Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards of Performance for the Offshore Oil and Gas Industry

      ECONOMIC IMPACT ANALYSIS OF FINAL EFFLUENT
LIMITATIONS GUIDELINES AND STANDARDS OF PERFORMANCE
         FOR THE OFFSHORE OIL AND GAS INDUSTRY
                          Prepared for:

                 U.S. Environmental Protection Agency
                         Office of Water
                   Office of Science and Technology
                   Engineering and Analysis Division
                Economic and Statistical Analysis Branch
                       Washington, DC 20460
                          Prepared by:

                    Eastern Research Group, Inc.
                        110 Hartwell Avenue
                       Lexington, MA 02173
                          January 1993

-------

-------
                                       PREFACE
       This document is an economic impact analysis prepared in support of the promulgation
of effluent limitations guidelines and standards of performance for drilling and production wastes
for the offshore oil and gas industry. The report analyzes the economic impact of alternative
regulatory options considered for drilling fluids, drill cuttings, produced water, produced sand,
end treatment, workover, and completion fluids.

       The report was prepared for the U.S. Environmental Protection Agency, Office of Water,
Office of Science and Technology, Engineering and Analysis Division, Economic and Statistical
Analysis Branch. The analysis was prepared by Eastern Research Group, Inc. (ERG), Lexington,
Massachusetts, under EPA contracts 68-CO-0080 and 68-C8-0084.

       ERG's project manager for this effort was Maureen F. Kaplan. Work on this report was
carried out by her and Eric M. Sigler. David Meyers served as expert reference and quality
control reviewer of the analytical content of the analysis. Mahesh Podar and Ann M. Watkins,
economists with the Economic and Statistical Analysis Branch, were the task managers.

-------

-------
                               TABLE OF CONTENTS
                                                                            PAGE
PREFACE     	..	.	._....	 i

LIST OF TABLES	xi

LIST OF FIGURES			xxvii

EXECUTIVE SUMMARY	......	,	ES-1

      ES.l   Background	ES-1
      ES.2   Description of Offshore Oil and Gas Industry	ES-2
      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.33 Treatment, Workover, and Completion Fluids	  ES-4
             ES.3.4 Produced Sand	,	...  ES-7
             ES.3.5 Miscellaneous Wastes	.,	ES-7
             ES.3.6 Sets of Selected Regulatory Options	ES-7
      ES.4   Economic Methodology Overview	  ES-7
      ES.5   Model Projects	 ES-10
      ES.6   Industry Activity Projections	»••			ES-10
      ES.7   Pollution Control Compliance Costs	 ES-12
      ES.8   Regulatory Impacts on Model Projects	ES-12
      ES.9   Regulatory Impacts on Oil and Gas Industry	ES-15
      ES.10  Regulatory Impacts on Production ....	ES-16
      ES.ll  Secondary Impacts of the Regulations	 ES-16
      ES.12  Impact on Small Businesses	ES-17


SECTION ONE     INTRODUCTION AND SUMMARY OF
                   REGULATORY OPTIONS	 1-1

      1.1    Introduction	 1-1
      1.2    Rulemaking History and Previous Analyses ...		 1-1
      1.3    Summary of Regulatory Options	 1-3
             1.3.1  Drilling Fluid and Drill Cuttings	 1-3
             132  Produced Water			— ... 1-5
             1.3.3  Treatment, Workover, and Completion Fluids	 1-8
             1.3.4  Produced Sand		...	 1-8
             1.3.5  Miscellaneous Wastes	 1-9
             1.3.6  Combinations of Selected Regulatory Options	1-9
                                        111

-------
r
                                           TABLE OF CONTENTS (cont.)
                                                                                                PAGE
              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			2-11
                     2.2    Offshore Oil and Gas Exploration 	2-11
                     2.3    Offshore Oil and Gas Development	  2-14
                           2.3.1   Development Logistics	  2-14
                           2.3.2   Inventory of Offshore Production Platforms	  2-17
                           2.33   Offshore Oil and Gas Production	  2-23
                     2.4    Support Activities		  2-26
                     2.5    Industry Downturn and Recovery 1986-1988	  2-30
                           2.5.1   Federal Offshore Leasing	  2-30
                           2.5.2   Exploration	  2-32
                           2.53   Production	,	2-36
                     2.6    References	  2-36


              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
                           3.23   Trends in Offshore Production Reserves  	  3-14
                           3.2.4   Financial Trends	  3-14
                           3.2.5   Increases in Industry Debt	  3-19
                     3.3    Financial Condition of Industry Segments  	  3-21
                           3.3.1   Ratios Used to Analyze Industry Segments	  3-21
                           3.3.2   Ratio Analysis of Major Integrated Companies	  3-23
                           3.33   Ratio Analysis of Independent Companies	  3-35
                     3.4    Financial Profiles of "Typical" Companies  	  3-40
                           3.4.1  Financial Profile of "Typical" Majors 	  3-41
                           3.4.2  Financial Profile of "Typical" Independents  	  3-45
                           3.43   Financial Comparisons Among "Typical" Oil Companies 	3-45
                     3.5    Current Financial Condition and Future Outlook	  3-55
                           3.5.1    1986 to Present	  3-55
                           3.5.2   Outlook	  3-57
                     3.6    References	  3-58
                                                        IV

-------
                             TABLE OF CONTENTS (cent)
                                                                              PAGE
 SECTION FOUR    STRUCTURES AND WELLS INCURRING COSTS	 4-1

       4.1    Existing Structures (BAT)			4-1
             4.1.1   Gulf of Mexico	4.2
             4.1.2   Pacific	 4-8
             4.1.3   Alaska	  4.12
             4.1.4   Summary	  4.12
       4.2    Projected Wells 	  ............  4-15
             4.2.1   Gulf of Mexico and Alaska  		„  4.15
             4.2.2   California	  4_24
             4.23   Atlantic	„  4.27
             4.2.4   Summary	  4_27
       4.3    Platform Projections, 15-year Period  	  4.33
             4.3.1   Total Platforms	  4.34
             4.32   Platforms Within and Beyond the 3-Mile and 4-Mile Boundaries ...  4-37
       4.4    References	4.59


SECTION FIVE      ECONOMIC METHODOLOGY  .. „	54

       5.1    Description  of the Economic Model	.....'	5-1
             5.1.1   Economic Model Overview 	•. „	  54
             5.12   Parameter Description	„	  5.2
             5.13   Model Calculation Procedures	5-4
             5.1.4   Interpretation of Model Results	5.5
       5.2    Construction of Regional Offshore Oil and Gas Projects ..-..-	5-8
             5.2.1   Overview	  5-8
             5.2.2   Description of the Offshore Oil and Gas Projects	5-8
             5.23   Results of Base Case Simulations - NSPS	  5-32
             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
       6.2    Produced Water	'	'.'.'.'.'.  6-5
             6.2.1  BAT Produced Water		................  6-5
             622  NSPS Produced Water	 6-18
       63    Treatment/Workover/Completion Fluids	 6-25
       6.4    Produced Sand	]" 6-27
       6.5    Combined Cost of Selected  Regulatory Options	 6-29
       6.6    References	 6 31

-------
                           TABLE OF CONTENTS (cont.)
                                                                          PAGE
SECTION SEVEN    IMPACTS ON REPRESENTATIVE FACILITIES 	7-1

      7.1    Drilling Fluids and Drill Cuttings	 7-1
      7.2    Produced Water  	 7-9
            7.2.1   Produced Water — BAT	7-9
            7.2.2   Produced Water — NSPS	  7-21
      7.3    Treatment/Workover/Completion Fluids	  7-25
      7.4    Produced Sand 	  7-26
      7.5    Combined Effects of Selected Regulatory Options	  7-26


SECTION EIGHT    IMPACTS ON REPRESENTATIVE COMPANIES 	8-1

      8.1    Methodology  	 8-1
      8.2    Drilling Fluids and Drill Cuttings 			 8-7
      8.3    Produced Water — BAT	  8-12
      8.4    Produced Water — NSPS	  8-18
      8.5    Treatment, Workover, and Completion Fluids  	  8-22
      8.6    Produced Sand	  8-22
      8.7    Combined Regulatory Packages	  8-30
      8.8    References	:	  8-34


SECTION NINE     IMPACTS ON PRODUCTION  	 9-1

      9.1    Methodology	 9-1
      9.2    Produced Water - BAT	,	9-2
      9.3    Produced Water - NSPS	 9-4
      9.4    Combined Effects of Selected Regulatory Options	9-4
      9.5    References				 9-4


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	;	,	  10-10
      10.4   Impacts on Service Industries	  10-14
      10.5   Impacts on Inflation	  10-15
      10.6   References	  10-15


SECTION ELEVEN   SMALL BUSINESS ANALYSIS	  11-1
                                       VI

-------
                           TABLE OF CONTENTS (cont.)
                                                                            PAGE
APPENDIX A       SELECTION OF OFFSHORE OIL AND GAS PROJECTS	. A-l

      A.1    General Parameter Categories	:	A-2
             A.1.1  Geographic Region  	A-2
             A.1.2  Number of Well Slots	A-5
             A.1.3  Type of Production	A-8
      A.2    Description of Model Projects	A-10
             A.2.1  Gulf of Mexico Model Projects	A-10
             A.2.2  Pacific Model Projects	A-13
             A.23  Alaskan Model Projects	A-16
      A.3    References	A-20


APPENDIX B       BASE CASE TIMING OF PROJECT DEVELOPMENT  	...... B-l

      B.I    Phases of Project Development	;. '.		;. B-l
      B.2    Duration of Project Development Phases	B-2
             B.2.1  Gulf of Mexico	B-2
             E.22  Pacific 	;.,	B-4
             B.2.3  Alaska	 B-9
      B.3    References	B-13


APPENDIX C       LEASE PRICES	,	.C-l

      C.I    Average Lease Cost Per Tract	C-l
      C.2    Discovery Efficiency „		C-3
      C3    Number of Platforms Per Discovery Well	C-7
      C.4    Ratio of Expected Production  	C-7
      C.5    References	C-8


APPENDIX D       EXPLORATION PHASE ASSUMPTIONS	D-l

      D.I    Geophysical and Geological Costs	D-l
      D.2    Discovery Efficiency	D-2
      D.3    Drilling Costs	;	D-2
      D.4    Number of Platforms Per Discovery Well	D-6
      D.5    References	D-6
                                       vu

-------
                            TABLE OF CONTENTS (cont)
                                                                            PAGE
APPENDIX E
DELINEATION PHASE ASSUMPTIONS 	E-l
      E.1    Cost Per Delineation Well	E-l
      E.2    Number of Delineation Wells Per Project  		E-l
      E.3    References	E-2


APPENDIX F       DEVELOPMENT PHASE ASSUMPTIONS	F-l

      F.I    Platform/Gravel Island Cost	F-l
      F.2    Lease Equipment Costs	F-2
      F3    Development Well Costs 	F-6
      F.4    Number of Production Wells Per Platform '.		F-6
      F.5    Rate of Installation of Development Wells  	F-6
      F.6    References	...	F-10


APPENDIX G       PRODUCTION/OPERATION PHASE ASSUMPTIONS 	G-l

      G.I    Peak Production Rates	G-l
             G.1.1  Gulf of Mexico	G-2
             G.1.2  Pacific	G-4
             G.L3  Alaska	G-4
      G.2    Production Decline Rate 	G-7
      G.3    Years at Peak Production	G-12
      G.4    Operation and Maintenance Costs (O&M)  	G-12
      G.5    References	G-19


APPENDIX H       PRODUCED WATER ASSUMPTIONS 	.H-l

      H.1    Modeling Assumptions	H-l
             H.1.1  Projects with Oil Production  	H-l
             H.1.2  Projects with Gas-Only Production	H-2
      H.2    Peak Water Production  	H-8
             H.2.1  Projects with Oil Production  	H-8
             H.2.2  Projects with Gas-Only Production	H-8
      H3    Average Water Production	H-ll
             H.3.1  Projects with Oil Production	H-ll
             H3.2  Projects with Gas-Only Production	H-ll
      H.4    Total Annual Water Production	H-13
             H.4.1  Existing Structures (BAT)	 H-13
             H.4.2  Projected Structures (NSPS)  	H-19
                                       vui

-------
                            TABLE OF CONTENTS (cont.)

                                                                               PAGE


       H.5   References	...!...	H-19


APPENDIX I        BASE CASE FINANCIAL ASSUMPTIONS AND RATES	  1-1

       I.I    Incremental Impact of Model Project on Corporate Income Tax Rate	  1-1
       1.2    Severance Taxes	  1-1
       1.3    Royalty Rates	  1-4
       1.4    Rental Payments	•.	  1-4
       1.5    Depreciation	  1-5
       1.6    Basis for Depreciation	  1-5
       1.7    Capitalized Costs	  1-6
       1.8    Inflation Rate	  1-6
       1.9    Escalation of General Project Costs in Real Terms	  1-7
       1.10   Oil Depletion Allowance		  1-7
       1.11   Salvage	  1-8
       1.12   Investment Tax Credit			  1-8
       1.13   Windfall Profits Tax	  1-9
       1.14   Discount Rate	  1-9
       1.15   References	1-10


APPENDIX J        ERG ECONOMIC MODEL FOR OFFSHORE
                    PETROLEUM PRODUCTION  		  J-l

       J.I    Introduction	  J-l
             J.1.1   Model Phases	J-l
             J.1.2   Economic Overview of the Model	J-2
       J.2    Step-By-Step Description of the Model	J-5
             J.2.1   Phase One - Leasing	  J-5
             J.2.2   Phase Two - Exploration	  J-5
             J.2.3   Phase Three - Delineation	  J-10
             J.2.4   Phase Four - Development	  J-12
             J.2.5   Phase Five - Production	  J-13
             J.2.6   Summary Statistics	  J-19
                                         IX

-------

-------
LIST OF TABLES

ES-1
ES-2
ES-3
ES-4

ES-5
ES-6

1-1
1-2
1-3
2-1

2-2.
2-3

2-4

2-5
2-6
2-7

2-8
2-9

2-10

Produced Water BAT Regulatory Options 	 	 	
Produced Water NSPS Regulatory Options 	 	 	 	 	 	 	
Selected Sets of Regulatory Options 	 , 	 	 	
Distribution of Oil, Oil/Gas, and Gas Producing 	 	 	 	
Platforms by Region and Size
Combined Cost of Selected Regulatory Packages 	 	 	
Combined Impacts on Typical Gulf 12 Well Project 	 	
Gulf of Mexico
Produced Water BAT Regulatory Options 	 	 	 —
Produced Water NSPS Regulatory Options 	 	 	
Regulatory Packages 	 	 	
Outer Continental Shelf (OCS) Federal Lease 	 	 	
Statistics, 1954-1990
OCS Leasing Statistics, 1980-1990 	
Total Royalty Revenues by Commodity and Year From All 	 	 	
Offshore Federal Leases, 1953-1990
Total OCS Federal Offehore Leasing Summary, 1980-1990 For 	
All Regions
Summary of State Offshore Lease Terms ....... 	 	 	
Historical and Planned State Offshore Leasing Activities 	
Total Offshore Exploratory Drilling in the United States 	 	
Federal and State Leases Alltime to January 1, 1992
Federal Waters Inventory of Producing Platforms 	
State Waters Inventory of Offshore Structures 	
and Producing Wells
Pacific Offshore Structures 	 	 	
Page
ES-5
ES-6
JES-8
.... ES-11

ES-13
	 ES-14

	 1-6
, 	 	 1-7
. . 	 1-10
, 	 .2-3

	 2-6
	 2-8

	 	 2-10

	 2-12
	 .. 2-13
	 2-15

	 2-18
	 2-20

	 2-22
      -XI-

-------
                        LIST OF TABLES (cont)

2-11

2-12
2-13
2-14
2-15
2-16
2-17
3-1

3-2

3-3

3-4

3-5

3-6

3-7
3-8
3-9
3-10

Production and Value of U.S. Grade Oil and Condensate, 	
Onshore-Offshore
Production and Value of U.S. Natural Gas, Onshore-Offshore 	
Support Activities 	
Offshore Drilling Activity, 1980-1990 	
Crude Oil Prices, 1980-1990 	
Frve-Year OCS Leasing Plan (1992-1997) 	
Annual Average Number of Active Mobile Offshore Drilling Rigs 	
U.S. Oil Companies Engaged in Offshore Exploration, 	
Development, and Production
Sample of Companies Providing Support Services to Offshore 	
Developers in 1986
Oil Industry Concentration Ratios: Offshore Activities 	 ;........
and U.S. Activities
Total U.S. Petroleum Demand, U.S. Average Crude Oil Wellhead ......
Price, 1975-1986
Total U.S. Natural Gas Demand, U.S. Average Natural Gas 	
Wellhead Price, 1975-1986
Trends in Capital and Exploration Expenditures (United 	
States, 1974-1984)
Offshore Wells Drilled and Drilling Costs 1975-1985 	
Dollar Value of Annual Oil and Gas Production 1980-1990 	
Financial Trends for 25 Major Petroleum Companies (1973-1985) 	
Financial Statistics for 26 Large U.S. Oil Companies 	
Page
	 2-24

	 2-25
	 2-27
	 2-28
	 	 2-31
	 2-33
	 2-34
	 3-3

	 3-4

	 3-7

...... 3-9

	 3-10

	 3-12

	 3-13
	 3-15
, , , . 3-16
	 3-18
(1980-1986)
                                -xii-

-------
LIST OF TABLES (cent.)

