141,700
$188,900
South Texas
$98,500
$146,500
$175,100
$232,400
Average Gulf
$101,467
$140,133
$173,267
$224,700
Cal ifornia/
Gulf Coast
Ratio
1.18
1.16
1.62
1.80
1.44
Source: DOE 1987.
G-22
-------
ak_o&m.uk1
TABLE G-15
OPERATION AND MAINTENANCE COSTS FOR ALASKA PROJECTS
Project
Beaufort platform
Navarin Basin
Norton Basin
Beaufort Gravel
Operation and Number of
Maintenance Islands/
Cost ($MM 1984) Platforms
$168.0
$132.0
$72.0
$120.0
7
7
4
7
Cost per
Platform
<$MM 1984)
$24.0
$18.9
$18.0
$17.1
Cost per
Platform
($MM 1986)
$25.3
$19.9
$19.0
$18.1
Note: 1984 prices inflated by 5.56X based on change in consumer price index.
Sources: OTA 1985; Economic Report 1988.
G-23
-------
Johnson 1988. Individual well production printouts sent to Maureen F.
Kaplan, Eastern Research Group, Inc., by Elaine Johnson. Alaska Oil and
Gas Conservation Committee, 25 February 1988.
MMS 1985a. U.S. Department of the Interior, Minerals Management Service,
St. George Basin Sale 89: Final Environmental Impact Statement. MMS 85-
0029, April 1985.
MMS 1985b. U.S. Department of the Interior, Minerals Management Service,
North Aleutian Basin Sale 92: Final Environmental Impact Statement, MMS
85- 0052, September 1985.
MMS 1985c. U.S. Department of the Interior, Minerals Management Service,
Norton Basin Sale 100: Final Environmental Impact Statement. MMS 85-0085
December 1985.
MMS 1985d. U.S. Department of the Interior, Minerals Management Service,
Scenarios for Petroleum Development of the Norton Basin Planning Area -
Northeastern Bering Sea. OCS Report, MMS 85-0013.
MMS 1985e. U.S. Department of the Interior, Minerals Management Service,
Final Environmental Impact Statement. Atlantic OCS Region. OCS Sale 111.
MMS 85-0032.
MMS 1986. U.S. Department of the Interior, Minerals Management Service,
Final Environmental Impact Statement: Proposed Oil and Gas Lease Sales
110 and 112: Gulf of Mexico OCS Region. OCS EIS, MMS 86-0087, November
1986.
MMS 1987a. U.S. Department of the Interior, Minerals Management Service,
Final Environmental Impact Statement: Proposed Oil and Gas Lease Sales
113/115/116: Gulf of Mexico OCS Region. OCS EIS, MMS 87-0077, October
1987.
MMS 1987b. U.S. Department of the Interior, Minerals Management Service,
Federal Offshore Statistics: 1985. OCS Report, MMS 87-0008.
Muskat, M. 1949. Physical Principals of Oil Production. McGraw-Hill, New
York, NY.
North, F.K. 1985. Petroleum Geology. Allen & Unwin, Boston, MA, 1985.
OTA 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of
Technology Assessment, Washington, DC, May 1985.
USGS, 1981. United States Geological Survey. Circular 860.
G-24
-------
APPENDIX H
PRODUCED WATER ASSUMPTIONS
Peak water production is used in determining the equipment required on the
platform to comply with the proposed regulatory options. Average annual water
production is used to estimate the annual operation and maintenance cost (O&M)
for each platform. The capital (equipment) and O&M costs are factored into
the economic model for each platform to calculate the annualized cost for each
regulatory option. The total volume of produced water generated during the
1986-2000 time period is used to estimate the amount of pollutants removed by
each regulatory option.
The capital and O&M costs are calculated by EPA, Industrial Technology
Division on the basis of the produced water volumes presented in this
appendix. These costs will be documented in the Development Document
supporting the Offshore Oil and Gas regulation.
H.I MODELING ASSUMPTIONS
Modeling assumptions differ depending upon whether a well produces oil or
only gas. These assumptions are outlined in the sections below.
H.I.I Projects with Oil Production
For projects that produce oil or oil with gas, water production is
calculated as a function of total liquid production. In other words, the well
is assumed to produce a constant volume of fluid during its lifetime, but the
proportion of fluid that is water will increase as the well ages. To evaluate
water production as a function of total liquid production, we need to estimate
several parameters:
Relationship of oil decline and water increase
Functional form of oil production decline
Decline rate of oil production
Initial watercut (i.e., how much of the fluid is water at the time the
well first produces)
H-l
-------
Oil production is assumed to decline at an exponential rate. The rai^rof
decline varies by region (see Appendix G for more details). As oil production
declines, water production increases to maintain a constant volume. (Figure
H-l illustrates the oil and water production from a well with an initial
production rate of 100 bbl/day for two years and a 15 percent exponential
decline every year thereafter.)
Initial watercut data are available from Alaska for platforms in coastal
waters and gravel islands in offshore waters (Table H-l). Initial watercut
values range from 0.1 percent to 4.3 percent with a median value of 0.9
percent. We round this value upwards to 1 percent for Alaska and all other
regions.
H.1.2 Projects with Gas-Only Production
There is generally little water produced with gas-only operations. Under
these circumstances we estimate water production with a water:gas ratio.
Water production for gas wells is assumed to be a function of gas production
times a water:gas ratio. A constant water:gas ratio was used in the
impact analysis of the disposal of onshore production wastes under
8002(m) of RCRA (ERG 1987).
An Appalachian basin survey is the only survey of which we are aware that
investigates water production from gas wells (Flannery and Lannan 1987). The
survey appears well designed and covers approximately 10 percent of existing
Appalachian Basin wells, including 12,274 gas wells. Approximately 39 percent
of the gas wells produce no water at all, even with gas production rates
exceeding 60 Mcf/day. An additional 51 percent produce less than 10 barrels
of water per month. Less than 1 percent produce in excess of 100 barrels of
water a month. Averaging the survey data results in an estimated water:gas
ratio of 17.2 bbl per MMcf.
For comparison, the water:gas ratio for offshore California gas wells can
be calculated from the annual report of the oil and gas supervisor. Table H-2
shows the data for 1985, 1986, and 1987 (California 1986, California 1987, and
California 1988). The ratio for the wells in state waters increases four-fold
from 1985 to 1986. The 1986 water:gas ratio for gas wells in State waters is
16.2 bbl per MMcf, which is similar to the ratio from the Appalachian basin.
The water:gas ratio for gas wells in State waters climbs another fourfold from
H-2
-------
BARRELS
120
100
Figure H-l
Water : Oil Relationship
Exponential Oil Decline
4 6
iO 12 14 It 18 20 22 24 26 28 30
YEAR
H-3
-------
% ak h2o.uk1
TABLE H-1
INITIAL UATERCUT - ALASKA
33
Year
Region Field Platform Installed
Cook Granite Point Bruce
Inlet* Granite Point
Trading Bay Spark
TSA
Monopod
McArthur River King Salmon
Grayling
Dolly Vardin
Steel head
Middle School Ground Baker
A
C
Dillon
1966
1966
1966
1966
1966
1967
1967
1967
1987
1965
1964
1964
1965
Initial
Production Data
Number
Year Of Wells
1967
1967
1967
1967
1967
1968
1968
1968
1966
1966
1968
1968
11
5
12
8
13
12
5
11
12
10
Oil (bbl) Water (bbl)
4,569,773
2,479,506
**
**
726,966
6,239,122
9,523,640
6,019,548
686,140
2,249,359
4,603,781
2,321,014
50,026
1,457
808
203,302
49,338
19,536
5,623
41,487
39,780
100,650
Initial
(atercut
(%)
1.1X
0.1X
0.1X
3.3%
0.5X
0.3X
0.8X
1.8X
0.9X
4.3X
Beaufort Endicott
Island
1987
1987
29 8,795,758
171,363
1.9X
Notes: * Platforms in Cook Inlet are in the coastal subcategory.
** Only gas production listed, no associated water production.
Phillip's A platform, installed in 1968 in North Cook Inlet, is a gas-only platform.
No water production is listed for 1969.
Source: Individual well production reports provided by Elaine Johnson, Alaska Oil and Gas Commission,
Anchorage, AK, February 1988.
-------
h20_gas.wk1
TABLE H-2
OFFSHORE WATER:GAS RATIOS
CALIFORNIA
Year
1985
1986
1987
Region
State
Federal
Combined
State
Federal
Combined
State
Federal
Combined
Number
of Wells
6
15
21
6
15
21
4
18
22
Gross Gas
Production
(Mcf)
6,126,304
31,227,299
37,353,603
5,341,798
27,279,321
32,621,119
2,067,900
23,424,998
25,492,898
Water
Production
(bbl)
25,016
177,724
202,740
86,542
136,396
222,938
138,277
150,075
288,352
Water:0il
Ratio
-------
1986 to 1987 when it is 67 bbl per MMcf. Note also that by 1987, two of the
six gas wells had stopped producing. For gas wells in Federal waters for 1985
through 1987 and for gas wells in State waters for 1985, the water:gas ratio
ranges from 4.1 to 6.4 bbl per MMcf.
The North Cook Inlet field has the sole gas-only platform in Alaska.
Although the field is in coastal waters, we use the data as indicative of the
potential water production from gas-only operations in offshore southern
Alaska. For the North Cook Inlet field, gas production is approximately 130
MMcf/day while water production is generally about 10 bbl/day with
fluctuations as high as 100 bbl/day (see Figure H-2). This results in a
water:gas ratio of 0.08 bbl per MMcf with fluctuations as high as 0.77 bbl per
MMcf. In 1984, the North Cook Inlet field produced 46,981 MMcf of gas and
5,058 bbl of water for a water:gas ratio of 0.11 bbl per MMcf (Alaska 1984).
The monthly summaries of production for the Federal Gulf of Mexico list
oil, condensate, gas, casinghead gas, and water. That is, no distinction is
made between produced water from gas operations and produced water from oil
and oil-with-gas operations. Discussions with MMS personnel resulted in the
observation that, in general, little water is produced with gas-only
operations, although there are exceptions (Lowenhaupt 1989).
From the California data in Table H-2 and the Alaska data in Figure H-2,
we see that water production from gas operations can be extremely variable.
The highest water:gas ratio seen in the offshore and onshore data is about 67
bbl of water per MMcf produced. But this high value appears in only a few
wells that appear to be close to the end of their economic lifetime. The
average value seen in the onshore Appalachian data - 17 bbl/MMcf - exceeds the
water:gas ratios seen for the Alaska data, offshore Federal California gas
wells, and offshore State California gas wells for two of the three years of
data. The 17 bbl/MMcf is the water:gas ratio used in this analysis.
H.2 PEAK WATER PRODUCTION
H.2.1 Projects with Oil Production
Peak water production is the amount of water produced in the last year of
the economic lifetime of the well. Table H-3 shows the sample calculations
for the Gulf 24 model with 18 productive wells. Peak oil production occurs in
H-6
-------
3J
Figure H-2. Water and Gas Production from North Cook Inlet Field, Alaska
Source: Alaska 1984.
-------
h20 mex.wkl
15-Jan-90
TABLE H-3
WATER PRODUCTION ESTIMATES
GULF 24 MODEL
GULF OF MEXICO
Oil Production (bbl/d)
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Year 1
6000
6000
5100
4335
3685
3132
2662
2263
1923
1635
1390
1181
1004
853
725
617
524
446
379
322
274
233
198
168
143
121
103
88
75
63
Year 2 Year 3 Year 4 Year 5
3000
3000
2550
2168
1842
1566
1331
1131
962
817
695
591
502
427
363
308
262
223
189
161
137
116
99
84
71
61
52
44
37
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
6000
9000
8100
6885
5852
4974
4228
3594
3055
2597
2207
1876
1595
1355
1152
979
832
708
601
511
435
369
314
267
227
193
164
139
118
101
Water
- eduction
(bbl/d)
60
90
990
2205
3238
4116
4862
5496
6035
6493
6883
7214
7495
7735
7938
8111
8258
8382
8489
8579
8655
8721
8776
8823
8863
8897
8926
8951
8972
8989
Average
Cumulative Annual
Water Water
Production Production
(bbl/d) (kbbl/yr)
1.
3,
6.
10,
15,
21,
27,
33,
40,
47,
55.
62,
70,
78,
87,
95,
104,
112.
121,
130,
138,
147,
156,
165,
174,
183,
192,
201,
60
150
140
345
583
698
560
056
091
584
467
681
177
911
849
960
217
600
088
667
322
043
819
642
505
403
329
279
251
240
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
22
27
139
305
481
651
811
961
,099
,226
,343
,450
.549
,640
,724
,801
,873
,939
,000
,056
,109
,158
.203
,245
,285
,322
,357
,389
,420
,448
Notes:
500 bbl/day initial production per well
15X decline rate
1% initial watercut
18 producing wells.