3-11

3-12

3-13

3-14

3-15

3-16

3-17

3-18

3-19

3-20

3-21

3-22

3-23

3-24
3-25

Debt/Capital Ratios (%) For Major Integrated and Independent 	
Companies
Return on Equity (%) Major Integrated Oil Companies: 	
19 Company Group (1977-1985)
Return on Equity (%) Comparison of Average Yields For Three 	
Samples of Major Integrated Oil Companies (1977-1986)
Return on Assets (%) Major Integrated Oil Companies: 	
19 Company EPA Group (1977-1985)
Return on Assets (%) Comparison of Average Yield for 4 Samples 	
of Major Companies (1977-1986)
Current Ratio Major Integrated Oil Companies: 19-Company 	 ,
EPA Group (1977-1985)
Current Ratio Comparison of Average Yields for 4 Samples 	
of Major Integrated Oil Companies (1977-1985)
Debt/Capital Ratio (%) Major Integrated Oil Companies in 	
19-Company EPA Group (1977-1985)
Return on Equity (%) Independent Oil Companies in ...
EPA 17 -Company Sample
Return on Equity (%) Independent Oil Companies in EPA . .
17-Company Sample
Return on Assets (%) Independent Oil Companies in EPA .
17-Company Sample
Current Ratio Independent Oil Companies in EPA 	
17-Company Sample
Debt/Capital Ratio (%) Independent Oil Companies in EPA
17-Company Sample
Balance Sheet for a "Typical" Major Integrated Oil Company . .
Income Statement for a "Typical" Major Integrated Oil Company
Page
	 3-20

	 .3-24

	 3-25

3-27

	 3-28

	 3-29

3-30

3-32

. . . . . 3-34

3-36

	 3-37

	 3-38

	 3-39

	 3-42
, . . , 3-43
        -X11I-

-------
                               LIST OF TABLES (cent.)
                                                                                age
                                                                               3-44
3-26

3-27
3-28
3-29

3-30

3-31
3-32
3-33

4-1
4-2

4-3

4-4
Financial Ratio and Performance indicators ror a lypicai 	
Major Integrated Oil Company
Balance Sheet for a 'Typical" Independent Oil Company 	
Income Statement for a 'Typical" Independent Oil Company 	
Financial Ratio and Performance Indicators for a "Typical" 	
Independent Oil Company
Profitability Comparisons Between "Typical" Offchore Oil 	
Companies
liquidity Comparisons Between Typical" Offshore Oil Companies . 	
Leverage Comparisons Between Typical" Offehore Oil Companies ...'..
Growth and Spending Comparisons Between "Typical" Offshore 	
Oil Companies
Summary of Well Data Gulf of Mexico State Waters 	 	 	
Summary of Platforms in Gulf of Mexico State Waters 	
Structures Estimated to Bear Costs
Summary of Platforms in Gulf of Mexico State Waters 	
' Structures Estimated to Bear Costs
Identification of Structures Estimated to Bear Increased 	


3-46
3-47
3-48

3-49

3-51
3-52
3-54

.t 	 4-5
	 .. 4-6

	 4-7

	 4-9
4-5


4-6


4-7
Pollution Control Costs Minerals Management Service Platform
Inspection System Complex/Structure Data Base March 1988

Structures Estimated to Bear Increased Pollution Control Costs
Federal Waters - Gulf of Mexico Region
BAT Structures in California Waters, Location by Distance
From Shore and Water Depth
BAT Structures in Offehore Waters All Structures Estimated .
to Bear Increased Pollution Control Costs Based on 3 Nautical
Mile Boundary
                                                                                4-10
4-11
4-13
                                          -xiv-

-------
                                LIST OF TABLES (cent)
                                                                                Page
4-8     BAT Structures in Offshore Waters, All Structures Estimated  	4-14
        to Bear Increased Pollution Control Costs Based on 4 Nautical
        Mile Boundary

4-9     MMS Federal OCS Model Outputs - Total 1993,1995, and	4-18
        2000 Production ($21/bbl of Oil -1986 Dollars)

4-10    OCS Production from Pre-1986 Sources ($32/bbl of Oil -1986 Dollars)	4-20

4-11    OCS Production from 1986 and Later Sources ($21/bbl of Oil -1986 Dollars) ..  4-22

4-12    1986 and Later NSPS Production ($21/bbl of Oil - 1986 Dollars)	4-23

4-13    Production Well Projections, 15 Year Period, Gulf of Mexico and Alaska   ....  4-25
        ($21/bbl of Oil -1986 Dollars)

4-14    Actual Drilling Rates for the Pacific - 1986-1989   			4-28

4-15    Breakdown of Pacific BAT Wells '.	4-29

4-16    Average Annual Number of Wells Drilled, BAT and NSPS	  4-3L
        ($21/bbl Scenario) 15 Year Period

4-17    Offshore Exploratory Efforts  	4-32

4-18    Estimated Productive BAT Wells in the Gulf of Mexico 			4-34

4-19    Summary of BAT and NSPW Wells by Region 	4-35

4-20    Platform Configuration Summary	,	,...  4-36

4-21    Platform Projections - Total All Projects ($21/bbl of Oil -1986 Dollars)	4-38

4-22    Platform Projections - Within 3 Miles  	4-39
        ($21/bbl of Oil-1986 Dollars) (All Projects)

4-23    Platform Projections - Within 3 Miles  	,	4-41
        ($21/bbl of Oil-1986 Dollars) (Oil Producing Projects)

4-24    Platform Projections - Within 4 Miles  	4-44
        ($21/bbl of Oil-1986 Dollars) (All Projects)
                                          -xv-

-------
                                LIST OF TABLES (cent.)
4-25    Platform Projections - Within 4 Miles ($21/bbl of Oil-	4-46
        1986 Dollars) (Oil Producing Projects)

4-26    Total Projected NSPS Structures 15 Year Period  	4-48
        Three Mile Boundary

4-27    Total Projected NSPS Structures 15 Year Period  	4-49
        Four Mile Boundary

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

5-5     Baseline Parameters for Pacific Projects	 5-13

5-6     Baseline Parameters for Alaska Projects  	5-14

5-7     Lease Prices for Model Projects	5-16

5-8     Total Exploratory Offshore Wells Drilled to January 1,1985	 5-17

5-9     Average Well Depths and Costs -1986 Data	5-18

5-10    Lease Equipment Costs - Gulf and Pacific Regions	5-19

5-11    Lease Equipment Costs for Alaska Projects	;.	 5-21

5-12    Development Well Cost - 1986 Data	5-22

5-13    Peak Offshore Per-Well Production Rates	5-23

5-14    Production Decline Rates	5-24

5-15    Operating Costs for Gulf of Mexico Platforms	 5-25

5-16    Operating Costs for Pacific and Cook Inlet Platforms	 5-27

                                          -xvi-

-------
                                 LIST OF TABLES (cont.)
                                                                                 Page
5-17    Operation and Maintenance Costs for Alaska Projects	;	5-28

5-18    Crude Oil Prices, 1980 to November 1987	5,29

5-19    Wellhead Prices and Regional Relationships -1985 Data	5-30

5-20    Relationship of Domestic Oil and Gas Prices - 1982-1987  	5-31

5-21    Baseline Financial Summary Statistics, NSPS Projects	5-33
        with Oil Production

5-22    Baseline Financial Summary Statistics, NSPS Projects  	5-34
        with Gas-Only Production

5-23    Baseline Financial Summary Statistics, BAT Projects	5-37
        with Oil Production

5-24    Baseline Financial Summary Statistics, BAT Projects	5-38
        with Gas-Only Production                  .                     ~

6-1     Summary of Current Requirements for Drilling Fluids	6-2

6-2     NSPS Drilling Fluids and Drill Cuttings, Summary of Costs	6-4

6-3     Produced Water, BAT Regulatory Options	  ... 6-8

6-4     BAT Per-project Incremental Pollution Control Costs, Oil		6-11
        and Gas Platforms, Gulf of Mexico

6-5     BAT Per-project Incremental Pollution Control Costs, Oil	6-12
        and Gas Platforms, Gulf of Mexico

6-6     BAT Per-project Incremental Pollution Control Costs, Gas-only  	6-13
        Platforms, Gulf of Mexico

6-7     BAT Per-project Incremental Pollution Control Costs,	6-14
        Oil-only Platforms, Gulf of Mexico

6-8     BAT Per-project Incremental Pollution Control Cost	6-15
        Oil-only Platforms, Gulf of Mexico

6-9     BAT Per-project Incremental Pollution Control Costs	6-16
        Oil and Gas and Gas-only Platforms, Pacific

                                          -xvii-

-------
                                LIST OF TABLES (cont.)
                                                                                  age
6-10    Total Costs of BAT Produced Water Options	6-17

6-11    Produced Water NSPS Regulatory Options  	6-19

6-12    NSPS Per-project Incremental Pollution Control Costs	6-20
        Oil and Gas Projects

6-13    NSPS Per-project Incremental Pollution Control Costs 	6-21
        Gas-only Platforms

6-14    NSPS Per-project Incremental Pollution Control Costs 	6-22
        Oil-only Projects

6-15    Total Costs of NSPS Produced Water Options	6-24

6-16    Summary of Treatment, Workover, and Completion Fluid Costs	6-26

6-17    Produced Sand Disposal Costs	<.	6-28

6-18    Combined Cost of Selected Regulatory Packages	.	,	 6-30

7-1     Pollution Control Options for Drilling Fluids and Drill	:.		7-3
        Cuttings, Model Project Impacts, Oil and Gas Platforms,
        Gulf of Mexico

7-2     Pollution Control Options for Drilling Fluids and Drill	 7-4
        Cuttings, Model Project Impacts, Oil and Gas Platforms
        Pacific

7-3     Pollution Control Options for Drilling Fluids and Drill	'.	 7-5
        Cuttings, Model Project Impacts, Oil and Gas Platforms and
        Oil-only Platforms, Alaska

7-4     Pollution Control Options for Drilling Fluids and Drill		7-6
        Cuttings, Model Project Impacts, Gas-only Platforms
        Gulf of Mexico


7-5     Pollution Control Options for Drilling Fluids and Drill	7-7
        Cuttings, Model Project Impacts, Gas-Only Platforms,
        Pacific  and Alaska
                                          -XVIII-

-------
                               LIST OF TABLES (cont.)
                                                                              Page
7-6    BAT Pollution Control Options for Produced Water	7-11
       Model Project Impacts, Oil and Gas Platforms,
       Gulf of Mexico

7-7    BAT Pollution Control Options for Produced Water	  7-12
       Model Project Impacts, Oil and Gas Platforms
       Gulf of Mexico

7-8    BAT Pollution Control Options for Produced Water		7-13
       Model Project Impacts, Oil and Gas Platforms
       Gulf of Mexico

7-9    BAT Pollution Control Options and Produced Water	7-14
       Model Project Impacts, Gas-only Platforms
       Gulf of Mexico

7-10   BAT Pollution Control Options and Produced Water	  7-15
       Model Project Impacts, Gas-only Platforms
       Gulf of Mexico

7-11   BAT Pollution Control Options and Produced Water ,	7-16
       Model Project Impacts, Oil-only Platforms
       Gulf of Mexico

7-12   BAT Pollution Control Options and Produced Water	  7-17
       Model Project Impacts, Oil-only Platforms
       Gulf of Mexico

7-13   BAT Pollution Control Options and Produced Water	7-18
       Model Project Impacts, Oil-only Platforms
       Gulf of Mexico

7-14   BAT Pollution Control Options and Produced Water 	7-19
       Model Project Impacts, Oil and Gas Platforms
       Pacific

7-15   NSPS Pollution Control Options for Produced Water	7-22
       Model Project Impacts, Oil and Gas Platforms
       Gulf of Mexico
                                         -xix-

-------
                                LIST OF TABLES (cent.)
7-16    NSPS Pollution Control Options for Produced Water  	7-23
        Model Project Impacts
        Alaska

7-17    NSPS Pollution Control Options for Produced Water  	7-24
        Model Project Impacts, Gas-Only Platforms
        Gulf of Mexico

7-18    Pollution Control of Treatment and Workover Fluids	 7-27
        BAT Model Project Impacts
        Gulf of Mexico

7-19    Pollution Control of Treatment, Workover., and Completion  	7-28
        Fluids, NSPS Model Project Impacts
        Gulf of Mexico

7-20    Pollution Control of Produced Sand, BAT Model Project Impacts	 7-29
        Gulf of Mexico, Oil and Gas Projects

7-21    Pollution Control of Produced Sand, BAT Model Project Impacts	 7-30
        Gulf of Mexico, Oil-only Projects

7-22    Pollution Control of Produced Sand, BAT Model Project Impacts		 7-31
        Pacific,  Oil and Gas Projects

7-23    Pollution Control of Produced Sand, NSPS Model Project Impacts	 7-32
        Gulf of Mexico, Oil and Gas Projects

7-24    Pollution Control of Produced Sand, NSPS Model Project Impacts	 7-33
        Pacific and Alaska

7-25    BAT Pollution Control Options for Produced Water, TWC Fluids	 7-34
        and Produced Sand, Impacts on Selected Projects
        Gulf of Mexico

7-26    NSPS Pollution Control Options for Produced Water, Drill Cuttings,  	7-37
        Drilling Fluids, Treatment, Workover, and Completion Fluids, and
        Produced Sand, Impacts on Selected Projects
        Gulf of Mexico

8-1     Oil Production, Reported in Barrels for 98 Ranking	8-3
        OCS Operators in 1989
                                         -xx-

-------
                               LIST OF TABLES (cont)
                                                                               Page
8-2    Oil Producers in the OCS Region  	:	8-6

8-3    Annual Cost of Pollution Control Options, Drilling Fluids  	8-8
       and Drill Cuttings

8-4    Effluent Guidelines Impacts on Typical Major Oil Company	8-9
       Compliance Costs Financed by Working Capital, Drilling
       Fluids and Drill Cuttings

8-5    Effluent Guidelines Impacts on Typical Major Oil Company	8-10
       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  	8-11
       of Effluent Guidelines Regulations, Drilling Fluids and
       Drill Cuttings

8-7    Effluent Guidelines Impacts on Typical Independent Oil Company	 8-13
       Compliance Costs Financed by Working Capital, Drilling
       Fluids and Drill Cuttings

8-8    Effluent Guidelines Impacts on Typical Independent Oil Company	8-14
       Compliance Costs Financed by Long-Term Debt, Drilling
       Fluids and Drill Cuttings

8-9    Changes in Financial Ratios for a Typical Independent as a		8-15
       Result of Effluent Guidelines Regulations, Drilling Fluids
       and Drill Cuttings

8-10   Annual Cost of Pollution Control Options, BAT Produced Water	8-16

8-11   Changes in Financial Ratios for a Typical Major as a	8-17
       Result of Effluent Guidelines Regulations, BAT Produced
       Water

8-12   Changes in Financial Ratios for a Typical Independent as a	8-19
       Result of Effluent Guidelines Regulations, BAT Produced
       Water

8-13   Annual Cost of Pollution Control Options, NSPS Produced	8-20
       Water
                                          -XXI-

-------
                               LIST OF TABLES (conk)
8-14   Changes in Financial Ratios for a Typical Major as a	8-21
       Result of Effluent Guidelines Regulations, NSPS Produced
       Water

8-15   Changes in Financial Ratios for a Typical Independent as a	8-23
       Result of Effluent Guidelines Regulations, NSPS Produced
       Water

8-16   Annual Cost of Pollution Control Options, BAT and NSPS	8-24
       Treatment, Workover, and Completion Fluids

8-17   Changes in Financial Ratios for a Typical Major as a	 8-25
       Result of Effluent Guidelines Regulations, BAT and NSPS
     '  Treatment, Workover, and Completion Fluids

8-18   Changes in Financial Ratios for a Typical Independent as a	 8-26
       Result of Effluent Guidelines Regulations, BAT and NSPS
       Treatment, Workover, and Completion Fluids            .

8-19   Annual Cost of Pollution Control Options	 8-27
       BAT and NSPS Produced Sand

8-20   Changes in Financial Ratios for a Typical Major as a Result of	 8-28
       Effluent Guidelines Regulations, BAT and NSPS Produced Sand

8-21   Changes in Financial Ratios for a Typical Independent as a	*	.. 8-29
       Result of Effluent Guidelines Regulations, BAT and NSPS
       Produced Sand

8-22   Annual Cost of Pollution Control Options, Combined Regulatory	 8-31
       Packages

8-23   Changes in Financial Ratios for a Typical Major as a Result	 8-32
       of Effluent Guidelines Regulations, Combined Regulatory Packages

8-24   Changes in Financial Ratios for a Typical Independent as a  	8-33
       Result of Effluent Guidelines Regulations, Combined Regulatory
       Packages

9-1    Cumulative Potential Loss of Production, BAT Produced Water	  9-3

9-2    Cumulative Potential Loss of Production, NSPS Produced  Water  	..;.....  9-5
                                        -XXII-

-------
LIST OF TABLES (cont.)
9-3
9-4

10-1

10-2

10-3
10-4
10-5
10-6
10-7

10-8
A-l

A-2
A-3

A-4

A-5
A-6
A-7
A-8
Regulatory Packages 	 • 	 • 	
Cumulative Potential Loss of Production, Impacts of Combined 	
Regulatory Packages
Ratio of Federal-to-State Production, Projected Productive 	 .,
Development Wells in Offshore Region
Potential Loss of Federal Revenues, Impacts of Combined 	
Regulatory Packages
Recent OCS Lease Bonuses Paid 	 •
Potential Impact of Compliance Costs on State Revenues 	
Potential Impact of Compliance Costs on Texas State Revenues 	
Total Texas State Revenues and Bonus Revenues 	 . 	
Potential Impact of Compliance Costs on Louisiana State 	
Revenues
Total Louisiana State Revenues and Bonus Revenues 	
Number of Structures by the Number of Wellslots Available, ..... 	
Gulf of Mexico, March 1988
Number of Wellslots on Pacific OCS Platforms 	 	 	
Distribution of Oil, Oil/Gas, and Gas Producing Platforms 	 	
by Region and Size
Sample 12-Well Structures Used in Selecting 12-Well Model 	
Project
Sample Structures Used in Selecting 24-Well Model Project 	 	
Sample Structures Used in Selecting 40-Well Model Project . . . . 	
Project Descriptions, Gulf of Mexico 	 	
Project Descriptions, Pacific Region 	
	 9-6
	 9-7
-
	 10-3

	 10-4

	 10-6
	 10-8
	 	 	 10-9
10-11
	 10-12

10-13
	 	 A-6

	 A-7
	 A-9

	 	 A-ll

	 A-12
	 A-14
	 A-15
	 A-17
          -XXlll-

-------
                                LIST OF TABLES (cent)
                                                                                age
A-9    Platforms in Cook Inlet		A-18



A-10    Project Descriptions, Alaska	A-21



B-I     Project Timing, Gulf of Mexico  	,	B-5



B-2     Project Timing for Recent Pacific Coast Platforms	B-7



B-3     Project Timing, Pacific Region		B-10



B-4     Project Timing, Alaska		B-14



C-l     Gulf of Mexico Lease Prices  	1	C-2



C-2     Pacific Lease Prices	..;... C-4



C-3     Alaska Lease Prices	C-5



C-4     Total Exploratory Offshore Wells Drilled to January 1,1985	C-6



C-5     Lease Prices for Model Projects	C-9



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



E-l     Number of Delineation Wells  for Typical Offshore Projects	E-3



F-l     Lease Equipment Costs - Gulf and Pacific	F-3



F-2     Lease Equipment Costs for Alaska Projects	F-5



F-3     Average Well Depths and Costs - 1986 Data	F-7



F-4     Total Development Offshore Wells Drilled to January 1,1985	F-8



F-5     Development Well Cost -1986 Data	F-9



G-l     Cumulative Production Per Well - Gulf of Mexico Assumptions  	  G-3



G-2     Peak Production Rates - California  	  G-5



                                         -xxiv-

-------
                                LIST OF TABLES (cont)
G-3

G-4


G-5

G-6

G-7

G-8

G-9


G-10


G-ll

G-12

G-13

G-14


G-15

H-l

H-2

H-3

H-4
1986 Gas to Oil Ratios - California
Average First-Year Production for Oil Wells in Cook Inlet,.
Alaska

Initial Production from Endicott Field, Beaufort Sea, Alaska

Engineering Estimate of Peak Production Rates - Alaska  ..

Peak Offshore Per-Well Production Rates	

Production Decline Rates	
1986 Operation and Maintenance Costs for Gulf of Mexico
Platforms
Annual Operating Costs - 12-Slot Platform in Gulf of Mexico
100 Foot Water Depth (1986 Dollars)
Labor Assumptions for Small Gulf Projects	

Operating Costs for Gulf of Mexico Platforms	

Operating Costs for Pacific and Cook Inlet Platforms
Ratio of 1986 Operation and Maintenance Costs - California
and Gulf Coast
Operation and Maintenance Costs for Alaska Projects	

Initial Watercut - Alaska	'.	

Offshore WatenGas Ratios - California	

Water Production Estimates - Gulf of Mexico	

Peak Water Production Rates - Existing and Projected Structures
H-5    Average Annual Water Production Rates - Existing and
        Projected Structures
  G-6

  G-8


  G-9

 G-10

 G-ll

 G-13

 G-15


 G-16


 G-18

 G-20

 G-21

 G-22


 G-23

.  H-4

.  H-7

.  H-9

 H-10


 H-12
                                          -XXV-

-------
                               LIST OF TABLES (cont)
                                                                              Page
H-6    BAT Structures in Offshore Waters		 H-14
        Based on 4 Nautical Mile Cut-off

H-7    Estimated Average Annual Produced Water Generated by Projects	 H-15
        in the  Gulf of Mexico

H-8    Estimated Average Annual Produced Water Generated by	 H-18
        Pacific Projects

H-9    NSPS  Structure Allocations ($21 bbl/Scenario)	 H-20

H-10    Estimated Average Annual NSPS Water Production,	 H-21
        $21/bbl Restricted Development Scenario

1-1     Twenty-Year Averages for Risk-Free, Corporate Borrowing,	 1-11
        and'Inflation Rates

1-2     Debt/Capital Ratio (%) Major Integrated Oil Companies in 	 1-12
        19 Company EPA Group

1-3     Cost of Capital Calculations	 1-13

J-l     Effect  of Tax and Accounting Systems on Cash Flows 	.....;,	J-4

J-2     Exogenous Variables Provided to EPA Economic Model		 J-6

J-3     -Cost and Cash Flow Uses in the Model	 J-21
                                        -xxvi-

-------
                                  LIST OF FIGURES
ES-1   Economic Methodology Overview	ES'9

2-1    Offshore Mobile Rig Utilization Data, Gulf of Mexico,	2-35
       1983-1988

5-1    General Schematic Diagram of ERG Economic Model  	5-3

6-1    Summary of Cost Allocation for Gulf of Mexico	6-10
       BAT Structure Flotation Technology

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-6

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-ll

B-5     Alaska Region:  Time from Lease Sale to First Spud Date 	B-12

G-l    North Cook Inlet Field, Alaska:  Gas Production	„	   G-14

H-l    Water: Oil Relationship	• • •	  H'3

H-2    Water and Gas Production from North Cook Inlet Field, Alaska	  H-6
                                          xxvn

-------

-------
EXECUTIVE SUMMARY
ES.1 BACKGROUND

EPA proposed effluent limitations guidelines and standards for the offishore 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. On November 26,1990, and March 13,1991, the Agency reproposed effluent
limitations guidelines and standards for both drilling and production wastes. This economic
impact analysis (EIA) is in support of the promulgation of final effluent limitations guidelines
and standards for the offshore oil and gas industry.

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. The production of oil and gas results in the generation, separation, and
discharge of waters and sand associated with hydrocarbons in the subsea reservoirs (i.e.,
produced waters and produced sand, respectively). When a well has reached its final depth, a
determination of its productive capability is made. If the well is not dry or uneconomical, it will
be completed as a productive well. During this process, fluids are pumped down the well bore,
both to clean it and to maintain sufficient pressure to prevent formation fluids from coming up
the hole until the blow-out preventer, valves, and other parts of the Christmas tree assembly are
installed. Once in production, a well is treated or worked over on a periodic basis to keep the
wellbore clear and to maintain production. Fluids associated with these operations are called
treatment, workover, and completion fluids. Other effluents regulated in this promulgation
include deck drainage, domestic wastes and sanitary wastes.
ES-1

-------
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 some regions 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 15 percent of United
states oil production and 30 percent of natural gas production in 1990.
ES3 OVERVIEW OF REGULATORY APPROACHES

ES.3.1 Drilling Fluids and Drill Cuttings

Four 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 diesel oil.
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 in the stock barite.
Zero discharge of drilling fluids and drill cuttings based on distance from shore.
The technology basis for the zero discharge requirement is onshore treatment
and/or disposal.
*State waters in Texas and Florida (on its Gulf coast only) include areas within 3 leagues, or
about 10.4 statute miles, from shore.
ES-2

-------
These requirements have been combined into four options:
              3 Mile Gulf California — For all regions except Alaska, drilling wastes from wells
              located within three miles of shore must meet zero discharge requirements.  In
              these regions, the disposal of drilling wastes from wells located beyond three miles
              of shore must meet limitations on toxicity, no discharge of diesel oil, no discharge
              of free oil as determined by the static sheen test, and limitations on mercury (1
              mg/kg) and cadmium (3 mg/kg) content in the stock barite. Alaska is excluded
              from the zero discharge requirement, but all discharges must meet the
              requirements for toxicity, free oil, diesel oil, cadmium, and mercury.

              8 Mile Gulff 3 Mile California — Zero discharge for all wells in the Gulf of
              Mexico located within eight miles from shore and zero discharge for all wells
              offshore California located  within three miles of shore. All wells located beyond
              eight miles of shore in the Gulf of Mexico, beyond three miles of shore off
              California, and all wells drilled offshore Alaska permitted to discharge  drilling
              fluids and drill cuttings that are in compliance with the requirements for toxicity,
              free oil, diesel oil, cadmium, and mercury.

              Zero Discharge GuIffCalifornia — Zero discharge for all wells located in the Gulf
              of Mexico and offshore California. All wells being drilled offshore Alaska
              permitted to discharge drilling fluids and drill cuttings that are in compliance with
              the requirements for toxicity, free oil, diesel oil, cadmium,  and mercury.

              4 Mile Gulf California — The requirements are the same as in the 3 Mile
              Gulf/California option, except that the boundary determining the zero discharge
              requirement is set at 4 miles from shore. This option is comparable to the
              preferred option in the March 1991  proposal.
       ES.3.2 Produced Water
       Three disposal technologies are considered for produced water:


       •      Zero discharge of produced water (technologically based on reinjection).

       •      Filtration of produced water prior to discharge. The costs and removals for this
              alternative are based on updated information for granular filtration.