H-8
-------
the second year of operation at a rate of 9,000 bbl/day. With an initial
watercut of 1 percent, total fluid production is 9,090 bbl/day. Water
production is the difference between oil production and total fluid
production. For example, in year 19, water production is 8,489 bbl/day
(i.e., 9,090 bbl/day total fluid production minus 601 bbl/day oil production).
Cumulative water production is 104,088 bbl/day in Year 19.
Peak water production, then, depends on the economic lifetime of the
project. The same project will have different peak water production rates for
BAT and NSPS evaluations because different oil prices are assumed in the BAT
and NSPS analyses. Project lifetimes and peak water production rates are
summarized in Table H-4.
H.2.2 Projects with Gas-Only Production
Peak water production for gas-only projects occurs at the time of peak gas
production. There will be no difference in peak water production for gas-only
projects depending upon whether the scenario studied is BAT or NSPS. Peak
water production rates for all projects are given in Table H-4.
H3 AVERAGE WATER PRODUCTION
H3.1 Projects with Oil Production
Average water production for oil-only and oil-with-gas projects is the
cumulative water production through the last economic year of production
divided by the economic lifetime of the well. For example, for a Gulf 24
model with an economic lifetime of 20 years (see Table H-3), average annual
water production is calculated as:
Cumulative water production (bbl/dav) * 365 days/vr / Average
/ 1000 = Annual
Economic lifetime of model project / Water
/ Production
(kbbl/yr)
or,
112.667 * 365
1000 - 2,056 kbbl/yr
20
H-9
-------
peak_h20.wk1
15-Jan-90
TABLE H-4
REVISED PEAK WATER PRODUCTION RATES - EXISTING AND PROJECTED STRUCTURES
Project
Type Region Model
Economic Lifetime
of Project (Years)
Existing Projected
Atlantic 24
21
Peak Water Production
Rate per Project
(bbl/day)
Existing
Projected
OIL
ONLY
Gulf 1a
1b
4
6
12
24
40
58
Pacific 16
40
70
13
17
18
18
16
18
20
22
8
9
11
15
19
20
20
18
20
22
24
9
10
12
421
461
1.871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
445
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
19,224
Cook Inlet*
Beaufort
Platform
Beaufort Island
Navarin
Norton
OIL
AND
GAS
Platform
Platform
Gulf
Pacific
Atlantic
Cook Inlet*
GAS
ONLY
Gulf
Pacific
Atlantic
Cook Inlet*
24
48
48
48
34
1a
1b
4
6
12
24
40
58
16
40
70
24
24
1a
1b
4
6
12
24
16
24
12
**
**
**
**
**
14
18
19
19
17
19
21
23
8
9
11
**
**
14
18
19
20
17
19
11
**
**
30
28
30
30
27
16
20
21
21
19
21
23
25
9
10
12
21
30
16
20
21
21
19
21
13
25
29
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
**
**
68
68
272
408
680
1,224
1,190
**
37,449
73,405
74,503
74,503
51,169
454
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
19,224
37,449
68
68
272
408
680
1,224
1,190
2,550
2,550
Notes: * Existing platforms in Cook Inlet are in the coastal subcategory.
** Produced water from gravel islands in the Beaufort Sea
(i.e., the Endicott field) is reinjected per State requirement.
There are no platforms currently producing in the Beaufort, Navarin,
Norton or Atlantic areas. Economic impacts are evaluated for these
projects and projects in the non-coastal region near Cook Inlet that
may occur at some point in the future.
Source: ERG estimates.
H-10
-------
Average water production by structure is listed in Table H-5.
This methodology is used for oil-only and oil-with-gas projects. Projects
with associated gas production are not assumed to produce more water than
projects that produce only oil. If gas production is coming from separate gas
wells on a platform, this approach may overestimate water production since gas
wells generally produce less water than oil wells. This may occur in existing
structures but there is no information by which to adjust existing structure
counts for this phenomenon. Projected structures are assumed to have
associated gas production for oil-with-gas model projects and are unaffected
by this assumption.
H3.2 Projects with Gas-Only Production
For average water flow rates, regional average water:gas ratios are used
where available. For California the ratio is 7 bbl water per MMcf (see Table
H-2 for wells in Federal waters). The 7:1 ratio is also used for Gulf of
Mexico and Atlantic projects. For Alaska, a 1:1 ratio is used based on the
data from the North Cook Inlet field (see Section H.I.2; this value is rounded
upwards to a 1:1 ratio). As for projects with oil production, average annual
water production is calculated as the cumulative water production divided by
the number of years of production. Because a water:gas ratio is used to
calculate water production from gas projects, and gas production declines over
the life of the well, average water production for longer-lived gas projects
will be lower than for shorter-lived gas projects. Average water production
by structure is listed in Table H-5.
H.4 TOTAL ANNUAL WATER PRODUCTION
Total amount of water produced is estimated in two steps. First, in order
to obtain water production by model project, the number of each model project
is multiplied by the average annual water production associated with each
project. These project totals are then summed over all projects to obtain the
grand total of water produced during the time period. Projects will be
installed and come into production throughout the time period, but the amount
of water produced by each project will be the average annual water flow.
H-ll
-------
avg_h20.uk1
15-Jan-90
TABLE H-5
REVISED AVERAGE ANNUAL WATER PRODUCTION RATES - EXISTING AND PROJECTED STRUCTURES
Economic Lifetime
of Project (Years)
Average Annual
Water Production
Rate per Project
(kbbl/yr)
proje
Type
OIL
ONLY
CI
Region
Gulf
Pacific
Atlantic
Cook Inlet*
Beaufort Platform
Beaufort Island
Navarin Platform
Norton Platform
OIL
AND
GAS
GAS
ONLY
Gulf
Pacific
Atlantic
Cook Inlet*
Gulf
Pacific
Atlantic
Cook Inlet*
Model
1a
1b
4
6
12
24
40
58
16
40
70
24
24
48
48
48
34
la
1b
4
6
12
24
40
58
16
40
70
24
24
1a
1b
4
6
12
24
16
24
12
Existing
13
17
18
18
16
18
20
22
8
9
11
**
**
**
*#
**
**
14
18
19
19
17
19
21
23
8
9
11
*«
**
14
18
19
20
17
19
11
**
**
Projected
15
19
20
20
18
20
22
24
9
10
12
21
30
28
30
30
27
16
20
21
21
19
21
23
25
9
10
12
21
30
16
20
21
21
19
21
13
25
29
Existing
90
107
443
665
994
1,939
3.505
5,486
2,358
5,213
9,324
**
**
**
**
**
**
95
111
456
685
1,034
2,000
3,604
5,631
2,358
5,213
9.324
**
**
6
5
20
28
54
89
112
**
**
Projected
99
114
469
703
1,071
2,056
3,696
5,767
2,579
5,720
10,128
4,664
9,247
17,100
17,766
17.766
12,054
104
117
480
720
1,105
2.109
3,782
5,893
2,579
5,720
10,128
4,664
9,247
6
5
18
27
49
81
98
204
40
Notes: * Existing platforms in Cook Inlet are in the coastal subcategory.
** Produced water from gravel islands in the Beaufort Sea
(i.e., the Endicott field) is reinjected per State requirement.
There are no platforms currently producing in the Beaufort, Navarin,
Norton or Atlantic areas. Economic impacts are evaluated for these
projects and projects in the non-coastal region near Cook Inlet that
may occur at some point in the future.
Source: ERG estimates.
H-12
-------
H.4.1 Existing Structures (BAT)
Gulf of Mexico
The number of structures in production in the Gulf of Mexico is taken from
the MMS Platform Inspection System, Complex/Structure data base as of March
1988. Table H-6 describes the data cleaning process used to identify
structures for which it is appropriate to calculate water production. Only
those structures with
known number of drilled wellslots
known type of production
known to be in production as of March 1988
are considered in this count of structures. This number will differ from that
presented in Section Two because all structures are included in that count.
These structures were then divided into categories to correspond to the
model projects. Categorization is based on the number of drilled wellslots,
and the breaks between the categories were chosen to create the best
correspondence between the actual and projected number of wells. A summary of
existing structures in the Gulf of Mexico is presented in Table H-7.
The estimated annual water production for projects in the Gulf of Mexico
is 885 million bbl/yr (see Table H-8). For comparison, the MMS estimate of
produced water generated in the Federal Gulf of Mexico in 1987 is
approximately 500 million barrels (Miller 1989; reproduced as Attachment H-l).
MMS 1989 indicates that in 1986, approximately 70.2 million barrels of water
were discharged in offshore Louisiana state waters while another 5.1 million
barrels were discharged in offshore Texas state waters. We assume, for this
report, that the volumes of water discharged are equal to the volumes of water
generated. We also assume that 1987 water production did not differ
drastically from 1986 water production. This results in approximately 573
million barrels/yr of produced water generated in the Gulf of Mexico.
The BAT O&M costs, then, are capable of handling an additional 54 percent
over 1987 water production rates. The capital (equipment) costs are
determined by peak, not average, flow rates so the infrastructure is capable
of handling even larger volumes of produced water. For these reasons, we
decided against attempting to incorporate structures in State waters in the
H-l 3
-------
mms desc.uk!
TABLE H-6
DESCRIPTION OF MMS DATA BASE STRUCTURE COUNTS
MARCH 1988
Remaining
Category Count Count
All structures 3562 3562
Structures classified as 465 3097
production structures,
i.e., with zero well slots
available and with
production equipment
Structures with missing , 33 3064
information on number
of wellslots drilled
Structures with zero 88 2976
drilled wellslots
Structures known not 721 2255
to be in production
Structures with missing 16 2239
information on product
type (oil or gas or both)
Structures whose drilled 6 2233
wellslots are used solely for
injection, disposal, or
as a water source
Source: Minerals Management Service Platform
Inspection System, Complex/Structure
see printouts, kre_bat.out,
kre_bat2.out and kre_bat4.out.
15-Jan-90
H-14
-------
TABLE H-7
EXISTING STRUCTURES BY REGION
07-Feb-91
NUMBER OF STRUCTURES
Structure Oil Only
Type <=
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Gulf Totals
Pacific 16
Pacific 40
Pacific 70
Pacific Totals
Atlantic
Alaska
Totals
4 mi les
26
1
23
0
0
0
0
0
50
0
0
0
0
Oil Only Oil and Gas Oil and Gas Gas Only Gas Only Total
> 4 mi les <=
38
9
18
18
22
5
1
0
111
0
0
0
0
4 miles > 4 miles <= 4 mi
27
13
10
2
3
8
0
0
63
7
0
4
11
193
82
101
124
215
188
2
0
905
1
6
8
15
les > 4 miles <= 4 mi les >
53
22
8
1
0
0
0
0
84 1
0
0
0
0
337
228
156
156
104
39
0
0
,020
1
0
0
1
106
36
41
3
3
8
0
0
197
7
0
4
11
Total
4 miles
568
319
275
298
341
232
3
0
2,036
2
6
8
16
Total
674
355
316
301
344
240
3
0
2,233
9
6
12
27
No existing facilities
50
No facilities
111
that do not
74
already re- inject
920
produced
84 1
water
.021
208
2,052
2,260
Note: Structures in the Gulf of Mexico have been classified according to the number of producing wells.
Structures in the Pacific have been classified according to the number of wells lots.
Source: MMS, 1988; CCC, 1988; SAS printout kre_bat6.out; SAS runs dated July 1990.
H-15
-------
structr.wkl
TABLE H-8
ESTIMATED AVERAGE ANNUAL PRODUCED WATER
IN THE GULF
OF MEXICO
Average Annual
Water Production
Structure
Type
Oil
Gulf la
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Oil With Gas
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Gas
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Per Project
GENERATED BY PROJECTS
Water
Production
Per Project
Number (kbbl/yr) (kbbl/yr)
64
10
41
18
22
5
1
0
220
95
111
126
218
196
2
0
390
250
164
157
104
39
90
107
443
665
994
1.939
3,505
5,486
95
111
456
685
1,034
2,000
3,604
5,631
6
5
20
28
54
89
5,760
1,070
18,163
11,970
21,868
9,695
3,505
0
20,900
10,545
50,616
86,310
225,412
392,000
7,208
0
2,340
1,250
3,280
4,396
5,616
3,471
Total 2.233 885.375
Source: ERG estimates.
H-16
-------
ATTACHMENT H-l
WATER PRODUCTION IN THE FEDERAL GULF OF MEXICO - 1987 DATA
United States Department of the Interior
IV REPLY
SF.KER 10:
PAD/RC3
Mail Stop 657
MINERALS MANAGEMENT SERVICE
ROYALTY MANAGEMENT PROGRAM
PRODUCTION ACCOUNTING DIVISION
P.O. BOX 17110
DENVER. COLORADO 80217
'JAM 2 7 [399
Ms. Maureen Kaplan
Environmental Protection Agency
6 Whittemore Street
Arlington, Massachusetts 02714
Dear Ms. Kaplan:
Subject: Volumes of Water Disposed of in Gulf of Mexico in 1987
The information below is provided in accordance with a telephone conversation
between you and John Marshall of this office on January 23, 1989.
The following volume/categories of water were disposed of in the Gulf of
Mexico in 1987:
a. Injected on a lease
b. Transferred off lease
c. Surface pit
d. Overboard
e. Meter differential
f. Well test
g. Gathering system
TOTAL
19,357,689
74,557,893
25,368,097
378,978,944
79,870
146,548
-12.325
498,476,716*
* or 498.5 million barrels of water disposed of in Gulf in 1987
If you have any questions, please do not hesitate to call Mr. Marshall at
303-231-3635 or our toll-free number 800-525-7922.
Sincerely,
'Michael A.^Miller, Chief
Reporter Contact Branch
H-17
-------
BAT structure counts. Another reason was the difficulty in obtaining a
supportable count of such structures. State records are generally maintained
on a well basis, not a structure basis. In addition, these well counts
include onshore wells that tap offshore fields, coastal wells, and offshore
wells with no means of discerning among these categories. Maps, such as those
produced by Houston Helicopter, do not specify the number of wells on multi-
well platforms nor do they indicate which structures are in production. This
is an area that will be investigated further after proposal.
California
The categorization of structures off the California coast is done on the
basis of the number of available wellslots. The number of drilled wells is
available only on a field basis and so is not appropriate to use here. Table
H-7 lists the number of structures by category while Table H-9 presents the
estimated annual water production.
The 1987 water volumes for the Federal DCS and the Huntington, South
Elwood, Summerland, and Carpinteria fields were added for an actual count of
107 million barrels. The estimated water production is 162 million barrels.
The estimated volume of water for the Pitas Point gas field is 112 thousand
barrels compared to an actual count of 140.5 thousand barrels (California
1988).
Alaska and the Atlantic
Production in Alaska is currently in Cook Inlet and in the Endicott Field
(Beaufort Sea region off the North Slope). The platforms currently existing
in Cook Inlet are considered to be coastal and so do not fall under the
jurisdiction of this regulation. The Endicott field is already injecting its
produced water due to State requirements. No BAT costs, therefore, are
incurred by existing Alaska projects.
There is no production in the Atlantic at this time.
H-18
-------
structr.wkl
TABLE H-9
ESTIMATED AVERAGE ANNUAL PRODUCED WATER GENERATED BY PACIFIC PROJECTS
Structure
Type
Oil
Pacific 16
Pacific 40
Pacific 70
Number
0
0
0
Average Annual
Water Production
Per Project
(kbbl/yr)
2,358
5,213
9,324
Water
Production
Per Project
(kbbl/yr)
0
0
0
Oil with Gas
Pacific 16
Pacific 40
Pacific 70
Gas
Pacific 16
8
6
12
2,358
5,213
9,324
112
18,864
31,278
111,888
112
Total
27
162,142
Source: ERG estimates.
H-19
-------
H.4.2 Projected Structures (NSPS)
Section Four presents the methodology used to project the number of
structures for the 1986-2000 time period. Table H-10 summarizes the number of
structures under the $21/bbl oil price scenario with restricted development.
Table H-ll lists the annual average volume of water produced during this time
period. The average annual volume of water produced is approximately 511
million barrels.
H.5 REFERENCES
Alaska 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation
Commission, n.d.
California 1986. 71st Annual Report of the State Oil and Gas Supervisor:
1985. California Department of Conservation. Division of Oil and Gas,
Publication No. PR06, 1986.
California 1987. 72nd Annual Report of the State Oil and Gas Supervisor:
1986. California Department of Conservation. Division of Oil and Gas,
Publication No. PR06, 1987.
California 1988. 73rd Annual Report of the State Oil and Gas Supervisor:
1987. California Department of Conservation. Division of Oil and Gas,
Publication No. PR06, 1988.
CCC 1988. Oil and Gas Activities Affecting California's Coastal Zone.
California Coastal Commission, 2nd edition, December 1988.
ERG 1987. Report to Congress, ManaEement of Wastes from the Exploration.
Development, and Production of Crude Oil. Natural Gas, and Geothermal
Energy. Volume 1: Oil and Gas, EPA/530-SW-88-003, December 1987.
Flannery, D.M. and R.E. Lannan 1987. An Analysis of the Economic Impact of
New Hazardous Waste Regulations on the Appalachian Basin Oil and Gas
Industry. Robinson & McElwee, Charleston, WV, February 1987.
Lowenhaupt 1989. Personal communication between Maureen F. Kaplan, Eastern
Research Group, Inc., and Jake Lowenhaupt, MMS, Gulf of Mexico Office, 9
January 1989.
Miller 1989. Letter to Maureen F. Kaplan, Eastern Research Group, Inc. from
Michael A. Miller, Chief, Reporter Contact Branch, Minerals Management
Service, dated 27 January 1989.
MMS 1989. D. F. Boesch and N. N. Rabalais, eds. Produced Waters in Sensitive
Coastal Habitats: An Analysis of Impacts. Central Gulf of Mexico. MMS 89-
0031, June 1989.
H-20
-------
TABLE H-10
NSPS STRUCTURE ALLOCATIONS
RESTRICTED ACTIVITY
$21/bbl SCENARIO
All Platforms
Region
Gulf
Model
Gulf
Gulf
Gulf
Gulf
Gulf
Gulf
1b
4
6
12
24
40
Total
76
235
123
180
114
27
Oil
12
89
34
84
62
27
Gas
64
146
89
96
52
0
Within 4-Miles
Total
23
60
43
14
0
0
Oil
0
27
15
14
0
0
Gas
23
33
28
0
0
0
Beyond 4 -Mi tes
Total
53
175
80
166
114
27
Oil
12
62
19
70
62
27
Gas
41
113
61
96
52
0
Pac i f i c
Atlantic
Alaska
Pacific 40 330
Pacific 70 440
Atlantic 24
Cook inlet 12 101
Cook Inlet 24 110
B. Gravel Island* 220
Total Platforms All Regions 766 318 448
0
0
2
142
0
0
2
58
0
0
0
84
1
1
0
624
0
1
0
260
1
0
0
364
* Oil only; all other projects are assumed to produce oil and casinghead gas.
H-21
-------
29-NOV-90
TABLE H-11
ESTIMATED AVERAGE ANNUAL NSPS WATER PRODUCTION
S21/BBL RESTRICTED DEVELOPMENT SCENARIO
Average Annual
Project Water Production
Type Model (kbbl/yr)
OIL
AND
GAS
OIL
ONLY
GAS
ONLY
NUMBER
TOTAL
Gulf
Pacific
Atlantic
C. Inlet
Platform
Island
Gulf
Pacific
Atlantic
C. Inlet
OF AFFECTED
1b
4
6
12
24
40
40
70
24
24
48
48
1b
4
6
12
24
16
24
12
STRUCTURES
117
480
720
1,105
2,109
3,782
5,720
10,128
4,664
9,247
17,100
17,766
5
18
27
49
81
98
204
40
Number of
Structures
12
89
34
84
62
27
3
4
0
1
0
2
64
146
89
96
52
0
0
1
766
WATER PRODUCED (kbbl/yr)
Annual Volume of
Water Produced
(kbbl/yr)
1,404
42,720
24,480
92,820
130,758
102,114
17,160
40,512
0
9,247
0
35.532
320
2,628
2,403
4,704
4,212
0
0
40
511,054
Source: ERG estimates.
H-22
-------
APPENDIX I
BASE CASE FINANCIAL ASSUMPTIONS AND RATES
The economic and financial accounting assumptions used in the economic
model are based upon common oil industry financing methods and procedures.
Changes in tax computations due to the Tax Reform Act of 1986' (Public Law 99-
514) are incorporated in the ERG model.
1.1 INCREMENTAL IMPACT OF MODEL PROJECT ON CORPORATE INCOME
TAX RATE
It is assumed that the model projects are incremental to the other
activities of the company, and therefore, the net taxable income is marginally
taxed at the U.S. corporate rate of 34 percent. This assumption implies that
the company has at least $100,000 of other net income without this project.
In addition, it is assumed that any net losses in the initial years of a
project can be applied to the net income of other projects, so that an
effective tax shield of 34 percent of the loss is realized. Therefore, the
yearly net cash outflow is 100 percent minus 34 percent, or 66 percent of the
year's loss. This is appropriate because of the customary size and level of
activities of firms undertaking offshore oil exploration and production. The
basis for federal income is gross revenues minus royalty payments, severance
taxes, depletion and depreciation allowances, and operating costs.
1.2 SEVERANCE TAXES
Since the Outer Continental Shelf regions are under the jurisdiction of
the Federal government, it is assumed that state severance taxes are not
applicable to the revenues generated by OCS production. Consequently,
severance taxes are not included in the analysis of model projects located in
Federal waters. The projects expected to be located in state waters and
therefore subject to severance taxes for tax purposes are the Gulf 1-well, 4-
well, 6-well, 12-well, and 24-well platforms; Cook Inlet projects, the
Beaufort Sea 48 well gravel island; and the California 40 wellslot platform.
1-1
-------
Texas state severance taxes are 4.6 percent on oil and 7.45 percent on
gas. Louisiana imposes a 12.5 percent severance tax on oil and a $0.07 per
Mcf tax on gas. (Using the 1982 wellhead price, the Louisiana $0.07 tax is
equivalent to a 1.3 percent tax on gas.) Based on cumulative oil and gas
production data for Texas and Louisiana offshore leases through 1981, an
average severance tax of 6.19 percent was calculated and this value is used
for the Gulf projects in State waters.
California, at present, has no severance taxes.
The Alaska severance tax structure consists of nominal rates that are then
adjusted by a formula. The formula is referred to as the ELF, the Economic
Limit Factor.
Nominal tax rates on oil are 12.25 percent of gross revenues for the first
5 years of production and 15 percent thereafter. The ELF formula for oil is:
460 x WD
PEL
ELF -
/I
I
where:
PEL - monthly production at the economic limit
TP - total monthly production
WD - well days for the month (assumed to be 30).
The monthly production at the economic limit value is confidential between the
oil company and the Alaska Department of Revenues. Three hundred bbl/day/well
or 9,000 bbl/month/we11 is used for the economic limit (PEL) in this analysis
(Logsdon 1988).
As an example, suppose monthly production is 50,000 barrels. Then the ELF
is:
( 9.000^
460 x 30
9,000
ELF - U - 50.000/
- (0.82)1'533 - .74
If the ELF is greater than 0.7, then the tax rate is the nominal rate,
the ELF is less than 0.7, severance taxes are calculated as follows:
For the first five years of production:
Oil Severance Taxes - Gross revenues x 12.25 percent x ELF.
1-2
-------
After the first five years of production:
Oil Severance Taxes - Gross revenues x 15.00 percent x ELF.
The oil ELF is applied as long as it is positive.
The nominal severance tax rate on natural gas is 10 percent, which is
adjusted by the following ELF formula:
PEL
ELF - 1 - TP
where:
PEL - monthly production at the economic limit
TP - total monthly production.
Three thousand Mcf/day/well or 90,000 Mef/month/we11 is used for the economic
limit (Logsdon 1988). Gas severance taxes are calculated as follows:
Gas Severance Taxes - Gross revenues x 10.00 percent x ELF.
Unlike the oil severance ELF, the gas ELF is applied regardless of value, as
long as it is positive.
For offshore leases, the basis for the severance tax calculation would be
on the basis of (gross revenues - exempt revenues) where royalty payments to
state government are considered exempt revenues.
13 ROYALTY RATES
Operators of oil- and gas-producing properties are usually required to pay
royalties to the lessors or owners of the land based on the value of extracted
production. This includes the Federal government for OCS leases and state
governments for leases located in state waters. In many instances, the
royalty rate is a floating rate that varies from year to year, or a complex
calculation based on the amount or mix of production. For the model projects,
it is assumed that an average fixed rate of one sixth (17 percent) of total
gross revenues is the best approximation of royalty payments for a typical
1-3
-------
large project in Federal waters and 22 percent for a project on a state-owned
tract.
1.4 RENTAL PAYMENTS
Rental payments generally comprise a negligible cash outflow in the
overall set of costs for an oil and gas project. For this reason, they have
been excluded from the analysis.