       •      Improved performance of gas flotation.
                                           ES-3

-------
Five disposal options are considered in the economic impact for BAT and NSPS produced water
regulations. The options for BAT are summarized in Table ES-1, while those for NSPS are
listed in Table ES-2. BAT options are distinguished by the exclusion of existing Gulf of Mexico
single-well structures with their own production equipment from zero discharge requirements;
these structures must meet flotation limitations. No exclusion from zero discharge requirements
is made under NSPS for these structures. The BAT Flotation All option includes costs for two
years of monitoring for radium in produced water, however, no monitoring requirement is
included in the BAT limitation. The monitoring costs are included in the economic impact
analysis to evaluate the effects should EPA seek this information through monitoring
requirements imposed in general permits. The NSPS Flotation All option includes no costs for
radium monitoring. BAT and NSPS options for Alaska are distinguished in the costing efforts
because existing offshore Alaskan structures (BAT) are already required to meet zero discharge
requirements by state permit conditions (so they will incur no BAT costs), but costs for projected
structures in Alaskan waters are included in the calculation of NSPS costs. The limitations for
Alaska, however, are the same under BAT and NSPS. All existing structures off California
(BAT) are excluded from meeting zero discharge requirements and instead must comply with
improved gas flotation limitations.
ES33
Treatment, Workover, and Completion Fluids
Treatment, workover, and completion fluids must meet the same limitations on oil and
grease as established for produced water (BAT and NSPS). The technology basis for this
limitation is commingling and treating the treatment, completion, and workover fluids with the
produced water wastestream. Those facilities unable to commingle without causing a treatment
system upset could comply by transporting the fluids to shore for recycling and reuse, where
appropriate, or disposal.
ES-4

-------
                                      TABLE ES-1

                                 PRODUCED WATER
                             BAT REGULATORY OPTIONS
Regulatory Option
Short Form of Title
BPT - All Structures

Improved Gas Flotation - All Structures

Filter (Granular) and Discharge
- All Structures Within 4 Miles
BPT - All Structures
Beyond 4 Miles

Gulf of Mexico
Zero Discharge Within 3 Miles
(Gulf Ib Structures = Flotation)
Flotation Beyond 3 Miles
California: Flotation - All Structures

Gulf of Mexico
Zero Discharge
(Gulf Ib Structures = Flotation)
California: Flotation - All Structures
BPT All

Flotation All

Filter 4 Miles
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
                                         ES-5

-------
                                     TABLE ES-2

                                 PRODUCED WATER
                            NSPS REGULATORY OPTIONS
Regulatory Option
Short Form of Title
BPT - All Structures

Improved Gas Flotation
- All Structures

Filter (Granular) and Discharge
All Structures Within 4 Miles
BPT - All Structures Beyond 4 Miles

Gulf of Mexico and Alaska
Zero Discharge Within 3 Miles
Flotation Beyond 3 Miles
California: Flotation - All Structures

Gulf of Mexico and Alaska
Zero Discharge - All Structures
California: Flotation - All Structures
BPT All

Flotation All


Filter 4 Miles



Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
                                        ES-6

-------
       ES.3.4 Produced Sand

       Produced sand consists of the slurried particles used in hydraulic fracturing and the
accumulated formation sands and other particles (including scale) generated during production.
This waste stream also includes sludges generated in the produced water system, such as tank
bottoms from oil/water separators and solids removed in filtration.  The options considered in
this analysis are BPT and the zero discharge of all produced sand.
       ES.3.5 Miscellaneous Wastes

       The rulemaking effort also establishes limitations on deck drainage, domestic wastes, and
sanitary wastes. Since the BCT, BAT, and NSPS limitations selected for miscellaneous waste
streams already apply in either existing BPT effluent guidelines, NPDES permits, or Coast Guard
regulations, there are no incremental costs.  As such, they are not considered further in this
analysis.
       ES.3.6 Sets of Selected Regulatory Options

       The Agency selected two regulatory "packages" for more detailed analysis of the
economic impacts of the combined costs on typical companies, future oil and gas production,
federal revenues, state revenues, and other parameters.  The packages are presented in Table
ES-3.
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.
                                          ES-7

-------
                                            TABLE ES-3

                             SELECTED SETS OF REGULATORY OPTIONS
         Regulatory   Effluent
         Package      Stream
                                             Effluent Control Option
                     Drilling Fluids & Drill Cuttings
                     BAT Produced Water
                     NSPS Produced Water
                     BAT Treatment & Workover Fluids
                     NSPS Treatment & Workover Fluids
                     NSPS Completion Fluids
                     Produce Sand
                                             3 Mile Gulf/California
                                             Rotation All
                                             Flotation All
                                             Oil and Grease Limits
                                             Oil and Grease Limits
                                             Oil and Grease Limits
                                             Zero Discharge
          B
Drilling Fluids & Drill Cuttings
BAT Produced Water
NSPS Produce Water
BAT Treatment  & Workover Fluids
NSPS Treatment & Workover Fluids
NSPS Completion Fluids
Produced Sand
3 Mile Gulf/California
Zero 3 Miles Gulf and Alaska
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
                                               ES-8
_

-------
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.
ES£ 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-4
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 and the appendices.
ES.6 INDUSTRY ACTIVITY PROJECTIONS

This report evaluates one projection of future offshore oil and gas activity. The
projection covers a 15-year time period and is based on an assumption of an average $21/bbl oil
price and restricted or constrained development activities in the Atlantic and the Pacific. This
scenario is considered the most reasonable given recent oil prices (approximately $21/bbl for
1992 for sweet light crude, see Oil and Gas Journal. OGJ Newsletter, 14 December 1992) and
presidential and state moratoria on efforts in the Atlantic and Pacific.
ES-10

-------
                                    TABLE ES-4

        DISTRIBUTION OF OIL, OIL/GAS, AND GAS PRODUCING PLATFORMS
                               BY REGION AND SIZE
Region and
Wellslot Size
                        Production Type
 Oil     Oil/Gas  Gas
                 Comments
Gulf la*
Gulf lb«
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40

Gulf 58
Atlantic 24

Pacific 16
Pacific 40

Pacific 70
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
No

No
No

No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes    No
Yes    Yes
No gas-only platforms among large Gulf
platforms.
No gas-only platforms among large Gulf
platforms.
Yes
Yes

Yes
Yes
No

No
No gas-only platforms among large Gulf
platforms.
No gas-only platforms among large Gulf
platforms.
Cook Inlet 12/24
Beaufort Sea 48
- Gravel island
- Platform
Norton Basin 34
Navarin 48
No

Yes
Yes
Yes
Yes
Yes

No
No
No
No
Yes"

No
No
No
No


No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
No infrastructure for gas delivery.
Source:    EPA 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.
                                        ES-11

-------
ES.7  POLLUTION CONTROL COMPLIANCE COSTS

       The regulatory costs were developed by the Engineering and Analysis Division, U.S.
Environmental Protection Agency, and are described in the development document for this rule.
Table ES-5 presents the annualized cost for the two regulatory packages analyzed in this report.
For Waste Package A — the selected package — the cost is estimated at $122 million (1986
dollars; $134 million hi 1991 dollars) in the first year of the regulation.  By the fifteenth year of
the regulation, the cost for this package is estimated to be $36 million (1986 dollars; $38 million
in 1991 dollars). The cost declines in time as existing projects, that must meet BAT
requirements, come to the end of their economic life.  Cost for NSPS is assumed to increase year
by year as projects come into operation. At the end of 15 years, the number of structures
coming into production is assumed to be equal to or less than the number of structures going out
of production.
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. EPA examined the combined effect of regulatory options on BAT
and NSPS projects.  The BAT models begin at the projects' economic midlife, a time at which
most drilling programs have been completed.  An existing project (BAT) will bear compliance
costs for'additional controls on produced water, produced sand, and treatment and workover
fluids.  Table ES-6 summarizes impacts for a Gulf 12-well oil and gas platform. The present
value of production  declines when the platform must meet the zero discharge requirement as
well as the filtration limitations. No loss of production is associated with limitations based on
improved performance of gas flotation.  Under the Flotation All option, the corporate cost of
production increases by less than 3 percent and the net present value decreases by less  than 4
percent.  Larger impacts are  associated with filtration and zero discharge requirements.

       New source (NSPS) projects incorporate the effects of incremental costs for pollution
control of exploratory wells (BAT) and development wells on NSPS platforms (NSPS).  An NSPS
project would bear increased costs for drilling fluids, drill cuttings, completion fluids, treatment
                                         ES-12

-------
                    o
                    o
                                                                        o •£•   in
                                                                        ss   fc
                                                           5   S
                                                           «»   *
               <0
               0)
               o>
                        o

                         c_
                                                    «M     •* 1^- in
                                  SO   CM «-

                                    *  *A  *
                                                                     0 0 «-   «^

                                                                     **r;&   ^
               O)
               01
              t£


              "o

               CO

               co

              S



              1
g
o

L.
O
01
                                               ^   in
                                               eo   in
                                                                           g
                                                                   TT*0    °
                                co^)   *-      ro   «-     «sn ^* *-
                                ^ Ov   *^      V»   fXJ     T- »- *^ *%
                    &



                    £


                    g
                    U
                                        (a  w co
                                        *J 4J 4J
                                *4— ^C ^C V  V V (D


                                 =§g»»«1
                                "^^^SSfc
                                ro u. u. o o o N
                                                                s
                                                                 CO
                                                                 CO
                                                       H- 01 01  01 CV 01

                                                       -* — -•  !H fe fei
                                                       •- O O         O

                                                       X I- t-—>—>—> L.
                                                          Q) 0> ••- ••- «i— 0)

                                                       tOIMIM O O O IM
     if
                                        al

s

o
UJ
—I CO

33


00
                           S      11^
                            C.      ^ L.«
                           o    L. c. o :
                              t- oi o s-

                           ""SS3,*1
        .= ud. "i-u


        ri °" co *~ co co •
        •— t- o. i— o. a.
        i. < CO < CO CO
        Q CO Z CO Z Z I
                                   O    c. L.  O 3
                                      t. 01 03--
                                   oa oi *• at  _ u.
                                        oua   •-

                                        lSo."   1
                                               '
                                                     a
                                                     -u
                                                     o
                                                                                                                                   s;
—* fi.    I—
—•   CO   CO CO"
•»- H- a. i— a. a.  —
 c. < co < to co  t.    o

             z a.   ^-
                                                                                        Q.

                                                                                        Ul
S
                       CD O)

                      -^ CD

                       3Jtf
                                                            ES-13

-------
a.
V3  «-


M  O
Ul  ID
         s
         V <-
               CD

               £
               o
               en
                                                    roo o o

                                                    mo oo
                       ocoeooooocoooo     oeoo>>oo
         V     «l         XXXXXXXXXX
         3     D3         ^ K1 ^O *~ *O «~ *O CO O O


                         (Mttiiiiiii



         S     »*
         M     CO       lrtO«-[O«* j^CM»

         L.O   ca       R-ora CM in (Min
               O
               o







         b     e         -J-M rjo rjoto «-o o





               a


         c~t-   a

         as.



               fi         SSggggKggg

         o LU   a         rofoooootoooo       o o o o

          SO3   O
          i^x


         >5   «0       OOOOOOOOOOO     _- -  _	
               ~       CNJOOCMCMCUCUOCUCUCM     §N-3|'O«
                       *O ^f *^" ^O ^O *G *O *«4" NO N9 ^O     CD fO C) CD CD


         — —           <55O?O<9?Q?Q?55O?5^?3     Tr^l'TT

         £. t.
         a. a.
                                     in ^-«—«—
                            JOvOvMOrOOOCOOJfVJ
                            »g5j|»t«*S~
                                   L. SI    —


                                 25,3    2
                         Is:
                                                     vfi ir»Q
                                                  •82**
                                                  ocvioino
                                                  WjOOK,
                           «»utinc>
-------
and workover fluids, produced water, and produced sand. Under the improved gas flotation
limits there is no loss in production, an increase in corporate cost of less than 1.5 percent, and
declines in net present value and internal rate of return of less than 6.5 percent.

       For projects larger than the Gulf 12-well platform, impacts are generally less than those
seen in Table ES-6, 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.

       In the real world,  there will be projects that fall between the BAT and NSPS models, e.g.,
platforms that are installed but complete part of their drilling program under the new
requirements.  They are much closer to the beginning of their economic life than to their
midpoint but not all wells are drilled under the new requirements.  For these platforms, the per-
project impacts are estimated to be equal to or less than the NSPS per-project impacts,
depending upon the number of wells drilled under the new requirements.
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 the 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.  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 0.05 percent. Financing all
                                          ES-15
-------
BAT and NSPS costs by working capital would decrease that parameter by no more than 0.5
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.
Financial ratios affected by debt-financing increase by less than  1 percent under the regulatory
packages investigated.  Working capital may decrease by 5.3 percent and the current ratio may
decline by 0.4 percent during the first year of the regulation. Under regulatory Package A,
working capital declines by 4.5 percent. All other ratios change by no more than 0.3 percent for
this regulatory package. 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.10  REGULATORY IMPACTS ON PRODUCTION

       The total amount of production2 from BAT and NSPS structures was calculated.  This
baseline estimate was compared to the total production under the two sets of regulatory options.
The range in potential production loss varies from less than 0.1 to 0.3 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 in the first year is estimated to be between $114 and $136
million (1986 dollars; $129 to $153 million in 1991 dollars, respectively), depending upon the
   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 BOB.
                                         ES-16
-------
regulatory package.  State revenues might be affected by reductions in lease/bonus bids. The
maximum impact of the guidelines on state revenues is $7.2 to $8.6 million (1986 dollars; $8.1 to
$9.6 million in 1991  dollars, respectively).  For either Texas' and Louisiana's estimated share of
the impact, lost revenues are less than 0.1 percent of the state's total 1986 revenues. These are
potential losses in tax revenues.

       The company-level impacts presented in Section ES.9 and the impact on federal and state
revenues are mutually exclusive. The company-level impacts  assume the companies make no
effort to recover any compliance costs by lowering other costs. Companies may choose to pass
along some or all of these increased costs through lower lease bids rather than absorb  them
through a reduction in profit. The loss in federal and state revenues is reported as if all costs to
the company were recouped through lower lease bids.  The actual impact of the regulation will
be one of the following: (1) company-level impacts as shown, (2) federal and state revenue
impacts as shown, (3) some mixture of company and federal/state revenue impacts, but not as
high as those shown. It would not be the sum of items (1) and (2).

       No significant impacts on the balance of trade, inflation, employment, or energy prices
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 necessary.
                                         ES-17
-------
-------
                                  SECTION ONE
       INTRODUCTION AND SUMMARY OF REGULATORY OPTIONS
1.1    INTRODUCTION

      This report evaluates the economic impact of final 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.  Offshore operations take place seaward of the
inner boundary of the territorial seas, as defined in section 502(8) of the Clean Water Act (the
Act). The industry is included as a subcategory of the oil and gas extraction point source
category.

      The U.S. 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 scheduled for promulgation:
             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).
1.2    RULEMAKING HISTORY AND PREVIOUS ANALYSES

       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
                                         1-1
-------
guidelines for additional 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. The focus of the Notice was new information relating to the discharge of drilling
fluids and drill cuttings.

       In light of the additional data and other information gathered since 1985, the Agency
reproposed BCT, BAT, and NSPS effluent limitations guidelines for the offshore oil and gas
industry on November 26,1990, and March 13,1991.  This rulemaking effort covered drilling
fluids, drill cuttings, produced water, and other waste  streams. A detailed economic impact
analysis (EIA) of the regulatory options was prepared in support of the March 1991 reproposal.
The EIA examined:

       •      Pollution control options for drilling fluids, drill cuttings, and produced water.
       •      Several sets of projections based on three oil prices  and two levels of
              development.
       •      Two types of filtration (membrane and granular), each with its own set of costing
              projections.

       This report is the economic impacts analysis associated with the promulgation of effluent
limitations  and guidelines and new source performance standards for the offshore oil and gas
industry. It incorporates responses to data and comments submitted with the March 13,1991,
rulemaking effort, such as:
              The inclusion of existing structures in the Gulf of Mexico state offshore waters in
              the count of structures estimated to incur BAT incremental pollution control
              costs.
              The revised costing of granular filtration as a treatment and disposal technology.
              Membrane filtration is not considered in this report.
              Additional regulatory options. These include consideration of improved gas
              flotation as a treatment technology, and the exclusion of single-well structures
                                           1-2
-------
              Economic impact analyses of regulatory options for treatment, workover, and
              completion fluids, as well as for produced sand.
13    SUMMARY OF REGULATORY OPTIONS

       1.3.1 Drilling Fluids and Drill Cuttings

       Drilling for oil and gas involves the use of drilling fluids and the generation of 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. Four 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 diesel oil.
       H      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 in the stock barite.
       •      Zero discharge  of drilling fluids and drill cuttings based on distance from shore.
              The technology basis for the zero  discharge requirement is onshore treatment
              and/or disposal.

Each requirement is discussed more fully below.

       No Discharge of Diesel Oil; 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 any diesel
oil.  The technology bases for  this requirement includes transportation to shore for disposal or
reuse or the substitution of less toxic mineral oil for diesel oil.
                                            1-3
-------
       No Discharge of "Free Oil"; This requirement prohibits the discharge of any free oil, as
measured by the static sheen test.


       Toxicity Limitation;  All options limit the toxicity of the discharge of drilling fluids as

measured using a 96-hour LC50 toxicity test.  The toxicity limitation is established at 30,000 ppm
suspended paniculate phase (SPP). The purpose of the requirement is to reduce the levels of

toxic constituents in drilling fluid and drill cutting discharges.


       Limitation on Mercury and Cadmium Content;  All options limit the amount of mercury

and cadmium in drilling fluids.  The concentration of mercury must not exceed 1 mg/kg (dry-

weight basis) and the concentration of cadmium must not exceed 3 mg/kg (dry weight basis) in

the stock barite.


       Zero Discharge Based on Distance from Shore;  Under the "Zero Discharge"

requirement, all drilling fluids and cuttings are prohibited from discharge.  The technology basis
for this limitation is transportation to shore for treatment and/or disposal.


These requirements have been combined into four options:
              3 Mile GulffCalifornia — For all regions except Alaska, drilling wastes from wells
              located within three miles of shore must meet zero discharge requirements.  In
              these regions, the disposal of drilling wastes from wells located beyond three miles
              of shore must meet limitations on toxicity, no discharge of diesel oil, no discharge
              of free oil as determined by the static sheen test, and limitations on mercury (1
              mg/kg) and cadmium (3 mg/kg) content in the stock barite. Alaska is excluded
              from the zero discharge requirement, but all  discharges must meet the
              requirements for toxicity, free oil, diesel oil, cadmium, and mercury.

              8 Mile Gulf/ 3 Mile California — Zero discharge for all wells in the  Gulf of
              Mexico located within eight miles from shore and zero discharge for all wells
              offshore California located within three miles of shore. All wells located beyond
              eight miles of shore in the Gulf of Mexico, beyond three miles of shore off
              California, and all wells drilled offshore Alaska permitted to discharge drilling
              fluids and drill cuttings that are in compliance with the requirements for toxicity,
              free oil, diesel oil, cadmium, and mercury.

              Zero Discharge GuWCalifornia — Zero discharge for all wells located in the Gulf
              of Mexico and offshore California.  All wells  being drilled offshore Alaska
                                           1-4
-------
             permitted to discharge drilling fluids and drill cuttings that are in compliance with
             the requirements for toxicity, free oil, diesel oil, cadmium, and mercury.
             4 Mile GulffCalifornia — The requirements are the same as in the 3 Mile
             Gulf/California option, except that the boundary determining the zero discharge
             requirement is set at 4 miles from shore. This option is comparable to the
             preferred option in the March 1991 proposal.
       1.3.2 Produced Water

       Three disposal technologies are considered for produced water:

       •      Zero discharge of produced water (technologically based on reinjection).
       •      Filtration of produced water prior to discharge. The costs and removals for this
              alternative are based on updated information for granular filtration.
       •      Improved performance of gas flotation.

Five disposal options are considered in the economic impact for BAT and NSPS produced water
regulations.  The options for BAT are summarized in Table 1-1, while those for NSPS are listed
in Table 1-2. BAT options are distinguished by the exclusion  of existing Gulf of Mexico single-
well structures with their own production equipment from zero discharge requirements; these
structures must meet flotation limitations. No exclusion from zero discharge requirements is
made under NSPS for these structures.  The BAT Flotation All option includes costs for two
years of monitoring for radium in produced water, however, no monitoring requirement is
included in the BAT limitation.  The monitoring costs are included in the economic impact
analysis to evaluate the effects should EPA seek this information through monitoring
requirements imposed in general permits. The NSPS Flotation All option includes no  costs  for
radium monitoring. BAT and NSPS options for Alaska are distinguished in the costing efforts
because existing offshore Alaskan structures (BAT) are already required to meet zero discharge
requirements by state permit conditions (so they will incur no BAT costs), but costs for projected
structures in Alaskan waters are included in the calculation of NSPS costs. The limitations for
Alaska, however, are the same under BAT and NSPS.  All existing structures off California
                                           1-5
-------
                                       TABLE 1-1

                                  PRODUCED WATER
                              BAT REGULATORY OPTIONS
Regulatory Option
Short Form of Title
BPT - All Structures

Improved Gas Flotation - All Structures

Filter (Granular) and Discharge
- All Structures Within 4 Miles
BPT - All Structures
Beyond 4 Miles

Gulf of Mexico
Zero Discharge Within 3 Miles
(Gulf Ib Structures = Flotation)
Flotation Beyond 3 Miles
California: Flotation - All Structures

Gulf of Mexico
Zero Discharge
(Gulf Ib Structures = Flotation)
California: Flotation - All Structures
BPT All

Flotation All

Filter 4 Miles
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
                                        1-6
-------
                                      TABLE 1-2

                                 PRODUCED WATER
                            NSPS REGULATORY OPTIONS
Regulatory Option
Short Form of Title
BPT - All Structures

Improved Gas Flotation
- All Structures

Filter (Granular) and Discharge
All Structures Within 4 Miles
BPT - All Structures Beyond 4 Miles

Gulf of Mexico and Alaska
Zero Discharge Within 3 Miles
Flotation Beyond 3 Miles
California: Flotation - All Structures

Gulf of Mexico and Alaska
Zero Discharge - All Structures
California: Rotation - All Structures
BPTA11

Flotation All


Filter 4 Miles



Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
                                         1-7
-------
(BAT) are excluded from meeting zero discharge requirements and instead must comply with
improved gas flotation limitations.
       1.3.3 Treatment, Workover, and Completion Fluids

       When a well has reached its final depth, a determination of its productive capability is
made.  If the well is economical, it, will be completed as a productive well.  During this process,
fluids are pumped down the well bore, both to clean it and to maintain sufficient pressure to
prevent formation fluids from coming up the hole until the blow-out preventer, valves, and other
parts of the Christmas tree assembly are installed.  Once in production, a well is treated or
worked over on a periodic basis to keep the wellbore clear and to maintain production.

       Treatment, workover, and completion fluids must meet the same limitations on oil and
grease  content as established for produced water (BAT and NSPS).  The technology basis for
this limitation is commingling and treating the treatment, completion, and workover fluids with
the produced water wastestream. Those facilities unable to commingle without causing a
treatment system upset could comply by transporting the fluids to shore for recycling and reuse,
where  appropriate, or disposal.
       1.3.4 Produced Sand

       Produced sand consists of the slurried particles used in hydraulic fracturing and the
accumulated formation sands and other particles (including scale) generated during production.
This waste stream also includes sludges generated in the produced water system, such as tank
bottoms from oil/water separators and solids removed in filtration. The option considered in this
analysis is zero discharge of all produced sand.
                                           1-8
-------
       1.3.5 Miscellaneous Wastes

       The rule establishes limitations on deck drainage, domestic wastes, and sanitary wastes.
Since the BCT, BAT, and NSPS limitations selected for miscellaneous waste streams already
apply in either existing BPT effluent guidelines, NPDES permits, or Coast Guard regulations,
there are no incremental costs.  As such, they are not considered further in this analysis.
       1.3.6 Combinations of Selected Regulatory Options

       The Agency selected two "packages" of regulatory options for more detailed analysis of
the economic impacts of these combined costs on typical companies, future oil and gas
production, federal revenues, state revenues, and other parameters.  Each package has an option
for:

       •      drilling fluids and drill cuttings
       •      BAT produced water
       •      NSPS produced water                       .--.....
       •      treatment, workover, and completion fluids
       •      produced sand.

The waste packages are listed in Table 1-3.
                                           1-9
-------
                                     TABLE 1-3

                             REGULATORY PACKAGES
Packages
Waste Stream
Regulatory Option
B
Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand

Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand
3-Mile Gulf/California
Flotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits

Zero Discharge

3 Mile Gulf/California
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits

Zero Discharge
                                      1-10
-------
                                   SECTION TWO
                     CHARACTERIZATION OF OFFSHORE
                             OIL AND GAS ACTIVITY
       The offshore oil and gas industry leases, explores, and develops areas located off the
coasts seaward 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. Throughout this report the terms platform, structure, and facility are used
interchangeably.

       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 that 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 Department of the Interior has jurisdiction over leases in areas seaward of state jurisdiction,
typically for areas beyond 3 miles of the coast. The exceptions to this rule are Texas and Florida
(on its Gulf coast side only), which have jurisdiction over areas up to 3 leagues (9 nautical miles,
or 10.4 statute miles) from their shores.
                                          2-1
-------
       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.
       2.1.1  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
1990. As shown in the table, lease sale activity has accelerated somewhat in recent years.
Throughout the 36-year history of the program, nearly 785.8 million acres have been offered and
nearly 64 million acres leased.  A total of 149,185 lease tracts were offered, 13,443 were bid on,
and 12,363 were leased during that period. In 1990, nearly 30 million acres were offered and
over 4 million were leased, and 10,459 tracts were offered and 825 were leased. Most of the
leased territory has been off the coasts of Texas and Louisiana. Tracts have also been offered
off the Pacific, Alaskan, and Atlantic coasts.

       Table 2-2 provides a summary of federal leasing activity for 1980-90.  The number of
tracts offered per year ranges from 483 to 27,984. Thirteen percent of the tracts offered during
the 10-year period were bid on. Of these bids, 92 percent were accepted.
                                            2-2
-------
i
        !!
        II
        i
          6
S" 8 5 6 S  -
5  8 8 8 8 »•
~    ^    tt
        p ro o o o t9

        51    11
        J3 8    $ »
' S3 •- 2 t*
 S 18 8 fe

 "
                                                                      5.
                                                                   8 3 S
                                                                   58 S
      R 8 5
                                                 g. $ S » i g § § I
                                                ; i i g §; g; si 5 s
               § §
              K § f S11S §
                  -
              § § 1 s i
             [ 8 g 8 |" |
             .»*tH'i**1
US8i
                                               5--I5
                                                                ,
                                                               1
                                                             iifl
                                                             '
             "" • E s 3
              llll
              lf*5-
              |tlf
              lls*
               gs«
              » j£fi

              til
W


O
                S S I

                                2 i S
                                       2 S S I 5 § § 1
                                       § « 8 8 8 S 8
                                       -- -- - -' --  - --
                                                                    8 »
                                                                     -  -
                          •
                                                  S S 8
                                               <* n r> i
                                               ^ B 5. !
                                               S S 8 1
                                               K as * i
               I S. i: 1 1
                                                             88*8 1 §

                                                 lllllllllllllll
                                                ^'''''''''''
                                                             if
                                                             SI
                                                                              IIM
                                                                              «IM
                                                                              l
                                        2-3
-------
    I/)
i   i
    CO 0\
               If
                1 e
               1
                                                    rS
                                                                  .
                                                            fc 5Sf? " =   S
                               n*r^^
                                               S 5
                    § § § 5



                    2" H 8 *• E S
                    N S3 ° * •- i
                      "
                            5.
S S 5
                                                          iillili I


       0\
                                                                g 18

                                                                  •
                                                         si S 3 S 2 ^ S

                                                         & R 8 5 8 £ ii i
                            8 §  S
                               81 p. I
                                                            T^ ^ W  10 ^
                                                      x
                                                    i c* S o ui
                                                                      I
                                                                              I S

                                                                              S P
                                            2-4
-------
C
*3




               P if !ff *~
                In IK {3
' O 90 * Q f'^QOOOCp^*!

 Hi I 111  I 1 §
 « * §5 to *- 3J K>  s *R (9
|*f   gfgi
                                                 9
                                                 Bl
                                                 3
                                                of «>

                         *~CkCDN.  PJO*OCPNO^O
                         a 1 1 ^  % I i I § 3 ?.
                          '            "
                                            ^<5O
                                            8. 1 §
                g I < !|" 5 § s" I S $ I i
                 fe
                          9 S I.  S I § ? S 2 § S
                           i i  i  1 5 § s" s.

                                                        11
S


H
   8
   ft!
                   i^j'MMif
                   v  01   »•«*•»•

                                          .

                               § S s p
                           S i$  S a S 5 i
                                               .
                                             1 5 is S 2 i

               s a & ? g ^ § - g s S ^  • I 8 • * « g fi « S i & g " g S *8.&
                 ' a If S tf :


                 5999:
                          S 8
                                 & 8 5 (5 5
                           5 5
                           10 ^
                               3;
                              ' oi

                    S'S'S'S
                          ^


                           '
                                u'i*!
                                llilSin f
                                18  S]III!l
                                                        ^ 5 1 * * •-8 S. t 2 5
                                                         I!1! H"!
                                                         "z7-Vibrf9i
                                                         e « c E I * a f 1
                                                        liyi

                                                        ill!
                                                               ill
                                                                 m
                                    2-5
-------
                                  TABLE 2-2
                      OCS LEASING STATISTICS, 1980-1990
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
No. of
Tracts
Offered
483
1,398
1,410
21,689
27,984
15,754
10,724
10,926
28,510
11,013 ,
10,459
No. of
Tracts
Bid On
258
520
404
1,325
1,530
736
155
680
1,675
1,079
845
No. of
Tracts
Sold
218
430
357
1,251
1,387
681
142
640
1,621
1,049
825
Average Bonus
Bid Per Tract*
{Millions of $}
19.3
15.4
11.2
4.6
2.9
2.3
1.3
0.8
0.8
0.6
0.7











     ^Current: dollars.
Source:  MMS, 199la.
                                     2-6
-------
        Leasing Revenues

        Payments made by lessees are of two types:  bonus payments and royalties.1 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.

        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 the bonus payments (or "bid
 prices") that have been received for leased areas.  During the period from October 1954 through
 August 1990, bonus payments totaling nearly $56 billion were received by the federal treasury for
 offshore tracts, with the average tract leasing for $4.5 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 1990
 range from $0.7 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 value2 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 $39 billion In royalties have been paid through
 1990. In 1990 alone, over $2.6 billion of oil and gas royalty payments were made for outer
 continental shelf (OCS) leases.
      1A third category, annual rental payments at $8/hectare (equaling $20/acre), is of insufficient
magnitude to be considered in the economic analysis.
   2Value, as used here, is equivalent to the wellhead selling price of oil or gas.  Because oil and
gas frequently are not sold at the wellhead, the term Value" is the wellhead value of the oil or gas
established by U.S. Department of the Interior, Minerals Management Service (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, 1953-1990
Royalties Paid (Billions of Dollars)'
Year
1953-1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Total (1953-1990)
Oil
$5.378
1.575
1.740
1.640
1.823
1.707
1.015
.999
.747
.818
1.091
$18.534
Gas
$4.669
1.712
2.075
1.815
2.091
1.906
1.518
1.338
1.310
1.300
1.539
$21.273
     'Does not include royalties  for substances other than oil and natural
gas.   Values in current  dollars.
Sources:  MMS, 1991b; MMS, 1991c.
                                   2-8
-------
        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) office 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 $3.2 billion received in 1990.
       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 that 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
       •      NASAArea
       •      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 certain activities, including drilling, may interfere with military or NASA operations.
Geological hazards analysis may be required under the geologic hazards stipulation if the bottom
                                           2-9
-------
2
                            tD  tO  Q
                               r~i  i~i
                               i-4  O
                                      O  U
                                  •O 4J  d
                                   g  a  o
                                   3  D  -H —.