1.5 DEPRECIATION
The Tax Reform Act of 1986 modifies the Accelerated Cost Recovery System
(ACRS) for property placed in service after 31 December 1986. Under the new
system, most oil and gas equipment will be classified as seven-year property.
The recovery method for this class is double declining balance (Snook and
Magnuson, 1986). The schedule used to write off capitalized costs in the
model is as follows:
Year 1 14.29% of costs
Year 2 24.49%
Year 3 17.49%
Year 4 12.49%
Year 5 8.93%
Year 6 8.92%
Year 7 8.93%
Year 8 4.46%
Year 1 in the above table is defined as the first year in which the equipment
is placed in service. According to relevant accounting principles, this is
the first year in which the equipment produces oil or gas.
The value of the deduction for depreciation is reduced by inflation. To
maintain the calculations on a constant dollar basis, the value of the
deduction is adjusted downwards in later years by the inflation rate. See
Section 1.8.
1-4
-------
1.6 BASIS FOR DEPRECIATION
The Tax Reform Act of 1986 repealed the Investment Tax Credit (Snook and
Magnuson, 1986; Coopers and Lybrand, 1986). This means that the initial basis
for depreciation is 100 percent of the total capitalized costs.
1.7 CAPITALIZED COSTS
It is assumed that the tax payer (oil company) elects to expense
intangible drilling costs incurred in the development of oil and gas wells.
Intangible drilling costs (IDCs) are estimated, on the average, to represent
60 percent of the cost of production wells and their infrastructure (Commerce,
1982; Commerce, 1983; API, 1986). The Tax Reform Act limits major integrated
producers to expensing 70 percent of IDCs with the remaining 30 percent
capitalized. (That is, a major may only expense 0.60 times 0.70, or 42
percent of its IDCs.) Independents are still allowed to expense 100 percent
of their IDCs. The remaining 40 percent of the total cost is capitalized and
treated as depreciable assets for tax purposes (Snook and Magnuson, 1986).
Dry holes are written off in the year in which the cost is incurred. For
independents, the proportion of the exploratory drilling cost that is
capitalized is therefore equal to 40 percent of the total drilling cost times
the discovery efficiency. For majors, the proportion is 58 percent of the
total drilling cost times the discovery efficiency. The remaining drilling
costs are expensed.
1.8 INFLATION RATE
The effective value of depreciation and cost-basis-depletion deductions is
reduced by inflation since the expenditures occur in year(s) prior to the
deduction. The model calculates an "adjusted depreciation" as follows:
Adjusted depreciation Depreciation in Year X
in Year X Year X
(1 + inflation rate)
An "adjusted cost-basis-depletion" is calculated in a similar manner.
The change in the "Fixed Weight Price Index" is used as a measure of
inflation for this analysis. Since 1982, the values are:
1-5
-------
1982 6.2
1983 4.1
1984 4.0
1985 3.7
1986 2.8
for an average of 4.2 percent (Economic Report, 1987). This value is used in
the analysis to deflate the depreciation and depletion.
1.9 ESCALATION OF GENERAL PROJECT COSTS IN REAL TERMS
It is assumed that costs will remain constant in real terms, i.e., the
rate of increase in material and labor costs is equal to the rate of
inflation.
1.10 OIL DEPLETION ALLOWANCE
The ERG model calculates depletion on a cost basis, which is appropriate
for major producers. Cost depletion allows the producer to recover the
leasehold cost over the producing lifetime of the well. The leasehold cost
consists of the bonus bid (see Appendix C), and certain geological,
geophysical and legal costs (see Appendix D).
Cost depletion is based on units of production and is represented by the
following formula:
B - U + S
where:
B - adjusted basis of leased property
S - units sold during the period
U - units remaining at the end of the period.
The initial basis of the property used in the ERG model consists of the
bonus bid and the geological and geophysical expenses. (That is, the legal
costs incurred in acquiring the lease are not explicitly included in the
model. It is assumed they form a minimal increment to the overall leasehold
cost.) The basis is then adjusted downward to account for the depletion taken
in each period. The portion of the adjusted basis taken as depletion in any
1-6
-------
given period is the units sold during the period, divided by the units sold
and the recoverable units remaining. For the purposes of the model, it is
assumed that all units produced in a period are sold in the same period.
Thus, the depletion for any given period is equal to the adjusted basis
multiplied by the ratio of units produced in the period to the sum of the
units produced and remaining. In this manner, the leasehold cost is amortized
over the productive life of the well.
The value of the cost-basis depletion is reduced in later years by
inflation. See Section 1.8 for the methodology used to correct for this in
the calculations. The value used in the annual cash flow is the inflation-
adjusted value. The unadjusted value is used to calculate the basis for
depletion in subsequent years.
1.11 SALVAGE
It is assumed that the after-tax cost to remove the infrastructure and to
retire the well at the end of its economic life is approximately equal to
their salvage values. Hence, there is no additional positive or negative cash
flow.
1.12 INVESTMENT TAX CREDIT
The Tax Reform Act of 1986 repealed the Investment Tax Credit (Snook and
Magnuson, 1986; Coopers and Lybrand, 1986).
1.13 WINDFALL PROFITS TAX
A phaseout of the Windfall Profits Tax of 1980 will begin no later than
January 1991, with a 33-month phaseout beginning as early as January 1988.
Under these conditions, the Windfall Profits Tax will apply, at most, to the
first few years of the projects. In addition, the industry is trying to have
the tax repealed in its entirety at an earlier date (OGJ, 1987) and the Senate
voted to repeal the tax in July 1987. For these reasons, the effects of the
Windfall Profits Tax have not been included in the analysis.
1-7
-------
1.14 DISCOUNT RATE
The discount rate used in this analysis represents the opportunity cost of
capital for investments in oil and gas production (Brigham, 1982) . The cost
of capital is the investor's expected rate of return for a particular
investment. That is, the cost of capital is the return that could be earned
elsewhere in the economy on projects of equivalent risk. The riskier the
investment, the higher the cost of capital.
The opportunity cost of capital is modeled as:
Real cost
of - 1 + nominal cost - 1
Capital 1 + inflation rate
where:
nominal cost - [equity cost * equity share] + [debt share * debt cost]
The equity cost is the sum of the risk-free return and the risk premium.
For the risk-free return, ERG uses the average return on long-term U.S.
Treasury bonds. The risk premium is the product of the average industry risk
(i.e., the industry beta) and the market risk for long-term investment.
The debt and equity shares are the portions of capital financed by debt
and equity, respectively. These are estimated by the average share of debt o
equity in the firm's value.
The debt cost is the after-tax cost of debt, i.e., the product of the
current cost of debt and (1 minus the corporate tax rate). For the current
cost of debt, the interest rates for Moody's Baa corporate bonds are used.
The next point to consider is whether to use long-term or short-term
estimates for each of these parameters. The productive life of the project
can be several decades in the ERG model. On this basis, long-term average
values are used in estimating the cost of capital.
Table 1-1 compiles twenty-year averages for risk-free returns, current
cost of debt, and inflation rates. (Most projects in this study are no longer
profitable after twenty years of production.) Table 1-2 gives the average
long-term debt-to-capital ratio for 19 major integrated companies. This ratio
varies around 25 percent for the time period investigated. On this basis, we
1-8
-------
TABLE 1-1
TWENTY-YEAR AVERAGES FOR RISK-FREE, CORPORATE BORROWING,
AND INFLATION RATES
YEAR
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
Average
RISK-
FREE
RATE
5.07
5.65
6.67
7.35
6.16
6.21
6.84
7.56
7.99
7.61
7.42
8.41
9.44
11.46
13.91
13.00
11.10
12.44
10.62
7.68
8.63
CORPORATE
BORROWING
RATE
6.23
6.94
7.81
9.11
8.56
8.16
8.24
9.50
10.61
9.75
8.97
9.49
10.69
13.67
16.04
16.11
13.55
14.19
12.72
10.39
10.54
INFLATION
RATE
2.6
3.7
4.4
3.6
3.5
2.9
5.5
7.8
8.0
5.3
5.1
6.2
8.5
9.3
9.3
6.2
4.1
4.0
3.7
2.8
5.3
Source: Economic Report, 1987, Table B-68, 10-year U.S. Treasury securities,
and Moody's Baa corporate bonds, Table B-4, inflation rate.
1-9
-------
TABLE 1-2
DEBT/CAPITAL RATIO (%)
MAJOR INTEGRATED OIL COMPANIES IN 19-COMPANY ERG GROUP
(1977-1985)
1977
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-McGee
Mobil Oil
Murphy Oil
Occidental Petroleum
Phillips Petroleum
Shell Oil (Royal Dutch
36.
26.
34.
38.
14.
5.
13.
20.
25.
35.
26.
21.
20.
7
4
2
1
4
8
5
9
2
5
8
0
6
1978
36
45
34
38
13
4
14
16
25
40
39
16
18
.0
.8
.6
.4
.3
.7
.1
.6
.6
.5
.4
.3
.4
1979
30.0
40.4
29.4
38.1
13.3
4.0
13.0
20.4
21.3
32.3
39.0
13.6
30.6
1980
29.5
33.5
27.1
36.0
12.5
10.8
10.7
24.1
19.0
19.1
25.6
12.4
33.0
1981
35.2
28.1
28.9
34.0
12.0
9.8
13.0
33.1
17.3
21.1
20.1
15.0
31.3
1982
38.9
26.0
28.7
34.3
10.6
16.6
14.6
29.7
21.1
16.9
43.5
22.7
27.8
1983 .
40.3
31.4
26.2
37.0
10.5
27.1
24.4
15.1
34.0
23.3
19.1
1984
40.1
39.1
26.9
28.1
11.6
23.5
40.9
14.3
43.3
26.0
17.3
1985
40.6
40.8
43.9
40.7
10.4
23.4
35.8
13.7
47.6
64.3
14.6
Petroleum)
Standard Oil of California 16.2 19.7
(Chevron)
17.2 13.0 12.4 11.3 10.6 43.4 28.9
Standard Oil of Indiana
(Amoco)
Standard Oil of Ohio
Sun Company
Texaco
Union Oil Company
Unweighted
Company Average*
25.2 23.5 21.1 18.8 21.4 22.0 20.1 17.3 16.9
71.9 65.4
18.9 19.4
19.1 24.8
26.8 28.6
50.3 39.8 36.1
16.8 34.5 28.6
21.8 18.0 15.1
26.0 21.9 18.3
33.8 29.2 26.4 25.4
24.7 24.8 25.3 20.7
12.8 14.1 41.0 31.6
18.6 17.6 15.3 64.1
26.2 27.6 25.2 23.1 22.7 23.9 23.8 28.2 33.1
Source: S&P 1982; S&P 1986.
"Simple average calculated from the ratios for all companies in the sample.
1-10
-------
use .25 percent as the debt share and 75 percent as the equity share in the
cost of capital calculations.
The cost of capital is calculated in Table 1-3. Sources for the remaining
parameter values are cited in the table. The estimated cost of capital is
7.55 percent. This value is rounded upwards to 8 percent for use in the
analysis.
1.15 REFERENCES
API 1986. 1984 Survey on Oil and Gas Expenditures. American Petroleum
Institute, Washington, DC, October 1986.
Brealey, Richard A. and A. Myers. 1984. Principles of Corporate Finance.
McGraw-Hill, New York, NY, 2nd Edition, 1984.
Brigham, E.F. 1982. Financial Management: Theory and Practice. The Dryden
Press, New York, NY, 3rd edition, 1982.
Commerce 1982. Annual Survey of Oil and Gas. 1980. U. S. Department of
Commerce, Bureau of the Census, Current Industrial Reports, MA-13k(80)-l,
March 1982.
Commerce 1983. Annual Survey of Oil and Gas. 1981. U. S. Department of
Commerce, Bureau of the Census, Current Industrial Reports, MA-13k(81)-1,
March 1983.
Coopers and Lybrand 1986. Tax Reform Act of 1986: Analysis. New York NY,
1986.
Economic Report 1987. Economic Report of the President 1987. Council of
Economic Advisors, January 1987, Table B-4.
Kavanaugh, M. 1987. "Cost of Capital in the Petroleum Industry: Memorandum
to Mahesh Poder, OPPE, Environmental Protection Agency, from M. Kavanaugh,
January 15, 1987.
Logsdon, C. 1988. Personal communication between Maureen F. Kaplan,
Eastern Research Group, Inc., and Charles Logsdon, Alaska Department of
Revenue, March 15, 1988.
OGJ 1987. "U.S. Government Must Act to Avert Energy Disaster," editorial, Oil
and Gas Journal. March 9, 1987, p. 11.