                                   ..  B  H H

                                  ||^g



                                  08*"
                                              *V
                                             s
                               •3
                               CO
                                          s
                                              HI
                                              s
                                              m
                                          M-l  0)
                                             CO
                                                        iHOOiHOOiHOVOOOcn
                                                            c>J H
                                                                          ro
                                                                                  en oo  in »*
                                                                                                        m      H
                                                                                                        Vi      01
                                                        OOOOOOOOOOOOOOOOOOOOCh


                                                        tH»Hf-lTHfHrHfHtHf-lflHrH
                                                                  2-10
-------
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 in some areas to protect
the marine environment (on the basis of geologic hazards, sensitive marine areas, biological
concerns, and other factors).  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 Minerals Management Service (MMS) in the leasing process.  Most states do not publish
historical data on individual lease 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. Table 2-6
summarizes historical and planned leasing activities in state waters.  Since states do not
distinguish between inland bays and harbors and open ocean, the numbers presented in Table
2-6 are likely to include both the Agency's "coastal" and "offshore" subcategories.
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 makes 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 about 15
                                           2-11
-------
in
§
                                 •«  id
H   01
 a  .P.
                                 .8
                             *  >i id
                             r-  JQ  0)
                             10          0)
                              •  4J  VI  r-l
                             ID  0)  O  id
                                 m
                                         m
 id   C      g
 >t  O   - O
 O       G  H  CM
 Vi   Cn  o  "w  ^.
     C  -rl      i-H

 c  -o   o  c  o

*O   Q)  *O  Cn
•rt   ft  O  fi  »O
^H   0)   H  Id  —.
CO  "O   ft Vl  rH
                                                                                    Q)
                                                                                    u
                                                                                    H  0)
                                                                                    CD  -P
                                                                                O  ft
                                                                                     I   O
                                                                                    4J  4J
                                                               H  -O
                                                                            I   3
                                                                                                       4J  CM
                                                                                                       -H   H
                                                                                                       n   •     B  i-H  J3
                           o  >-4
                           O   01
                           O   U
    •H  Cn

    •O  -H
 I  0)  U
    S  3

 >t C  ?
    0)  V4
in  vi  ft
                                                         c   m
                                                         d)   id
                                                        TJ  O  0<
                                                         G  r-t  G
                                                            •m  u
                                                                                      %  Cn
                                                                                      a)  a
                                                                                      a  •*
                                                                                      oi  u
                                                                                      n  3
                                                                                       .   *
                                                                                       1   S
                                                                                      M  ft
                                                        O  O
                                                                ft
                            •s
                                                                                                       I   ">
                                                                                                          CM
                                                                                                      •O  C
                                                                                                      •H  -r<
                                                                                                      m  g
                                                               01   C
                                                               d  -r4
                                                               0)   U

                                                               *3
                                                               1
                                                                                                                       in
 (0  I/I
*o
 C  0)
                                                                                                                                              CTi
                                                                               id   a)  vi
                                                                               0)  <-i  id
                                                                                                                                  •H
                                                                                                                                   0)  id
                                                                                                                                   m  Vi
                                                                                                                                                  to
                                                                                                                                 co
                                                                              I.
                                                                              Vi

                                                                              ft
                                                                                                                                  Q  tt)

                                                                                                                                   id
                                                                                                                                              •o
                                                                                                                                               vi
                                                                                                                                               id
                                                                                                                                              m   o>
                                                                                                                                               id  
-------
TABLE 2-6
HISTORICAL AND PLANNED STATE OFFSHORE LEASING ACTIVITIES
State
            Currently
              Leased
              Acres
                      Future Planned
                      Lease Sales
Alabama       105,000

Alaska


California    132,419
Florida     2,600,000

Louisiana     249,889
Texas
430,000
One sale scheduled for July 1988

Five sales planned 1988-1992
involving offshore tracts.

None currently planned;
environmental impact assessments
preceding for several potential
future sales.

None

Lease sales are held monthly;
leasing activity has declined
since 1980

Lease sales held twice per year;
leasing activity has declined
since the early 1980s.
Sources:   Alaska
           Alabama
           California
           Florida
           Louisiana
           Texas
        Litzen,  1988;  Douglas,  1988;  Alaska,  1988.
        HcRory,  1988.
        Willard,  1988; CDC,  1987.
        Hachenberger,  1988.
        Alexander,  1988.
        Boone,  1988.
                                                2-13
-------
percent of the exploratory wells drilled will prove to contain economic amounts of oil or gas, see
Table 2-7.)

       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 in each offshore
region before January 1,1992.  An estimated 8,899 exploratory wells had been drilled as of that
time. Of these, 6,431 were drilled in federal waters. Of all the wells, oil was found in 407 cases
(4.6 percent), gas was found in 782 cases (8.8 percent), and 7,710 (86.6 percent) were dry holes.
Nearly thirty percent of exploratory drilling occurred in state waters (27.7 percent; both coastal
and offshore subcategories) and the remaining 72.3 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 oal price determine whether the operating company will produce the field.
Characteristics of the field (volume, porosity, water saturation, and other data used to calculate
                                           2-14
-------
                                TABLE 2-7

     TOTAL OFFSHORE' EXPLORATORY DRILLING IN THE UNITED STATES
          FEDERAL AND STATE LEASES ALLTIME TO JANUARY 1,1992
                                Number of Exploratory Wells
Location
                  Oil
                                  Gas
                              Dry
                                                                  Total
ALASKA
State
Federal
   Total
19
- 1
20
 7

 7
  58
  28
  86
  84
  29
 113
CALIFORNIA
State
Federal
   Total
20
25
45
10
 0
10
 139
 166
 305
 169
 191
 360
OREGON
Federal
WASHINGTON
State
Federal
   Total

PACIFIC COAST
Federal

PACIFIC OCEAN
State
Federal
   Total
 39
 28
 67
 17.

 17
                                  2
                                  4
                                  6
                                 39
  199
  245
  444
                                   2
                                   4
                                   6
                                                 41
  255
  273
  528
 FLORIDA
 State
 Federal
    Total
                                 15
                                  9
                                 24
                                  15
                                   9
                                  24
 LOUISIANA
 State
 Federal
    Total
 65
212
277
113
306
419
1,016
3,734
4,750
1,194
4,252
5,446
                                     2-15
-------
                                 TABLE 2-7 (cont)
 Location
Oil
                                   Nunber of Exploratory Wells
                                     Gas
                                                      Pry
                                                  Total
 TEXAS
 State                41
 Federal              ll
    Total             52

 N. GULF OF MEXICO
 State                 1
 Federal              10
    Total             11

 GOLF OF MEXICO
 State               107
 Federal             233
    Total            340

 ALABAMA
 State
 Federal              —
    Total

 MISSISSIPPI
 State                 0
 Federal               0
    Total              0

 ATLANTIC OCEAN
 Federal              —•

 GRAND TOTAL
 State               146
 Federal             261
    Total            407
                 213
                 112
                 325
                   0
                  14
                  14
                 330
                 435
                 765
                  4
                  3
                  7
                  0
                  0
                  0
                347
                434
                782
   740
 1,323
 2,063
     0
   387
   387
 1,776
 5,454
 7,230
    4
    1
    5
    1
    0
    1
                                   36
1,975
5,735
7,710
   994
 1,446
 2,440
     1
   411
   412
2,213
6,122
8,335
    8
    4
   12
    1
    0
    1
                                                    36
2,468
6,431
8,899
    •American Petroleum Institute (API)  definition for an offshore well  is  a
well producing from beyond natural shorelines.  This table is taken from an
API report and may therefore include wells in the coastal subcategory.

Source:   API,  1992,  Section XI, .Table 7.
                                    2-16
-------
  hydrocarbon volumes) 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 has
  been made to begin development, a production platform is put in place. Platforms are custom
  designed for water depth, bottom stability conditions, the expected number of wells, the size of
  the drilling rig, and other factors. Additional wells,  called  development wells, typically 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 determine the required  number and placement of production
  platforms.
        232 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 offehore subcategory waters are defined in 40 CFR 435. A
 platform is in the offehore subcategory if it is located seaward of the inner boundary of the
 territorial  seas.  For this analysis, we focus on all existing structures that are either in or nearing
 production and are therefore likely to incur compliance  costs for the disposal of produced water,
 drilling fluids, drill cuttings,  produced sand, and treatment/workover/completion fluids under the
 various regulatory options.
       Platforms in Federal Waters

       Table 2-8 presents data on the number of existing platforms in production located on
federal OCS leases. Overall, there are an estimated 2,255 platforms and approximately 12,300
producing wells. Note that of the 2,255 platforms in federal waters, 2,233 are in the Gulf of
                                           2-17
-------
                                 TABLE 2-8

          FEDERAL WATERS INVENTORY OF PRODUCING PLATFORMS
Area
                      Number of
                      Production
                      Platforms
             number of
             Producing
             Wells
             Comments
Alaska



Atlantic



California

Gulf of Mexico


TOTAL FEDERAL DCS
   22

2,233


2,255
   337

11,892


12t273
All Federal OCS areas
still in exploration
phase.

All Federal OCS areas
still in exploration
phase.

See Table 2-10.

See text.
Source:   EPA estimates.
                                    2-18 .
-------
 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 well slots, no information on the
               number of well slots, 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 Section Four on how the count was obtained.

       The inventory of 22 structures off the California coast is estimated from data from the
 California Division of Oil and Gas, California Coastal Commission, and the Minerals
 Management Service. Onshore wells with offshore completions, and structures within inland bays
 are not included in this inventory since they fell into a different subcategory. At present, no
 production platforms are in place in federal waters off the coast of Alaska or in the Atlantic.
       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 an "offshore11 well as any well that produces 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 offehore and structures in inland bays. States such
as Louisiana and Texas maintain counts of production wells, but not platforms.

       For this reason, a major mapping effort was undertaken to obtain a more accurate count
of the structures in state waters in the Gulf of Mexico.  This effort is described in more detail in
Section 4. Table 2-9 is a listing of platforms in state waters. Production is occurring from two
gravel islands in the Beaufort Sea in the Endicott field. These structures are in the offehore
category but are not included in the count of structures estimated to bear costs because current
state requirements mandate  the reinjection of produced water.
                                           2-19
-------
TABLE 2-9

STATE WATERS INVENTORY OF OFFSHORE STRUCTURES AND PRODUCING WELLS
State
Alaska

California
Atlantic States

Gulf of Mexico
Alabama
Number of
Production
Structures
2

10
0


0
Number of
Producing
Wells
120

204
0


0
Comments
Endicott field. Zero
discharge of produced water
required by State.
see Table 2-10.
Little or no current
development or
exploration activity

Gas fields in Mobile Bay are
  Florida
  Louisiana
        180
        211
                                           not in offshore category.
No activity ongoing or
planned other than a
small number of
exploratory wells.

See Section 4.
  Texas

Total
        104

        296
        128

        663
                                           See Section 4.
Sources:
Alaska
Alabama
MMS, 1990a.
EPA estimates.
               California  CDC, 1991a.
               Florida
               Louisiana
               Texas
            Hachenberger, 1988.
            EPA estimates.
            EPA estimates.
                                              2-20
-------
        Summary of Structure Count

        For the economic impact analysis, it is not sufficient to obtain a count of existing
 structures. It is also necessary to estimate which of those structures are likely to bear
 incremental costs of additional pollution control. This excludes old shut-in platforms that are no
 longer producing, and structures already required to reject produced water (i.e:, the Endicptt
 field, Alaska).  The  existing structures in the Pacific (Table 2-10) are all assumed to bear BAT
 costs regardless of whether they have yet commenced production. There are two existing
 facilities in Alaskan state offshore waters in the Endicott field. These currently reinject produced
 water under state requirements.  No significant compliance costs for this rule would be incurred
 by the Alaskan facilities; hence, they are not included in this count. In summary, an estimated
 2,549 structures are to bear BAT costs.  Of these, 2,517 structures are in the Gulf of Mexico and
 32 are in the Pacific.  More information on the BAT profile can be found in Section 4.1 and
 Table 4-7 and 4-8.
       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 different sources. It was impossible to
 present the statistics with one consistent reporting date. However, this introduced 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. Adjustments to the inventory were made to account for shut-
in platforms.
                                           2-21
-------
TABLE 2-10

PACIFIC OFFSHORE STRUCTURES
 Field
Structure
    Name
            Water
    Year    Depth
Installed    (ft)
                Number of
          Producing Wells
 FEDERAL
 Beta
 Beta
 Beta
 Corpinteria
 Carpinteria
 Corpinterio
 Dos Cuadras
 Dos Cuadras
 Dos Cuadras
 Dos Cuadras
 Hondo
 Hondo
 Hueneme
 Pttas Pt
 Pt. Arguello
 Pt. Arguello
 Pt. Arguetic
 Pt. Pedernales
 St. Clara
 St. Clara
 St. Clara
 St. Ynez
Edith
Ellen
Eureka
Henry
Hogan
Houchin
A
B
C
Hillhouse
Harmony
Heritage
Gina
Habitat
Harvest
Hermosa
Hidalgo
Irene
Gail
Gilda
Grace
Hondo
Total Producing Wells
STATE
Belmont
Belmont
Carpinteria
Carpinteria
Huntington
Huntington
Rincon
Summerland
Siiroerland
S. Elwood
Belmont
Esther
Heidi-
Hope
Emmy
Eva
Rincon
Hazel
Hilda
Holly
    1983
    1980
    1984
    1979
    1967
    1968
    1968
    1968
    1977
    1969
    1989
    1989
    1980
    1981
    1985
    1985
    1987
    1985
    1987
    1981
    1979
    1976
    1948
    1964
    1965
    1964
    1961
    1964
    1957
    1957
    1960
    1966
 161
 265
 700
 291
 150
 151
 188
 188
 193
 190
1200
1075
  95
 303
 670
 602
 430
 242
 739
 210
 318
 842
  42
  35
 128
 140
  41
  58
  45
 100
 106
 211
Total Producing Wells
           17
           29
           27
           22
           16
           24
           41
           38
           17
           40
Not producing
Not producing
            7
            9
Not producing
Not producing
Not producing
           10
            9
           39
           17
           21

          337
           21

           56
           30
           30
           44

           15
           29

          204
Notes:   Platform Elly has no wells and is not included in this count.
         Onshore wells with offshore completions and wells drilled  in inland
         bays are not included in the count.

Source:  HHS, 1989; HHS, 1990b,c; CCC, 1988;  CDC, 1991a,b,c;
                                                2-22
T2JO.UK3    13-Oct-92
-------
       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 greatly in size and production
capability. All platforms that have productive wells are included in the inventory; 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 processing-only structures (i.e.,
no wells, just separation equipment) may in some cases appear grouped in statistics as
"platforms."  Non-production structures are excluded from 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 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 U.S. waters total fewer than 50.
Terefore, no attempt was made to adjust the platform count to include these structures.1
             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 OCS leasing
program.  The percentage of U.S. oil production from offshore wells compared to total domestic
    *A trend toward subsea completions would change the number of structures but not the number
of wells.

                                           2-23
-------


I
Z
§
8
t*
O ff]
II
§i
^^ Hit
M 9
§1
p|
2 O
$
Q
jr
0
1
m





m M
5 HI
r-l 01
tJ *
at Hellhea
>£ Dollars]
o u
0 O
> §
H 43
fi *
Q
o rt
(U fl]
.8
IT
a
c a
o pa
•n
1 1 uj
O 0
•o a
Ij JJ*
1


S
a oT
tj ^
§ H
«!
H
R)
's
1
«H
O
"8
1
0 *
* S
«
1
'8
0
s
i
i
b tH 01 ro •*
oo oo oo oo oo
o\ on on on on
on r- 01 on oo
oo t* in tH oo
o tH oo vo in
01 ro 01 01 01
VD «* 01 *
vo in CM vo on
r- oo H 01 vo
vo ro CM o on
tH O ro 00 tH
r- 01 ^ O 01
VD •*•*•<* 03
t- r* r~ t^ r»
CM 01 01 OJ 01
O tH 01 ro t
00 00 00 00 00
on en on on on
tH rH tH rH tH
in vo r> oo on o
oo co oo oo oo en
en on on on on on
en tH o oo vo ro
o in ** m oo o
«r 01 in 01 in o
CM tH tH rH rH CM
VO O tH f- O tH
ro t- CM vo f oo
CM O vo ro n CM
rH O On O H <*
in tH oi o r~ t-
oo rH en •* o t-
00 ^3 ^D ^* ^* ^O
f^ t>& *$P CO ^* IO
o o t^ "t tr> m
VO Ol in rH VO ^"
on in oo ro on ^*
01 ro ** •* rH o
00 On CM 00 OI rH
en t- r- •* in on
o in vo in vo r>
tH
vo o in ro in ro
r» in vo in r* ro
01 in r~ o ro oo
co vo ^* ro on ro
vo tH o on ^" vo
oo ro 01 on in ao
r» ^* o H t- in
vo ro *J* ro ro ^*
cn ^* ro vo 00 r*
ro 01 oo ro ro r-
in in r* 01 r~ oo
in 01 ro H r- vo
^i oo r*- cn oo ^
r» vo ^ r» r» oo
CM H o cn r- vo
ro ro ro CM CM 01
ro ^J1 on in rH o
o 01 r~ in 01 ro
H vo vo on oi cn
vo r- vo in «H «*
in in ro ro tH cn
O oo on oo oi r-
in 01 on vo in in
•* vo vo t-i in t—
oo o O ro r*> cn
tH tH rH ** VO 00
oo r~ vo in co CM
CM CM CM 01 01 01
in vo r> oo on o
00 00 00 00 CO On
on on on on on on
tH rH tH tH rH rH
a!
VI
n
O
•O
8
o
a
o
§
1
o
m
O
0^
4J
0)
u
s
Pi
o
-p
1
4J
&
•iH
•O
Q)
I
4J
m
•H
•8
0)
• • 3-
S a
a >
i 3
-p ^
§ rH
H '3
STf
* S
* ™













01
an
H
H
«
Source:
2-24
-------
                S
n«
   co  co  co GO  co     oo  co  oo oo  oo  en
   CM  en  en o\  CM     crt  cr*  o\ CM  en  o*
   i-l  i-l  i-l tH  H     ,H  i-H  rH H  f-4  i-l



   en  oo  vo en  vo     I-H  <3-  UD en  en  .-i
   in  en  «* in  vo     in  en  vo vo  vo  t--                 ...

   iH  i-H  CM CM  CM     (NIiHiHiHiHH                 ij

                                                              JB
                                                               n



   CN  co in  en  oo     oinoHoiio                  °
   co  •* vo  vo  TJ-     co  CM rn  in  in t-                 _,
   1-1  co t~  c»>  cr»     en  co vo  t—  en tH                  g


   in  in en  rH  TJ<     vo  o 00  t—  r- in
   o  en »*  vo  en     H  vo oo  in  in vo                 Jjj

   CM  er> in  ro  r-     ro  CM co  O  o i-<                 2
   roro4>^^>     >*  n CN  n  ro n                 *j


                                                              O
   oj^yr^nr^     r^iot^«d*vDoo
   o vo  •*  o r-     oornvocnt-r-                 S
   CnCniH^PU)     incnOiHt^^J*                 ^

   intHooepr-      mrHvoinrHpJ'                 *}
                         •* o  in ^ ^*  o                 2
                         o o>  *3* r* oo  ^                 ^
                         •»••»*•»»                 «
  n)'^«^rw                e


 o  o  oo vo  oo      t^  vo  i~- r-  oo  CD
 CNCNf-IHiH     rtrtrtrHtH^H





 vo  CN t>- in  **     CM  vo  VD in  o CN
     VDCMOCO     ^VOfOfOHH                 tl
 r^^cM^a>cM     CMint-t^-on                 ^

 CN  vo oo  VD  in     oococo'rH'eo'eM'                "°

 m^u^tfi  f  m     r^inoiHcMun                 2

 in  in in  •<«•  in     ^"'^in'in'in'in'         m      d
                                                     •       ffl
                                                     *•<•>•
                                                     B)      ^     CM

 .^SSS"''*     oo-*rHchcn^         ^!      i{     S
 inro^cnin     m^orococo          o      5     r-i
 lf)CM^Or*)      t^fOTl'O^'CM         *3
  ^^•^^^      ^i»«.^^^                 *•"!
 «O»HHOflO      VO CN O  O  VO CN         41      5     (_7

 cnio^^-irHco      in CN oj  vo  oo  o          §      ^     §«

 2'2CY)CNO'      CNCMCMCMCMrT"          M      5
 «-l«-I.Ht-|1H      iHiH<-lr-4f-|>H          g      •}:     ..
                                                    O      £     CD
                                                    *      Jr     IB

OHCMro^     in vo  r- CO  CM  O                        u
oo co  co  oo oo     oo co  oo oo  oo  CM                        3
CM CM  CM  CM CM     CM CM  CTi CM  CM  CM                        Q
                                            2-25
-------
oil production has fluctuated over the last decade, while offshore natural gas production has
generally increased in relative importance.  In 1980, offshore oil production accounted for 12.1
percent of domestic production.  As low oil prices shut in marginal onshore wells, offshore
production is gained market share. In 1990, offshore production accounted for 14.7 percent of
the national total. The percentage of domestic natural gas produced offshore peaked in 1984
with 29.3 percent. Total offshore natural gas production has also fluctuated between 4.6 trillion
cubic feet in 1986 to 5.5 trillion cubic feet in 1990.  In 1990 about 395 million barrels of oil (14.7
percent of U.S. production) and 5.5 billion million cubic feet of gas (29.7 percent of U.S.
production) came from offshore areas. The offshore oil and gas had a combined market value of
about $17 billion (1990 dollars).
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. 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 analyze patterns of subsea
geologic structures to determine their potential  for oil and gas accumulation and production,
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 one percent of all drilling is performed by operating companies (Baker,
1979). The annual level of activity of drilling contractors is shown in Table 2-14.
                                           2-26
-------
                                  TABLE'2-13

                             SUPPORT ACnViTIES
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:  EPA.
                                      2-27
-------
                                  TABLE 2-14




                        Offshore Drilling Activity, 1980-1990"
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Number
of Wells
Drilled
1,272
1,476
1,464
1,270
1,421
1,247
898
709
866
746
704
Footage
Drilled'
12,503,275
14,422,470
14,537,052
12,831,906
14,259,153
12,815,948
9,407,734
7,345,300
9,334,400
7,721,400
6,963,800
Average
Depth
Per Well
(ft-)
9,829
771
9,930
10,104
10,035
10,277
10,476
10,360
10,779
10,350
9,892
     •includes exploration, delineation,  and development drilling.




Source:   API, 1992.
                                       2-28
-------
       During well drilling, well completion prior to production, and well treatment or workoyer
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 that 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 also supply 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 firm is hired to build a production
system. The marine construction industry includes firms that 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 provided  primarily by major oil companies, which in turn are supported by a large
and independent service and manufacturing industry.
                                          2-29
-------
2.5    INDUSTRY DOWNTURN AND STABILIZATION 1986-1990

       The low oil prices of 1986 led to a downturn in the offshore oil and gas industry. The
downturn was particularly evident in the decrease of leasing and exploration activities and
reduced the revenues.  Table 2-15 lists the domestic first purchase prices for crude oil (also
called "wellhead prices") from 1980 to 1990.  The nadir was reached in July 1986 when a barrel
of oil sold for only $9.25, and the average price for 1986 was 52 percent lower than the 1985
price. The industry has adjusted to lower prices; note the 866 wells drilled in 1988 (Table 2-14)
and the $20/bbl oil price for 1990 (Table 2-15).
       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 2-2 summarizes OCS leasing activity
from 1980 to 1990. The average bonus bid per tract steadily declined during this period.  The
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
percent of the offered tracts received bids.  In 1986, only 155 tracts—1.4 percent of the tracts
offered, and the lowest  number seen during this period—received bids. 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 were 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, in each sale, twice as many of tracts
 received bids 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
                                            2-30
-------
                                  TABLE 2-15

                         CRUDE OIL PRICES, 1980-1990
Year
                                                       Domestic First
                                                       Purchase Prices*
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
21.59
31.77
28.52
26.19
25.88
24.09
12.51
15.40
12.58
15.86
20.03
     "Current dollars.

Source:  API, 1992.
                                    2-31
-------
 stabilization of crude oil prices at levels exceeding $18/bbl (Hagar, 1987). With oil prices higher
 than they were in 1986, companies are now generating more capital for new investments.
        Lease Sales - Future

        The final 5-year Leasing Plan for 1992 to 1997 was announced in July 1992 (MMS, 1992;
 see Table 2-16).  The plan provides insight on future levels of offshore leasing and exploration
 activity- A notable difference between the 5-year leasing plan for 1987-1992 (OGJ, 1987) .and
 the 1992-1997 plan is the drop in the number of planned lease sales from 37 to 18.  Annual sales
 will still be held for the Western and Central Gulf of Mexico.
                                                                               -\
        Sales in other OCS areas will occur infrequently. One sale is scheduled for the Atlantic
 region (Mid- and South). One sale is scheduled for the Eastern Gulf of Mexico (north of 26
 degrees). Six sales are scheduled for Alaska (Gulf of Alaska/Yakutat, Cook Inlet/Shelikof, St.
 George Basin, Hope Basin, Chukchi Sea, and the Beaufort Sea).  The Gulf of Mexico and
 Alaska, then, are the two most active areas in terms of future leasing. This information, as well
 as the absence  of lease sales in the Pacific, figures in the well and platform projections discussed
 in Section Four.
       2.5.2  Exploration

       The average number of active rigs is one measure of exploration activity (see Table 2-17
and Figure 2-1). In 1986, the industry slumped to half its 1985 levels. The West Coast had no
more than two mobile rigs active at any time throughout all of 1986 (PennWeli, 1987, 86-97).

       An upturn in drilling activity in the Gulf began in the second half of 1987 (see Figure
2-1).  The year ended with a slightly higher average number of drilling rigs than for 1986. The
industry appears to have adjusted to the lower oil prices; the  annual average number of rigs
fluctuates between 126 and 141 for the 1988-1990 period. In  October 1992, there were  151
                                           2-32
-------
                                  TABLE 2-16




                   FIVE-YEAR OCS LEASING PLAN (1992-1997)
Sale#
141
142
143

147
150
149
152
155
158
151
144
157
161
148
153
164
166
159
Area . ,..
Western Gulf of Mexico
Central Gulf of Mexico
Western Gulf of Mexico
i' '•
Central Gulf of Mexico
Western Gulf of Mexico
Cook Inlet/ Shetikof Strait (Alaska)
Central Gulf of Mexico
Western Gulf of Mexico
Gulf of Alaska/ Yakurar
Eastern Gulf of Mexico
Beaufort Sea (Alaska)
Central Gulf of Mexico
Western Gulf of Mexico
Chuckchi Sea (Alaska)
St. George Basin (Alaska)
Mid & South Atlantic
Central Gulf of Mexico
Hope Basin (Alaska)
Sale Date
Mid-1992
Early-1993
Mid-1993

Early-1994
Mid-1994
La'te-1994 "'""'
Earfy-1995
Mid-1995
Mid-1995
Late-1995
Late-1995
Early-1996
Mid-1996
Mid-1996
Late-1996
Late-1996
Early-1997
Mid-1997
Source: MMS, 1992.
                                        2-33
-------
                                 TABLE 2-17

                       ANNUAL AVERAGE NUMBER OF
                  ACTIVE MOBILE OFFSHORE DRILLING RIGS
            Year
Average dumber
of Rigs Drilling
            1981
            1982
            1983
            1984
            1985
            1986
            1987
            1988
            1989
            1990
      147
      154
      137
      196
      188
       94
      100
      141
      126
      135
Source:  Marsh, 1992.
                                     2-34
-------
               Source: Offshore Rig Newsletter, Offshore Data Services, Inc., Houston, TX.
Figure 2-1.     Offehore Mobile Rig Utilization Data, Gulf of Mexico, 1983-1988.




Source:  Drilling Contractor. December 1987/January 1988.
                                             2-35
-------
 mobile offshore rigs in the Gulf of Mexico, and 100 of them were under contract (Offshore,
 1992).
       2.53  Production

       Offshore projects that were begun between 1981 and 1985, when oil sold for $24 to
 $32/bbl, would only have been in their 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 2-11).  The decline in drilling activity in 1986 is 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 made up 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 indicated that oil industry executives believe
 that only Alaska and the offshore region hold promise of potential giant fields within the United
 states (Solomon and Sullivan, 1987).
2.6    REFERENCES

Alaska. 1988. Alaska Department of Natural Resources, Division of Oil and Gas. Five-Year
       Oil and Gas Leasing Program.  January.
Alexander, S.  1988. Telephone conversation between Sarah Alexander (Louisiana Office of
       Mineral Resources, Mineral Board, Production Audit Section) and Mark Lennon
       (Eastern Research Group, Inc.). 23 March.
API.  1992. American Petroleum Industry. Basic Petroleum Data Book.  Volume XII, Number
       2.  May.
                                          2-36
-------
 Baker, R.  1979 A Primer of Oil-Weil Drilling. 4th Edition.  Petroleum extension Service.  The
       University of Texas at Austin. Austin.  Texas, in cooperation with International
       Association of Drilling Contractors. Houston. Texas.
 Boone, P.  1988. Telephone conversation between Peter Boone (Texas General Land Office)
       and Mark Lennon (Eastern Research Group, Inc.).  March.

 CCC. 1988.  Oil and Gas Activities Affecting California's Coastal Zone: A Summary Report.
       California Coastal Commission. December, pages 31-33.

 CDC. 1987.  California Department of Conservation. Division of Oil and Gas. 72nd Annual
       Report of the State Oil and Gas Supervisor:  1986.  Sacramento.

 CDC. 1991a. California Department of Conservation. Division of Oil and Gas. 76th Annual
       Report of the State Oil and Gas Supervisor:  1990.  Sacramento.

 CDC. 1991b. California Department of Conservation. Division of Oil and Gas. Point Fermia,
      . Newport Beach, Offshore Map #OM.

 CDC. 1991c. California Department of Conservation. Division of Oil and Gas. Rincon, West
       Montalvo, Offehore Map #02-1.                           <

 Douglas, R. 1988.  Telephone conversation between Russell Douglas (Alaskan Oil and Gas
       Conservation Commission) and Mark Lennon (Eastern Research Group, Inc.). March.

 Drilling Contractor. 1988.  "Gulf of Mexico Activity Picks Up Momentum," Drilling Contractor.
       December 1987/January 1988.  pp. 9-11.

 Hachenberger, E. 1988.  Telephone conversation between Ed Hachenberger (Florida
       Department of Natural Resources, Division of State Lands) and Mark Lennon (Eastern
       Research Group, Inc.).  22 March.

 Hagar, R.  1987. "Record Deepwater Tracts Draw Bids." Oil & Gas Journal. 17 August,  pp.
    .,-  24-25.    ,       -.,..,,                                      . &

 Hays, M. 1987. Telephone  conversation between Michael Hays (LA State Minerals Board) and
       Maureen F, Kaplan (Eastern Research Group, Inc.). 2 March.

 Litzen, K.  1988. Telephone conversion between Kelly Litzen (Arkansas Department of Natural
       Resources, Division of Oil and Gas) and Mark Lennon (Eastern Research Group, Inc.).
       March.