Snook, S.B. and Magnuson, W.J. Jr. 1986. "The Tax Reform Act's Hidden Impact
on Oil and Gas," The Tax Adviser. December 1986, pp. 777-83.
S&P 1982. Standard and Poor's Industry Survey, "Oil, Basic Analysis,"
Nov. 1982.
S&P 1986. Standard and Poor's Industry Survey, "Oil, Basic Analysis,"
Nov. 1986.
1-11
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TABLE 1-3
COST OF CAPITAL CALCULATIONS
PARAMETER
Risk- free return
Industry beta
Market risk
Risk premium
Cost of debt
Debt cost
Debt share
Equity share
Inflation rate
Nominal cost
Real cost
VALUE
8.63%
0.84%
8.00%
6.72%
10.54%
6.96%
25.00%
75.00%
5.30%
13.25%
7.55%
SOURCE
See Table 1-1.
Kavanaugh, M. 1987. Average beta for
petroleum companies, Standard & Poor's
Reports .
Brealey and Myers 1984.
Calculated.
See Table 1-1.
24
Stock
Tax Reform Act of 1986, highest corporate
tax bracket is 34 percent.
See text.
See text.
See Table 1-1.
Source: as listed.
1-12
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APPENDIX J
ERG ECONOMIC MODEL FOR OFFSHORE PETROLEUM PRODUCTION
J.I INTRODUCTION
The ERG model simulates the costs and petroleum production dynamics
expected in the development and production of an offshore well for oil and/or
gas. Data to define the well and the petroleum reservoir are entered into the
model. Through the use of internal algorithms, the model calculates the
economic and engineering characteristics of the project. Outputs from the
model include: production volume, project economics, and summary statistics.
The model is structured to be flexible. It is capable of modeling
projects on a single-well or multiple-well basis with exploration and
development occurring within a single year or over a decade. Flexibility is
possible through the use of user-specified inputs for a wide variety of
variables. Inputs include, but are not limited to: lease bids, development
schedules, infrastructure and operating costs, initial petroleum production,
production decline rates, tax rate schedules, and wellhead prices. The data
define the proposed development project.
From the user-specified data, costs and production performance are
calculated on a yearly basis through a series of algorithms. The model
calculates yearly production, present value of yearly production and present
value of production income. The model generates a consistent set of annual
values and summary statistics to evaluate the project. All dollar amounts in
this analysis and in the accompanying printout are in thousands of 1986
dollars.
J.I.I Model Phases
The project life of an offshore well for oil and/or gas is divided into
five phases: (1) from lease bid to the start of exploration, (2) from the
start of exploration to the start of delineation, (3) from delineation to the
start of development, (4) from the start of development to the start of
J-l
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production, and (5) production. The length of each of these phases is an
exogenous variable input to the model.
For multiple well projects, the impetus to begin production is great and
the production phase may overlap the development phase. That is, petroleum
production may begin while some wells are still being drilled. The ERG model
is capable of modeling this situation (see Section J.2).
The project operates for 30 years or for as long as it is profitable.
Project economics are evaluated annually within the model algorithms and the
project is shut down at the first negative cash flow.
J.1.2 Economic Overview of the Model
The economic character of the model phases is quite different. Phases one
through four generate cash outflows; no revenues are earned during this
period. The fifth phase, production, generates net cash inflows. During this
phase, the project will continue to operate as long as operating cash inflows
exceed cash expenses.
J.I.2.1 Cash Flows - Categorization
The model deals with a number of basic cash flows (or resource transfers).
The basic cash flows are as follows:
Leasing Phase: Lease bid - cost of acquiring rights to explore and
develop a tract of land.
Exploration Phase: G&G costs - geological and geophysical expenses
incurred prior to drilling.
Exploration well costs - cost of drilling an
exploration well.
Incremental drilling costs - additional cost of
drilling due to new regulations concerning muds and
cuttings.
Delineation Phase: Delineation well costs - costs of drilling a
delineation well.
Incremental drilling costs - additional cost of
drilling due to new or revised regulations concerning
drilling fluids and drill cuttings.
J-2
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Development Phase: Development well costs - costs of drilling a
development well (includes prorated cost of building
and installing a petroleum production platform, see
Appendix F).
Infrastructure costs - cost of production equipment
installed on the platform.
Incremental drilling costs - additional cost of
drilling due to new or revised regulation concerning
drilling fluids and drill cuttings.
Production Phase: Revenues from oil and gas production - production
levels multiplied by price forecasts.
O&M costs - cost of operating and maintaining the
well.
The basic cash flows, summarized above, are affected by a number of
factors that are depicted in Table J-l below. The matrix in Table J-l can be
illustrated by using the lease bid as an example. Initially, the lease bid
generates a cash outflow in the initial phase of the project. Three factors,
however, will allow a portion of that outflow to be recouped during the
production phase of the project. These factors, the Federal and state
corporate tax rates and the depletion allowance for major integrated
producers, are denoted by plus signs in the table because of their positive
effect on the project cash flow. (Major producers are allowed to amortize the
leasehold cost over the productive life of the well and use this allowance to
reduce taxable revenue. For a more detailed discussion of the depletion
allowance, see Section I.10.)
J.2 STEP-BY-STEP DESCRIPTION OF THE MODEL
The ensuing discussion is a sequential overview of how the code operates.
It starts with the lease bid and ends with the shut down of the well either
after 30 years of production or when the project becomes unprofitable. To
illustrate the code, the inputs, calculations, and outputs for a 12-well oil
and gas platform in the Gulf of Mexico are used. The project was chosen
because its size and production type are common in the Gulf (see Appendix A).
The discussion is based on the computer printout that is attached to this
appendix. Identification numbers for specific lines are given in the right-
hand margin. A list of user-specified inputs is given in Table J-2. All
dollar values (e.g.. costs and revenues) are expressed in thousands of 1986
dollars. Values on spreadsheet may differ in the final digit from numbers
presented in the text due to rounding.
J-3
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TABLE J-l
EFFECT OF TAX AND ACCOUNTING SYSTEMS ON CASH FLOWS
AFFECTING FACTORS
LEASE G&G
BID COSTS COSTS
PRODUC-
EXPLOR- DELIN- TION
ATION EATION DEVELOP- EQUIP-
WELL WELL MENT WELL MENT
COSTS COSTS COSTS
BAT/
NSPS
INCRE-
MENTAL PRODUC-
DRILLING TION OPERATING
COSTS REVENUES EXPENSES
Federal Corporate
Income Tax
State Corporate
Income Tax
Depletion Allowance
Royalties
State Severance Tax
Depreciation
Current Expensing
+ (cost basis)
+ (percentage basis)
+ - Increases net cash inflow. In the case of expense items, cash outflows, the existence of tax
rates mitigates the cash outflows.
- - Decreases net cash inflow. In the case of revenue items, cash inflows, the existence of tax
rates decrease cash inflows.
-------
TABLE J-2
EXOGENOUS VARIABLES PROVIDED TO ERG ECONOMIC MODEL
IDENTIFICATION
NUMBER
PARAMETER
1
2
4
5
6
7
8
9
10
12
13
23
24
25
36
37
38
39
40
41
48
56
57
58
59
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Lease cost.
Geological and geophysical expense.
Real discount rate.
Inflation rate
Years between lease sale and exploration.
Percent of cost considered expensible intangible drilling
costs.
Drilling mud cost increment.
Federal corporate tax rate.
Drilling cost per exploratory well.
Discovery efficiency.
Platforms per successful exploratory well.
Years between start of exploration and delineation.
Number of delineation wells drilled.
Cost per delineation well.
Total platform cost.
Pollution control capital costs (produced water).
Years between delineation and development.
Number of development wells drilled.
Number of development wells drilled per year.
Drilling cost per development well.
Annual Pollution Control Capital Costs.
Percent watercut in oil and gas to start.
Oil and gas production decline rate.
Cost escalator.
Royalty rate.
Depreciation schedule.
Severance tax rate - oil.
Severance tax rate - gas.
Gas only flag.
Years between development and production.
Years at peak production.
Oil - peak production rate (bbl/day).
Gas - peak production rate (MMCF/day).
Number of producing wells.
Number of wells put in service per year.
Wellhead price per barrel - oil.
Wellhead price per Mcf - gas.
Total operating costs.
Annual pollution control equipment operating cost (produced
water).
Source: ERG estimate.
J-5
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J.2.1 Phase One - Leasing
The lease cost (line 1) is a user-specified input, the value of which is
based on 1986 lease sales in the Gulf of Mexico. See Appendix C for regional
lease costs and their derivation.
J.2.2 Phase Two Exploration
Line 2 represents the costs of geological and geophysical (G&G)
investigation of the site as a percentage of lease cost. The value shown in
line 2 is based on information in the API cost survey for 1986 (see Section
D.I). The total leasehold cost (line 3) is the sum of the lease bid and G&G
expenses. The total leasehold cost is a cash outflow in Year 0 of the
project; the value on line 3 is therefore the present value of the leasehold
cost. The leasehold cost forms the basis for the depletion allowance as
calculated on a cost basis for major integrated producers.
Line 4 is the real discount rate, i.e., the cost of capital. This value
will be used throughout the code to discount future cash inflows, cash
outflows, and production in order to express them in present value terms.
Line 5 is the inflation rate. This parameter is used to reduce the value
of the deductions for cost-basis depletion and depreciation in future years.
Line 6 is the number of years between the lease bid and the start of
exploration. For all projects in the Gulf of Mexico, exploration begins in
the same year as the lease sale. For other regions, the number of years
between lease bid and the start of exploration varies from one to. two years
(see Appendix B).
The petroleum industry has considerable latitude in its treatment of
costs. Unlike most other industries, an oil company can expense, in the
period incurred, costs that would normally be capitalized. The immediate
expensing of a portion of capital costs provides a significant tax advantage
to an oil company.
Line 7 contains the percentage of drilling costs that are considered
"Intangible Drilling Costs" (IDCs) and are eligible for expensing. An initial
value of 60% is used in this analysis as the percentage of costs considered
J-6
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IDCs. This is based on annual surveys of expenditures (see Section 1.7).
Under the Tax Reform Act of 1986, independents may expense 100% of IDCs, while
majors may expense only 70% of the IDCs. Since the project is assumed to be a
venture by a major company, the value shown is 42 percent (0.60 x 0.70).
The additional costs due to new pollution control regulations on drilling
muds and cuttings are entered in line 8. The Federal corporate income tax
rate is entered on line 9.
The drilling cost for a well depends on the depth drilled, environmental
requirements, and regional costs for parts and labor. The cost of drilling a
well has been summarized in Section D.3, and is entered on line 10. The
discovery efficiency, the ratio of productive wells to all wells drilled, also
varies by region, depending upon the predictability of the reservoir. All-
time regional averages are used in this study (see line 12. Section D.2).
Line 13 is the number of platforms built per successful exploratory well.
This parameter varies by region, see Section C.3.
Line 14 displays the exploratory well costs for the project. The
exploratory well cost is the sum of the cost of drilling the well and the
drilling mud cost increment divided by the product of the discovery efficiency
and the number of platforms per successful well. This cost is spread over the
number of years between the start of exploration and the start of delineation
(see line 23). For the 12-well COM project, the annual exploratory well costs
are:
Annual (well cost + incremental drilling fluid cost) + Years
Explora- - (discovery efficiency * no. of platforms per of
tory Well successful well) Exploration
Costs
- (4.355 + 0) +1 - $7,234
(.14 * 4.3)
One year for exploration is scheduled for this project (line 23).
The annual cost of successful efforts (line 15) is the product of the
annual exploratory well cost and the discovery efficiency:
Annual Cost of - Annual Total Well Cost
Successful Efforts * Discovery Efficiency
- ($7,234 * .14) - $1,013
J-7
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Annual expensed costs (line 16) are the sum of two factors: (1) the
product of the annual cost of successful efforts times the percent costs
expensed (line 7) and (2) dry hole expenses:
Annual Expensed - (cost of successful efforts x % expensed)
Costs + exploratory costs x (1-disc. eff.)
- ($1,013 * .42) + ($7,234 * .86)
- $425 + $6,221
- $6,646 (note rounding)
In other words, the annual expensed cost is the sum of unsuccessful efforts
and the expensible portion of intangible drilling costs for successful wells.
The expensed cost is $6,646/yr for each year of exploration. The actual
cash outflow, however, is dependent upon the corporate tax rate. The expenses
reduce the tax bill for a profitable corporation. The calculations to
determine the actual cash outflow, shown below, assume a marginal corporate
tax rate of 34 percent (see line 17).
Expensed Cash Flows - (1 - tax rate) * Expensed Costs
- (1 - .34) * $6,646 - $4,387
Capitalized cash flows, line 18. are the exploration costs that are not
expensed. The proportion of drilling efforts that may be expensed depends
upon whether the corporation is a major or independent producer. For the Gulf
of Mexico project, a major producer is assumed. Under the Tax Reform Act of
1986, a major may expense 70 percent of the intangible drilling costs (IDCs)
and the IDCs are estimated to be 60 percent of the drilling costs. For a
major, then, 1 - (0.6 x 0.7) or 58 percent of the successful drilling costs
are capitalized:
Capitalized Cash Flows - 0.58 * Cost of Successful Effort
(line 18)
- 0.58 * $1,013 - $587
Since capitalized costs generate no tax shield in the year incurred, the
capitalized cash flow is equal to the capitalized cost.
Once the various exploration costs and cash flows have been calculated,
they are put in present value terms as of the lease year. For all Gulf of
J-8
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Mexico offshore projects, exploration costs are incurred in Year 0, the year
the lease was obtained. For these projects, the present value of all
exploration costs are the same as the value for Year 0.
Present values are calculated for expensed exploration cash flows,
capitalized exploration cash flows, and all exploratory costs (lines 19. 20.
and 22). The sum of all capitalized exploration cash flows is given in line
21.
J.23 Phase Three - Delineation
If an exploratory well discovers petroleum, delineation wells may be
drilled to confirm the size and extent of the reservoir. In this project, one
year is assumed to pass between the start of exploration and the start of
delineation (line 23. see Appendix B for timing assumptions). Two delineation
wells are drilled (line 24), each costing the same as an exploratory well
(line 25). As with exploratory wells, the costs are allocated over the number
of platforms per successful exploratory well (line 27).
The annual delineation costs (line 28) are the product of the number of
delineation wells and the cost per delineation well, divided by the number of
platforms per successful exploratory well. This cost is allocated over the
number of years between the start of delineation and the start of development
if its value is greater than one (line 37). For the 12-well Gulf of Mexico
project, the annual delineation well costs are:
Annual - (well cost + incremental drilling fluid cost)
Delineation * number of delineation wells
Well + number of platforms per successful discovery
Cost
($4,355 * 2) + 4.3
- $2,026
The tax shield (line 29) is the product of the annual delineation cost,
the percentage of drilling costs considered intangible drilling costs (which
are therefore eligible for expensing), and the corporate tax rate:
J-9
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Tax Shield - Drilling Cost
*Percentage of drilling costs considered IDCs
*Percent of IDC that can be expensed
*Federal corporate tax rate
- $2,026 * 0.6 * 0.7 * .34
- $289
Expensed cash flow (line 30) is the annual delineation well cost times the
expensed percentages of IDCs minus the tax shield:
Expensed Cash Flow - (Annual delineation cost
* percentage considered expensible IDCs)
- tax shield
($2,026 * 0.42) - $289
$562 (note rounding)
Capitalized cash flow (line 31) is the annual delineation well cost times the
portion of costs that cannot be expensed.
Capitalized cash flow - delineation costs * (1 - 0.42)
- $2,026 * .58
- $1,175
Once the various delineation costs and cash flows have been calculated,
they are put in present value terms of the half year. The delineation costs
are incurred in Year 1 of the 12-well Gulf of Mexico project. The costs and
cash flows must be adjusted by the time value of money, i.e., the discount
rate. For this project, the delineation costs are discounted as follows:
Present Value - cost in Year I + 1.081
For the expensed cash flow, this is
PV expensed cash flow - $561 +1.08
- $520
Present values are calculated for expensed cash flow, capitalized delineation
costs, and total delineation costs (lines 32-35).
J-10
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J.2.4 Phase Four Development
The costs of production equipment and other infrastructure costs are
entered in line 36. Additional construction costs for the installation of
pollution control equipment are entered separately in line 37. For this
project, there are two years between the start of development and the start of
production (see line 66). Costs for both types of construction are allocated
over the first year or over the years of construction minus one year (see line
4Z).
The development phase in the code is structured to accommodate the
drilling of development wells after a reservoir has been determined. Separate
entries for the total number of wells in the project, the number of wells
drilled each year, and the drilling cost per well appear in lines 39 through
41. respectively.
Lines 42 through 48 calculate the costs incurred each year from the
drilling of development wells, and the construction of production and
pollution control facilities. The total annual capital development costs are
given in line 49.
The tax shield, line 50. is the product of the annual total capital
development costs, the corporate tax rate, and the percent of costs expensed.
For Year 1 of the 12-well Gulf of Mexico project, this is $11,660 x 0.34 x .42
or $1,665. The expensed cash flow, line 51. is the total annual capital
development costs (line 49) times the percentage of costs expensed (line 7)
minus the tax shield (line 50). For Year 2, this is ($29,436 x 0.42) - $4,203
or $8,160. The capitalized cash flow, line 52. is the product of total
capital costs and (1 - the percentage of expensible IDCs). For Year 3, this
is $19,624 x 0.58 or $11,382. Note that the sum of the tax shield, the
expensed costs and capitalized costs is equal to the total costs.
As with the exploration costs, development costs are discounted to
determine their present value in the lease year. Present values of all
development costs, expensed development costs, and capitalized development
costs are given in lines 53 through 55. respectively.
J-ll
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J.2.5 Phase Five - Production
In the production phase of the project, a variety of financial and
engineering variables interact to form the economic history of the well.
Line 57 provides the production decline rate for oil and gas. The ERG model
incorporates an exponential function for production decline, i.e., a constant
proportion of the remaining reserves is produced each year. For every barrel
produced in the initial year of operation in this project, 0.85 barrel is
produced in the second year, 0.852 or 0.723 barrel in the third year, and so
forth.
The ERG model is capable of handling cost escalation (see line 58). In
this report, we are considering costs in real terms, and thus no escalation is
assumed.
The royalty rate paid to the lessor of the land is provided in line 59.
The depreciation schedule is listed in line 62. State severance taxes on oil
and gas are given in lines 63 and 64. respectively. Note the flag for
calculating severance taxes for Alaska since these must be adjusted by the
Economic Limit Factor (ELF).
Line 65 is a flag to identify gas-only projects. The flag is necessary
for the proper calculation of depletion on a cost basis within the code.
The number of years that a well produces at its peak rate is given in
line 67. The peak production rates per well for oil and gas are given in
lines 68 and 69. respectively. Note that these are figures for daily
production and that the units for gas production are MMcf/day.
Since not all wells are turned into producing wells (e.g., exploratory
wells in offshore operations or reinjection wells), lines 70 and 71 specify
the number of producing wells and the rate at which they enter production.
The wellhead prices for oil and gas are entered on lines 72 and 73.
Annual operating costs are entered on line 74. while line 75 contains the
incremental costs of water disposal due to compliance with pollution control
regulations.
Line 77 provides the number of producing wells in service and is
calculated from the total number of producing wells and the number of wells
that go into service per year. The barrels of oil produced per day dine 78)
j-12
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is a function of the number of wells and the year in which they went into
service.
In general, production for a group of wells that went into service in the
same year is calculated as:
Daily Production - # of wells x # of barrels/day x decline rate"
where a - year of production - number of years at peak production
This is extended to calculate production for wells going into service in
different years. For example, in line 78,
Daily Production Year 3-6 wells * 500 bopd
- 3,000 bopd
Year 4 - (6 * 500) + (4 * 500)
- 3,000 + 2,000
- 5,000 bopd
Year 5 - (6 * 500 * 0.85) + (4 * 500)
-2,550+2,000
- 4,550 bopd
Year 6 - (6 * 500 * 0.852) + (4 * 500 * 0.85)
- 2,168 + 1,700
- 3,868 bopd
and so forth.
The annual oil production is calculated as 365 times the daily production
(line 80). The price per barrel is repeated in line 81 for convenience in
cross-checking the gross revenues for oil production (line 85). Lines 82. 83,
and 84 list the daily gas production, annual gas production, and wellhead
price per Mcf.
J.2.5.1 Income Statement
Lines 85 through 107 comprise an income statement that is repeated
annually for a thirty-year project lifetime. Since most projects become
uneconomical before this, lines 108 through 114 check for a negative net cash
J-13
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flow and readjust the actual production, revenues, and cash flows to zero when
appropriate.
Lines 85 and 86 list the revenues from oil and gas production. Total cash
inflow for the year is given in line 87. Royalty payments are calculated on
the basis of gross revenues (lines 88 and 89. see line 60 for the royalty
rate). Severance taxes are calculated on the basis of gross revenues minus
royalty payments (lines 90 and 91. see lines 63 and 64 for severance tax
rates). The economic limit factor (ELF) for the calculation of severance
taxes for Alaska is given in lines 92 and 93 (see Section H.2 for a more
complete discussion of severance tax calculations for Alaska). Net revenues
for Year 3, line 94. are calculated as:
Net revenues - Total Gross revenues - royalty payments
- severance taxes
- $30,783 - $5,738 - $1,034 - $1,259 - $227
- $22,525 (note rounding)
Operating costs are given in line 95: incremental operating costs due to
pollution control appear in line 97. The entry on line 98 is the sum of the
capitalized costs spent in the exploration, delineation, development and
production phases to that year:
Capitalized Costs - Capitalized Costs in the Exploration Phase
For Year 3 + Capitalized Costs in the Development Phase
+ Capitalized Costs in Development Phase up to that year
- $587 + $1,175 + $6,763 + $17,073 - $25,598
(line 21) (line 33) (line 52)
The adjusted depreciation allowance is listed in line 99. The
depreciation schedule under the Tax Reform Act of 1986 is found on line 62.
The unadjusted depreciation allowance is the product of $25,598 (capitalized
costs) and the depreciation rate for the appropriate year, e.g., $25,598 x
14.29% - $3,658 for the first year of operation for the project (Year 3).
The figure of $3,658 is the number that would be used in the tax
calculations for the company. The value of that deduction, however, has been
eroded by inflation. To adjust for this effect, we calculate a deduction that
is deflated, e.g., $3,658 + (1 + inflation rate)Ye"x or $3,658 + (1.042)3 -
($3,658 + 1.131) - $3,234, see line 99 and note rounding.
J-14
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The operating earnings (line 100) are defined as net revenues (line 94)
minus operating costs (line 95) minus pollution control operating costs (line
96). For Year 3 of the project:
Operating Earnings - Net revenues - operating costs
- pollution control operating costs
- $22,524 - $2,312 - $0 - $20,212
Line 101. earnings before interest and ODA (oil depletion allowance),
subtracts depreciation and amortization from operating earnings. For Year 3,
Earnings Before - $20,212 - $3,234 - $16,978 (note rounding)
Interest and ODA
For major integrated producers, the depletion allowance is calculated on a
cost basis, that is, the leasehold cost is amortized over the productive life
of the well:
Depletion Leasehold Depletion "Year X" Production
Allowance - Cost - Allowance x Total Production
in "Year X" Taken from "Year X".
for Year 3, the depletion allowance for the Gulf project is:
- ($11,952 - 0) * x (1,095,000 bbl + 13,875,110 bbl)
(Line 3)
- $943
Depletion is calculated based on oil production only, unless the gas-only flag
is set in Line 65.
The figure of $943 must be deflated because the leasehold cost was spent
in Year 0, but the deduction is not taken until a later year. For Year 3, the
adjusted depletion allowance (line 102) is calculated as:
Adjusted
Depletion Depletion Allowance
Allowance - in "Year X" (1 + inflation rate)Year x
in "Year X"
(line 90)
For Year 3 in the project, the adjusted depletion allowance is:
- $943 + (1.042)3
- $834
J-15
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The depletion allowance is calculated on an unadjusted basis for every year
and then deflated. If the project ends while a depletion allowance may still
be taken, the depletion allowance in that year and subsequent years is termed
"surplus depletion" (line 116).
Earnings before interest and taxes dine 104) is defined as the earnings
before interest and ODA (line 101) minus the adjusted oil depletion allowance
(line 102). For Year 3 of the project, earnings before interest and taxes are
$16,979 - $834 - $16,145.
The earnings in line 104 form the basis for Federal income tax. This is
calculated in line 105 on the basis of information in line 9 (Federal tax
rate). Earnings after taxes are given in line 106.
The project cash flows, line 107. are determined by adding non-cash
expenses, depreciation and depletion, to earnings after taxes. The net cash
flow for Year 3 is $10,656 + $3,233 + $834 - $14,723.
The cash flows forecasted for the project may or may not be sufficient to
justify continuation of operations. In some circumstances, net cash flows may
be positive only because of large values for depreciation, e.g., where large
capital expenditures are required on a small project or later in the operating
life of the project. Under these circumstances, the project is likely to shut
down even though cash flow is positive. Project shutdown is evaluated by the
parameter
Project shutdown - Net cash flow (Line 107)
- (tax rate * depreciation and amortization)
(line 9) (line 99)
- (1-tax rate) * (expensed pollution control
capital costs)
(line 96)
which calculates the actual cash outlay in that year. If the parameter is
equal to or less than zero, the project is assumed to shut down. The model
prints a "1" in line 108 for years in which the project operates and a "0" for
years in which the project does not operate.
In the event that the project is shut down, certain variables must be
recalculated to reflect that decision. Lines 109 through 114 restate
production volumes, revenues, and cash flow in light of the shutdown. That
is, production and revenues are set to zero after the project shuts down.
J-16
-------
Other project variables, such as depreciation, are recalculated because of the
earlier shutdown date. Unexpended capitalized costs and surplus depreciation
are given in lines 115 and 116.
The income statement for the second and third.decades of operation is
found on lines 117 through 155 and 156 through 190, respectively.
J.2.6 Summary Statistics
At the end of the project, all costs and revenues are put in present value
terms as of the lease year; see lines 191 through 222. Two terms have not
been discussed previously. Line 194. expensed investment cash flows, is
defined as the sum of the present values for expensed exploration cash flows
(line 19) and expensed delineation and development costs (lines 32 and 54)
minus the present value of unexpended expensed investment costs. For the
project, this is $4,387 + $520 + $14,307 - 0 - $19,214 (note rounding).
Line 195. capitalized costs, is the sum of the present values of capitalized
exploration costs (line 20) and capitalized delineation and development costs
(lines 34 and 55) minus the present value of unexpended capital costs. For
the project, this is $587 + $1,088 + $29,934 - $0 - $31,609 (note rounding).
The present value of total company costs is the summation of the present
values of the parameters so listed in Table J-3; see line 204. This parameter
provides a measure of the present value of net company resources expended in
development and operation of petroleum projects. Entries marked with a "plus"
in the column contribute to corporate costs. Excess depreciation and surplus
depletion lower corporate costs and are therefore marked with a "minus".
Total company costs for oil are the present values for oil royalties and
severance taxes and the oil portion of the remaining costs, see line 205).
These costs are apportioned by the ratio of oil revenues to total revenues.
An analogous procedure is followed to obtain the total company cost for gas
(see line 206).
The capital and the annual operation and maintenance costs for incremental
pollution control of produced water effluents are put in terms of present
value and are annualized over the economic lifetime of the well. The
annualized cost is given in line 207.
J-17
-------
TABLE J-3
COST AND CASH FLOW USES IN THE MODEL
USE IN MODEL
COST OR CASH FLOW ITEM
COMPANY
COST
SOCIAL
COST
DEPLE-
TION
(COST
BASIS)
DEPREC-
IATION
Leasehold cost
G&G expenses
Total capitalized exploration costs
Total capitalized delineation costs
Total capitalized development costs
PV of expensed investment cash flows
PV of capitalized costs
PV of pollution control costs
PV of royalties
PV of severance taxes
PV of operating costs
PV of income taxes
PV of excess depletion
PV of surplus depreciation
PV of all investment costs
operations
capital
PV - present value.
-------
Oil and gas production is also discounted to give present value
equivalents; see lines 208 through 210. Corporate costs per barrel and
corporate costs per Mcf are obtained by dividing the present value of the
company cost by the present value equivalent of production (see lines 211
through 213).
The present value of social costs (lines 214 through 216) provides a
measure of the value of net social resources expended in the development and
operation of offshore petroleum projects. The difference between company cost
and social cost is that the social cost ignores the effects of transfers that
do not use social resources. The items included in social cost are listed in
Table H-3. Social cost per unit of production is obtained by dividing the
social cost by the present value equivalent of production, lines 217 through
213.
The net present value of the project, line 220. is calculated as:
Net Present - PV of Cash - PV of Cash
Value Inflows Outflows
PV of Operating Cash Flows
- PV of Expensed Investment Cash Flows
- PV of Capitalized Costs
- PV of Leasehold Costs
+ PV of Excess Depletion
+ PV of Surplus Depreciation
A positive net present value is indicative of a profitable project at the
assumed discount rate, i.e., it generates more revenue than investing the
capital in a project with that expected rate of return.
The internal rate of return, line 221. is the rate of return that equates
the present value of capital in the exploration and development of the project
with the present value of the operating cash flows. An internal rate of
return higher than the discount rate is indicative of a profitable project.
The net present value and the internal rate of return are inverse methods
of evaluating the profitability of a project. In calculating the net present
value, the discount rate is fixed and the net present value may vary. In
calculating the internal rate of return, the net present value is set to zero
and the discount rate is allowed to fluctuate.
J-19
-------
LINE-
Sun Date: 08-Feb-90 1986 data _^tf-L_
Project Type: Gulf 12
OIL and GAS
Lease Bid: $5,673 1
G&G Expense: 110.SOX 2
Leasehold Cost: $11,952 3
Real Discount Rate: 8.00X 4
Inflation Rate: 4.20X 5
Yrs Btwn Lease Sale & Strt of Exp: 0 6
Percent Costs Expensed: 42.00% 7
Drilling Mud Cost Increment: SO 8
Corporate Tax Rate: 34X 9
EXPLORATION COSTS
Cost Per Exploratory We( I: $4,355 10
Drilling Mud Cost Increment: SO 11
Discovery Efficiency: 0.14 ' . 12
Platforms per Successful Expl. Wei 4.3 13
Year Year Year Year
0123
Explor. Costs Per Platform: $7,234 SO SO SO 14
Cost of Successful Efforts: $1,013 SO SO SO 15
Expensed Costs: $6,647 SO SO SO 16
Expensed Cash Flows: $4,387 SO SO SO K7
Capitalized Cash Flow: SS87 SO SO SO KB
PV of Expensed Exploration Cash Flows: $4,387 19
PV of Capitalized Expl. Cash Flows: SS87 20
Total Capitalized Expl. Costs: S587 21
PV of all Expl or story Costs: S7.234 22
DELINEATION COSTS
Years Between Start of Expl.
and Delineation: 1 23
Muter of Delineation Wells
Drilled: 2 24
Cost per Delineation Well: $4,355 25
Drilling Nud Cost Increment: SO 26
Platform Per Find: 4.3 27
Year Year Year Year
1 2 34
Total Delineation Costs: $2,026 SO SO SO 28
Tax Shield: $289 SO SO $0 29
Expensed Cash Flow: S561 SO SO SO 30
Capitalized Cash Flow: $1,175 $0 $0 $0 31
J-20
-------
PV Expensed Cash Flow:
Total Capitalized Delineation Costs:
PV of Capitalized Delineation Costs
PV of all Delineation Costs:
Total Platform Cost:
Pollution Control Capital Costs:
Yrs btun Delineation & Constn:
Hunter of Wells Drilled:
Number Uells Drilled Per Year:
Drilling Cost Per Well:
Drilling Cost Per Well:
Drilling Hud Cost Increment:
Well Start:
Nuster of Uells Drilled:
Total Drilling Costs for Year:
Annual Platform Cost:
Annual Poll Cent Capital Costs:
Total Annual Capital Cost:
Tax Shield:
Expensed Cash Flow:
Capitalized Cash Flow:
PV of All Construction Costs:
PV of Expensed Construction Costs:
PV of Capitalized Construction Costs:
FINANCIAL RATES
SS20
is: $1,175
:sj $1,088
$1,876
CONSTRUCTION COSTS
$11,660
$0
0
10
6
$4,906
Taar Year Year Year Year Year Year Year Y«ar >
12345 6739
$4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906
SO $0 $0 $0 $0 $0 $0 $0 $0
01234 5678
06400 0000
SO $29,436 $19,624 SO SO SO $0 $0 SO
$11,660 $0 $0 SO $0 SO SO SO $0
SOSOSOSOSO SOSOSOSO
$11,660 $29,436 $19,624 SO SO SO SO $0 SO
$1,665 $4,203 $2,802 $0 SO SO $0 SO $0
$3,232 $8,160 $5,440 SO $0 $0 $0 SO $0
$6,763 $17,073 $11,382 $0 SO SO $0 SO SO
$51,611
$14,307
ts: $29,934
10X
8SX
OX
22X
34X
7
14.29X 24.49X 17.49X 12.49X 8.93X 8.92X 8.93X 4.46X
6.19X
LINE
NO.
32
33
34
35
36
37
38
39
40
41
'63-
10
$4,906 42
SO 43
9 44
0 45
SO 46
SO 47
s° 48
SO 49
SO 50
SO 51
SO 52
53
54
55
56
57
58
59
60
61
62
63
Percent Water Cut in OtG to Start:
Of I/Gas Prod. Oecl. Rate/Year (X):
Cost Escalator (X):
Royalty Rate (X):
Federal Tax Rate (X):
Average Depreciation life (years):
Deprec. rate (subs, years):
State Severance Tax Rate-Oil:
(If Alaska enter 99)
State Severance Tax Rate-Gas: 6.19X 64
(If Alaska enter 99)
J-21
-------
PRODUCTION COSTS
Gas Only? (1=yes, 0»no):
Yrs Btun Strt Dev & Strt Prod (<5)
Number of Years at Peak Prod («>1)
Oil Peak Prod. Rate/Well(bb):
Gas Peak Prod. Rate/We IKMMCF/D):
Mo. of Producing Wells:
Mo. of Uells Put in Service/Year:
Price of Oil Per Barrel:
Price of Gas Per HCF:
Total Operating Costs ($000):
Poll Cont Oper Costs ($000):
Days of Production Per Year:
Producing Wells:
Barrels of Oil Per Day:
Days of Production Per Year:
Barrels of Oil Per Year:
Price/Barrel of Oil:
HCF of CM Per Day:
WCF of CM Per Year:
Price/NCF of Gas:
Annual Oil Revenues ($000):
Annual Gas Revenues ($000):
Total Revenues ($000):
Royalty Ptyaents-OiI ($000):
Royalty Payaents-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska S«v. Taxes-Oil:
ELF for Alaska Sev. Taxes-Gas:
Net Revenues ($000):
Total Operating Costs ($000):
Exp. Poll.Cont.Cap.Costs ($000):
Poll.Con.OperatIng Costs ($000):
Capitalized Coats ($000):
Adjstd Deprec I Ajeort ($000):
Operating Earnings ($000):
Earnings Before Interest and 00A:
Adjstd Depletion (Cost Basis):
Surplus Depletion:
0
) 2
) 2
500
0.835
10
6
$23.82
$2.57
$2,312
$0
365
Year
3
Year
4
Year
5
Year
6
Year
7
Year
8
Year
9
Year
10
Year
1 1
rear
12
NO.
65
66
67
68
69
70
71
72
73
74
75
76
OIL PRODUCTION
6
3000
365
1095000
$23.82
4
5000
365
1825000
$23.82
0
4550
365
1660750
$23.82
0
3868
365
1411638
$23.82
0
3287
365
1199892
$23.82
2794
365
1019908
$23.82
2375
365
866922
S23.82
2019
365
736884
$23.82
1716
365
626351
$23.82
1459
365
532398
$23.82
77
78
79
80
81
GAS PRODUCTION
5
1829
$2.57
$26,083
$4,700
$30,783
$5,738
$1,034
$1,259
$227
0.25
-2.59
$22,524
$2.312
$0
SO
$25,598
$3,233
$20,212
$16,979
$834
$0
8
3048
$2.57
$43,472
$7,833
$51,304
$9,564
$1,723
$2,099
$378
0.25
2.59
$37,540
$2,312
SO
SO
$11,382
$6,697
$35,228
$28,531
$1,334
$0
8
2773
$2.57
$39,559
$7,128
$46,687
$8,703
$1,568
$1,910
$344
0.19
-2.95
$34,162
$2,312
SO
SO
so
$5,914
$31,850
$25,936
'$1,165
$0
6
2357
$2.57
$33,625
$6,059
$39,684
$7,398
$1,333
$1,623
$293
0.10
-3.64
$29,037
$2,312
$0
SO
SO
$4,053
$26,725
$22,672
$950
$0
5
2004
$2.57
$28,581
$5,150
$33,731
$6,288
$1,133
$1,380
$249
0.02
-4.46
$24,682
$2,312
$0
SO
so
$2,780
$22,370
$19,590
$775
SO
5
1703
$2.57
$24,294
$4,377
$28,672
$5,345
$963
$1,173
$211
ERR
-5.43
$20,979
$2,312
SO
SO
so
$2,374
$18,667
$16,293
$632
SO
4
1448
$2.57
$20,650
$3,721
$24,371
$4,543
$819
$997
$180
ERR
-6.56
$17,833
$2,312
$0
SO
so
$2,280
$15,521
$13.241
$516
$0
3
1231
$2.57
$17,553
$3,163
$20.715
$3,862
S696
$847
$153
ERR
-7.90
$15,158
$2,312
$0
$0
$0
$1,430
$12,846
$11.416
$421
$0
3
1046
$2.57
$14,920
$2.688
$17,608
$3,282
$591
$720
$130
ERR
-9.47
$12,884
$2,312
$0
$0
$0
$323
$10,572
$10,249
$343
$0
2
889
$2.57
$12,682
$2,285
$14,967
$2,790
$503
$612
$110
ERR
-11.32
$10,951
$2,312
$0
$0
$0
$0
$8,639
$8,639
$280
SO
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
J-22
-------
Earnings Before Int and Taxes:
Statutory Tax:
Earnings Before Int After Tax:
Net Cash Flow:
Shutoff?
Actual Oil Prod./Year (Barrels):
Actual Gas Prod./Year (HMCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Ptr Barrel:
MNCF CM Per Day:
MMCF Gu Per Tear:
Price Per NCF:
Oil Revenues ($000):
Gas Revenues ($000):
Total Revenues ($000):
Royalty Payaents-OiI ($000):
Royalty Payaants-Gaa ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Sev. Taxes-Oil:
ELF for Alaska Sev. Taxes-Gas:
Net Ravanun($000):
Operating Costs:
Exp. Poll.Cont.Cap.Costs ($000):
Pollution Control Operating Coats:
For PV Poll. Control:
Adjstd Daprac ft Amort ($000):
Operating Earnings ($000):
Earnings Before Interest and ODA:
Adjsted Depletion (Cost Basis):
Surplus Depletion:
Earnings Before Int and Taxes:
LINE
$16,145
$5,489
$10,656
$14.723
1
1095000
1829
$30,733
$22,524
$14,723
$5,489
SO
$0
Year
13
$27,197
$9,247
$17,950
$25,981
1
1825000
3048
$51,304
$37,540
$25,981
$9,247
$0
$0
Year
14
$24,771
$8,422
$16,349
$23,427
1
1660750
2773
$46,687
$34,162
$23,427
$8,422
$0
$0
Year
15
$21,722
$7,386
$14)337
$19,340
1
1411638
2357
$39,684
$29,037
$19,340
$7,386
$0
$0
Year
16
$18,815
$6,397
$12,418
$15,973
1
1199892
2004
$33,731
$24,682
$15.973
$6,397
$0
SO
Year
17
$15,661
$5,325
$10,336
$13,343
1
1019908
1703
$28,672
$20,979
$13,343
$5,325
$0
SO
Year
18
$12,725
$4,327
$8,399
$11,194
1
866922
1448
$24,371
$17,833
$11,194
$4,327
$0
$0
Year
19
$10.995
$3.738
$7,257
$9,107
1
736884
1231
$20,715
$15,158
$9,107
$3,738
$0
$0
Year
20
$9,906
$3,368
$6,538
$7,204
1
626351
1046
$17,608
$12,884
$7,204
$3,368
$0
SO
Year
21
$8,360
$2.342
$5,517
$5,797
1
532398
889
$14,967
$10,951
$5,797
$2,342
SO
SO
Year
22
NO.
104
105
106
107
108
109
110
111
112
113
114
115
116
OIL PRODUCTION
1240
365
452539
$23.82
1054
365
384658
$23.82
896
365
326959
$23.82
761
365
277915
$23.82
647
365
236228
$23.82
550
365
200794
$23.82
468
365
170675
$23.82
397
365
145074
$23.82
338
365
123312
$23.82
287
365
104816
S23.82
117
118
119
120
GAS PRODUCTION
2
756
$2.57
$10.779
$1,942
$12,722
$2,371
$427
$520
$94
ERR
-13.49
$9,309
Z312
$0
$0
$0
$0
$6,997
$6,997
$228
$0
$6,768
2
642
$2.57
$9,163
$1,651
$10,813
$2,016
$363
$442
$80
ERR
-16.05
$7,912
2312
$0
$0
$0
$0
$5,600
$5,600
$186
$0
$5,414
1
546
$2.57
$7,788
$1,403
$9,191
$1,713
$309
$376
$68
ERR
-19.05
$6,726
2312
$0
$0
$0
$0
$4,414
$4,414
$152
$0
$4,262
1
464
$2.57
$6,620
$1,193
$7,813
$1,456
$262
$320
$58
ERR
-22.59
$5,717
2312
$0
$0
$0
$0
$3,405
$3,405
$124
SO
$3,281
1
395
$2.57
$5,627
$1,014
$6,641
$1,238
$223
$272
$49
ERR
-26.76
$4,859
2312
$0
$0
$0
$0
$2,547
$2,547
$101
$0
$2,446
1
335
$2.57
$4,783
$862
$5,645
$1,052
$190
$231
$42
ERR
-31.65
$4,130
2312
$0
$0
$0
$0
$1,818
$1,818
$82
$0
$1,736
1
285
$2.57
$4,065
$733
$4,798
$894
$161
$196
$35
ERR
-37.42
$3,511
2312
$0
$0
$0
$0
$1,199
$1,199
$67
SO
$1,131
1
242
S2.57
$3,456
$623
$4,078
$760
$137
$167
$30
ERR
-44.20
$2,984
2312
$0
$0
$0
$672
$672
$55
$0
$617
1
206
$2.57
$2.937
$529
$3,467
$646
$116
$142
$26
ERR
52.17
$2,537
2312
$0
$0
$0
$225
$225
$45
SO
$180
0
175
$2.57
$2,497
S450
$2,947
S549
$99
$121
S22
ERR
-61.56
$2,156
2312
$0
SO
SO
C$156)
($156)
$37
$37
'($192)
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
J-23
-------
LINE
Statutory Tax:
Earnings Before Int After Tax:
Net Cash Flan:
Shutoff?
Actual Oil Prod./Year (Barrels):
Actual Ga* Prod./Year (HNCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Per Barrel:
WCF CM P«r Day:
MCF Gas Per Tear:
Price Per NCF:
Oil Revenues ($000):
Gas Revenues (SOOO):
Total Revenue* ($000):
Royalty Peyaents-OiI ($000):
Royalty Payments-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Sev Taxes-Oil:
ELF for Alaska Sev Taxes-Gas:
Net Revenuas($000):
Operating Coats:
Pollution Control Operating Costs:
For PV Poll. Control:
Operating Earnings ($000):
Earnings Before Interest and 00A:
Adjstcd Depletion (Cost Basis):
Surplus Depletion:
Earnings Before Int and Taxes:
Statutory Tax:
Earnings Before Int After Tax:
$2,301
$4,467
$4,695
1
452539
756
$12,722
$9,309
$4,695
$2,301
$0
SO
Year
23
$1,841
$3,573
$3,760
1
384658
642
$10,813
$7,912
$3,760
$1,841
$0
$0
Year
24
$1,449
$2,813
$2,965
V
326959
546
$9,191
$6,726
$2,965
$1,449
$0
$0
Year
25
$1,115
$2,165
$2,289
1
277915
464
$7,813
$5,717
$2,289
$1,115
$0
$0
Year
26
$832
$1,614
$1,716
1
236228
395
$6,641
$4,859
$1,716
$832
$0
$0
Year
27
$590
$1,146
$1,228
1
200794
335
$5,645
$4,130
$1,228
$590
$0
$0
Year
28
$385
$747
$814
1
170675
285
$4,798
$3.511
$814
$385
$0
$0
Year
29
$210
$407
$462
1
145074
242
$4,078
$2,984
$462
$210
$0
$0
Year
30
$61
$119
$163
1
123312
206
$3,467
$2,537
$163
$61
$0
$0
Year
31
(*6^^0§4
($127)145
($91)146
0 147
0 148
0 149
*° 150
10 151
SO 152
*°153
*° 154
$0 155
Year
32
OIL PRODUCTION
244
365
89093
$23.82
207
365
75729
$23.82
176
365
64370
$23.82
150
365
54714
$23.82
127
365
46507
$23.82
108
365
39531
$23.82
92
365
33601
$23.82
78
365
28561
$23.82
67
365
24277
$23.82
57 156
365 157
20636 i5g
$23.82 159
GAS PRODUCTION
0
149
$2.57
$2,122
$382
$2,505
$467
$84
$102
$18
ERR
72.60
$1,833
2312
$0
$0
($479)
($479)
$77
$77
($556)
($189)
($367)
0
126
$2.57
$1,804
$325
$2,129
$397
$72
$87
$16
ERR
-85.58
$1,558
2312
$0
SO
($754)
($754)
$65
$65
($819)
($279)
($541 )
0
107
S2.57
$1,533
$276
$1,810
$337
$61
$74
$13
ERR
100.86
$1,324
2312
SO
$0
($988)
($988)
$55
$55
($1,043)
($355)
($689)
0
91
$2.57
$1,303
$235
$1,538
$287
$52
$63
$11
ERR
-118.84
$1,125
2312
SO
SO
($1,187)
($1,187)
$47
$47
($1.234)
($419)
($814)
0
78
$2.57
$1,108
$200
$1,307
$244
$44
$53
$10
ERR
-139.99
$957
2312
SO
SO
($1,355)
($1,355)
S40
$40
($1.395)
($474)
($921)
0
66
$2.57
$942
$170
$1,111
$207
$37
$45
$8
ERR
164.87
$813
2312
SO
$0
($1,499)
($1,499)
$34
$34
($1,533)
($521)
($1,012)
0
56
$2.57
$800
S144
$945
$176
$32
S39
$7
ERR
-194.14
$691
2312
SO
SO
($1,621)
($1,621)
$29
$29
($1.650)
($561)
($1,089)
0
48
$2.57
$680
$123
$803
$150
$27
$33
$6
ERR
228.57
$588
2312
SO
SO
($1,724)
($1,724)
$25
$25
($1,749)
($595)
($1,154)
0
41
$2.57
$578
$104
$682
$127
$23
$28
$5
ERR
-269.09
$499
2312
$0
$0
($1,813)
($1,813)
S21
$21
($1,834)
($623)
($1,210)
oTeo
34 161
$2.57 162
$492 163
$89 164
$580 165
$108 166
$19 167
$24 168
$4169
ERR 17°
-316.75 171
$424 172
2312 173
*° 174
*°175
($1,888)i76
($1,888)177
$18 178
$18 179
($1,905)180
($648)i8i
(S1.258.tflc
J-24
-------
Net Cash Flow:
Shutoff?
Actual Oil Prod./Ye
Actual Ga* Prod./Year (MHCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
PV of Net Revenues:
PV of Excess Depletion:
PV of Surplus Depreciation:
PV of Capitalized Costs:
PV of Leasehold Cost:
PV Poll. Cont. Costs:
PV of Royalties -oil:
PV of Royalties - gas:
PV of Severance taxes
PV of Severance taxes
PV of IncoB* Taxes Paid:
PV of Operating Costs:
Total Company Costs:
Total CoMpmy Costs
Total Company Coats - Gas
Annualized Pol1.Cont.Costs:
($290)
0
garrets): 0
WCF): 0
WOO): SO
30): $o
MO): SO
>: $0
$152,784
$30
ion: SO
ish Flows: $19,213
: $31,610
$11.952
SO
$38,923
$7,013
oil: $8,542
gas: $1,539
$37,393
$19.036
$175,192
I: $148,445
is: $26,747
its: SO
$476) ($633) ($767) ($881) ($978)
0000
0 00 0
0000
$0 $0 $0 $0
$0 $0 $0 $0
$0 $0 $0 $0
SO $0 $0 $0
191 pv Equiv. of Oil (bbl): 7,427,
192 PV Equiv. of Gas (MHCF): 12.
193 pv BOE 9,611,
194 Amortized Company Cost per bbl:
195 Amortized Company Cost per Mef :
196 Amortized Company Cost per BOE:
197
198 pv Of social Costs - Total: $86,
199 pv of Social Costs - Oil: $72,
200 pv of social Costs - Gas: $13,
201
202 Amortized Social Cost per bbl:
203 Amortized Social Cost per Ncf:
Amortized Social Cost per BOE:
204
205 Net Present Value of Project:
206 internal Rate of Return:
207 NO. Of Years of Production:
0
0
0
SO
SO
$0
$0
539
404
069
031
896
135
19
LINE
NO.
($1,060) ($1,130) ($1,189) ($1,240) 183
0 0
0 0
0 0
$0 $0
$0 $0
$0 SO
$0 $0
$19.99
$2.16
$18.23
$9.81
$1.06
$8.95
$33,610
0.201
0 0 184
0 0 185
0 0 186
$0 SO 187
$0 $0 188
$0 SO 189
SO SO 190
208
209
210
211
212
213
214
215
216
217
218
219
220
221
222
J-25
------- |