Lobsenz,  G. 1987.  "U.S. Plan on Drilling Would Open Georges Bank to Exploration," Boston
       Globe. 28 April.    ,

Marsh, T. 1992.  Telephone conversation between Tom Marsh (Offshore Data Services,
       Houston, Texas) and Joe Dawley (SAIC).  5 October.
                                         2-37
-------
McRoiy, R.  1987. Telephone communication between Robert McRory (Alabama Department
   '    of Conservation, State Land Division) and Maureen F. Kaplan (Eastern Research Group,
       Inc.)  2 March.

McRory, R.  1988. Telephone communication between Robert McRory (Alabama Department
       of Conservation, State Land Division) and Mark Lennon (Eastern Research Group, Inc.)
       March.

MMS.  1987.  U.S. Department of the Interior. Minerals Management Service. Federal
       Offshore Statistics;  1985. MMS 87-0008.

MMS.  1989.  MMS Map #89-0100, Southern California Area, U.S. Department of the Interior,
       Minerals Management Service, December 1.

MMS.  1990a.  U.S. Department of the Interior. Minerals Management Service.  Alaska Update:
       September 1988 - January 1990.  MMS 90-0012.

MMS.  1990b.  U.S. Department of the Interior. Minerals Management Service.  Production
       Record by Platform: 1989. MMS 90-0071. September.

MMS.  1990c.  Pacific Update August '87 - November '89. US. Department of the Interior,
       U.S. Minerals Management Service, MMS 90-0013, Tables 11 & 13.

MMS.  1991a.  U.S. Department of the Interior. Minerals Management Service.  Federal
       Offshore Statistics;  1990. MMS 94-0068.

MMS.  1991b.  U.S. Department of the Interior. Minerals Management Service.  Mineral
       Revenues; 1990. Royalty Management Program.

MMS.  1991c.  U.S. Department of the Interior. Minerals Management Service.  Mineral
       Revenues: 1980-89. Royalty Management Program.

MMS.  1992.  U.S. Department of the Interior. Minerals Management Service. "Interior
       Secretary Affirms 5-Year Management Program for Offshore Oil and Gas Leasing."
       News Release. 1 July.

Offshore.  1992.  Weekly Newsletter.  Offshore Data Services.  Houston, Texas.  23 October.

OGJ. 1987.  "Interior's Final 5-Year Plan Seeks to Slow Pace of Offshore Leasing."  Oil & Gas
       Journal. 4 May. page 26.

PennWell. 1987. Offshore Yearbook:  1987.  PennWell Publishing Company. Tulsa, Ok.

Phillips, E. 1987. Telephone conversation between Ed Phillips (Alaska Dept. of Natural
       Resources) and Maureen F. Kaplan (Eastern Research Group, Inc.). 2 March.

Sharlot, S. 1987. Telephone conversation between Sarah Sharlot (Texas General Land Office)
       and Maureen F. Kaplan (Eastern Research Group, Inc.). 5 March.

                                         2-38
-------
Solomon, C. and A. Sullivan. "Major Oil Firms Intend to Boost Spending in '88," Wall Street
       Journal. 10 November,  page 4.

Willard, A. 1987. Telephone conversation between Al Willard (California State Lands
       Commission) and Mark Lennon (Eastern Research Group, Inc.).  31 March.

Willard, A. 1988. Telephone conversation between Al Willard (California State Lands
       Commission) and Mark Lennon (Eastern Research Group, Inc.).  29 March.
                                         2-39
-------
-------
                                  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 conditions.
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 33 presents a ratio analysis of industry segments to
identify how key financial ratios  have changed over time 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 record low oil prices in 1986 severely impacted the financial health of
the oil and gas industry. By using 1986 financial statements for typical oil and gas companies in
the analysis,  the impacts of incremental pollution control costs will not be underestimated.  The
industry financial ratios (Section 33) and representative financial statements (Section 3.4) are
used as the basis for the economic impact analysis presented in Section Eight.
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
                                          3-1
-------
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 consists of 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 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,
diversified into other areas such as mining and development of alternative (nonpetroleum)
energy sources.  The major oil companies are oriented toward oil production, while the
independents, by contrast, are oriented toward the production of natural gas.

       The major integrated oil companies generally are 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
(Smith, 1986).  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 that provide support services  to offshore drilling
rigs and platforms.  Table 3-2 lists some of the larger participants in these support activities.

       Although all of the companies involved in offshore oil and gas development could be
affected by BAT and NSPS regulations,  the production companies are directly responsible for

                                            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
Amoco
Atlantic Richfield
Chevron
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 Ohio (Subsidiary
 of British Petroleum)
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
WilsMreOil
       "A sample of the independent companies that are active offshore.

Source:    S&P, 1982a; Smith, 1986.
                                         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)
Specialty 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
                                 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)
        McDerraott Inc.


        Service Vessel Suppliers

        Jackson Marine (subsidiary of Halliburton)
        Newpark Resources
        Offshore Logistics
        Tidewater Marine, Inc.
        Zapata Corp.


        Contract Diving Services

        Oceaneering International
Source:  S&P, 1986c; PWell, 1986.
                                           3-5
-------
having BAT and NSPS systems in operation and 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 a
decrease in demand for their services.
       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
concentration of offshore petroleum production than offshore gas production; (b) the industry
    «
concentration ratios for offshore oil and gas have decreased since 1973 for the 8 and 16 largest
company segments, respectively; (c) the 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,
respectively, 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.
       The four principal areas of offshore oil activity in the United States are 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 risk 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
                                            3-6
-------

























m
&d
S
{?
^1*

U


CO
J3
_^
@
1*3


H
H


C
O

fjjj
O
«? 00
i 1
•<3 t«
H 0
|3


OB

z
5
>^<
t*J
g
g
1
o
u
b

ftn

1
»J
o


















*?-»
CO W
cq w

(V 5

i^j Qi
o O
o tJ
d


















£ w
CO fv]

§ §
*5 p.
H
o rj
in












M W
S B
S
vo Q












H co
co w
U M
U Pi
PI 3
co o














CO
m
rH

O
CO
m
H

00
r-
m
rH
vo
r*-
en
rH


ro
r-
m
H



H
CO
m
rH

0
CO
m
H


CO
r-
m
H

V0
r-
m
H
ro

m
H
H
CO
m
H
o
CO
m
H
CO
p*-
m
rH


vo

m
H

ro
r-
H
H
CO
m
rH
0
CO

iH

CO
r-
m

VD
m
H

ro
t-
- m
H










mm H r-
co o mo
mm m m

d d m co
m rH co H
. m m m m

co H m in

co o co m
mm m co
•«* co d d

mm mm
m co m co


dm o d

mm mo
m co mm



in ro dm
«* ^ o t-
m co m t—

r- H H <•

ro in o m
m co en t—


vo ro d vo
*3« tj< d CO
m co m t—

ro H vo d

vo d mm
m oo co r»
ro r"* m co

vo ro ro H
m co m co
tn co m ro

CO H VO VO
vo E-- vo in
o d m in
m d en co
vo r- vo in
vo vo co in
r* o r- vo


ro c- d vo

ro o vo ro
co r> t- vo

o co vo in
vo d d in
co t> r- vo
co d in ro
vo ro H vo
*P in •* ro •
TP in o en
co ro d vo
TI* in *P ro

H vo m co
d r* d **
in 4* in ^

TP en o in
r* o co *p
in in ^ ^
fl)
4J m in mm
d vo tn in *#
i§

g
«8 £ d?
B *"" *""
B U U 09
fl> -H -H 0)
Q) fH — , iJ — AJ -
6 O  vo
c-* VD vo in


t* VD H *»

r* * wo
t* vo r*- tt»

Tf d co in
mm H <*
co c*» r* vo .
^t en co co
m H in d
^ in mm
co in in en
vo o ** *p
^< in mm

d H co co _
. . . . -o
in r- vo H o>
g
M H HO C
•* r- u> •* B

."* "* |
4J O\ *J* ' C^ O\ Q
BJ • • » •
a co ** m t^ T
a u> in f v a
•8 -r

O f
•s 3? 3? "c
fl T
So u ~
 VD co r*
co m ^ m
rp O VO m
H f" mo
^ m m m

H ro d co
in ^ m VD

It- ro vo o
^p m m H
mm ^ ^p

m H en co
VO 0 VD O



5 S

u o
•H -H

& J CQ JJ JP a
4J Q) O B fl) O
HO O O
O J3 rH H J3 rH
K*  S r-
g 0 d 1 H
2 o .
g (DM VO

£J (0 iH
u CO)
* 0) J3 to -
« S13 SP
2 a -H en
Pi • 4J H
^ Q) CO M -
. A m 4) to
£ 0) 4J C
S .-3 S g S
r? u .e u>
•" to e» in 43
0 "° -S ^o IH

R u G ®
® OJ U 0 S

*tt p cj _ Q jq

to
Q)
•H
I 5 |
o o
Sa ca
3-7
-------
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.
3.2    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-wide
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
decreased in 1979, however, and dropped sharply over the next 4 years, but 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
increased hi 1985 and 1986.  In 1986, prices fell to levels as  low as $12 per barrel before
rebounding to approximately $19 at year's 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 generally increased, with large jumps
in the 1979-1982 period.
   j
       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
                                          3-8
-------
                                TABLE 3-4

                      TOTAL U.S. PETROLEUM DEMAND,
             U.S. AVERAGE CRUDE OIL WELLHEAD PRICE, 1980-1990
YEAR
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
DOMESTIC
CONSUMPTION
(MILLIONS
BARRELS /DAY)
17.06
16.06
15.30
15.23
15.73
, 15.73
16.28
16.67
17.28
17.33
16.99
AVERAGE
CURRENT
DOLLARS
21.59
31.77
28.52
26.19
25.88
24.09
12.51
15.40
12.58
15.86
20.03
WELLHEAD PRICE
CONSTANT
DOLLARS*
24.04
32.42
28.52
25.85
24.96
23.34
12.49
14.98
11.77
14.14
17.22
Source:   API, 1992, Section VI, Table 1.

     "Constant 1982  prices calculated using Producer Price  Index, 1982 = 100.
                                    3-9
-------
                                  TABLE 3-5

                       TOTAL U.S. NATURAL GAS DEMAND,
             U.S. AVERAGE NATURAL GAS WELLHEAD PRICE, 1980-1990
YEAR
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
DOMESTIC
CONSUMPTION
(TRILLION
CUBIC FEET)
19.88
19.40
18.00
16.83
17.95
17.28
16.22
17.21
18.03
18.78 •
18 . 71
AVERAGE
CURRENT
DOLLARS
1.59
1.98
2.46
2.59
2.66
2.51
1.94
1.67
1.69
1.69
1.72
WELLHEAD PRtCB
CONSTANT
DOLLARS"
1.77
2.02
2.46
2.56
2.57
2.43
1.94
1.63
1.58
r.si
1.48
Source:   API,, 3.992, Section VI,  Table 2; Section XIII, Table 5.

     •Constant 1982 prices calculated using Producer Price Index, 1982
                                                                     100.
                                   3-10
-------
 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, drove
 prices lower still.  The decreasing 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.
       3.2.2 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 from 1974 to 1984.  The 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 (reflecting 1981 oil prices) 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.
                                            3-11
-------
            in
            (S
            at
             •

            at
                              vo
                                                            in
 m
 co
            in
                                                            in
co

                                                            0)
                                    3-12
-------
«







*
n
2
oo
9\
^H
CO
o

§
3
h^
1
1
s
,_;
£
O
CO
d
1
o
S
CO
1






EH
W
O •
O EH
fe
> W v>
EH
W P
is o
o
0 PS O
> H itt-
rf CU •- -


SB
EH
PH P
SJ | ^
• EH
0 PS fe
jrf p[
Q
H
J W i4
< iJ 1-3
EH t-q H
o a PS
EH S Q
M
H
2 °
dp S|
PJ M 0

W
ill
Q
W h)
0 W J H
tfc O & O
Q
W iJ
O J J M
% O ^ Q






VO !*• rH On
vo oo P) in
r-> rr P) vo
O 03 CM 00
P) PJ «* P)


«* rH PJ VD
CM VO O O
O r~ CM en
PJ PJ ^l1 PJ




en rH o ^J*
CM t^ CO O
00 P" On rH
on on en o



CN VO «* O
r~ r» vo r»
CM «* «3- CM



* dP dP dP
O f» r-- rH
** n P) •*


= H VO VO 00 •
rH ^- P) H
in in in in


«* in CM P>
'I' rH «* en
"* tn *f CM


t* in vo • on
H rH 00 in
PJ >* <• 5j«


O rH CM P)
00 CO 00 00
on on on on
rH rH H rH



PJ
CM
in
PJ


vo
PJ
in
PJ




in
0
O



rH
CM



dP
O
"


CO
VO
in


CM
PJ


vo
oo
•<*


•<*
00
on
rH



PJ
VO
en
PJ


PJ
o
*




CM
O



r-
CM



dP
VO
**


rH
f-
in


o
PJ


Of>
vo
PJ


in
oo
on
rH



00
CM
CM
00

P)


vo
oo
on



in
a\
CM


VO
on
oo
CM




0
vo
o



on
O
t-



dP
on



PJ


CM
rH


CM
CM


00
on
rH



00
VO
00
oo
CM


CM
rH
rH
PJ




VO
r-
r-
o



VO
VO
- oo



dP
t-
m


rH
en


CM
on
rH


PJ
03
rH


00
00
on
rH



O
on
00
O
PJ


on
rH
PJ




o
in
PJ
0



vo



dP
on



in
vo


CO
CM
CM


00
in
rH


on
oo
on
rH



0
VO
rH
PJ


CM
rH
rH
PJ




CM
on
00
on



0



dP
rH
in


on
tn
PJ


on
o
CM


vo
PJ
rH


o
on
on
rH



















o
*"*
0)
rH
EH
••
H
H
H
o
•H
Q)
01 W
n) -
rH CM
•H en
O en
*O rH
-P
C H
0) P*
V) 
-------
        3.2.3 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 relative offshore natural gas
 production has increased. 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 hi  1975.
       3.2.4 Financial Trends

       During the 1970's to mid-1980's, the oil industry experienced dramatic market changes
that 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 (CMB, 1981; CMB, 1982; CMB, 1983; CMB, 1985a; CMB, 1985b;
and CMB, 1986). Most of the firms included are major domestic integrated companies, two are
large domestic independent companies and several are refiners or 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 are
positively correlated with crude oil price increases and worldwide economic cycles.  The
companies experienced large increases in revenues and net income following the price increases
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
                                          3-14
-------
                           TABLE 3-8

   DOLLAR VALUE OF ANNUAL OIL AND GAS PRODUCTION 1980-1990
               (IN BILLIONS OF CURRENT DOLLARS)
OFFSHORE PRODUCTION

YEAR
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
NAT-
URAL
GAS
8.5
11.0
13.2
11.7
14.0
12.0
8.9
8.5
8.7
8.8
9.4
OIL AND
CON-
DENSATE TOTAL
7.9
12.2
11.8
11 . 2
12.1
11.0
5.8
6.7
5.5
6.5
7.9
16.4
23.2
25.0
22.9
26.1
22.5
13.8
15.2
14.2
15.3
17.3
NAT-
URAL
GAS
23.6
29.0
32.3
31.9
33.9
31.1
24.7
20.4
21.4
21.7
22.2
ONSHORE PRODUCTION
OIL AND
•CON-
DENSATE TOTAL
57.8
87.2
78.3
71.9
72.0
67.9
34.3
40.2
32.0
37.5
45.9
81.4
116.2
110.6
103.8
105.9
- 99.5
58.9
60.6 .
53.4
59.2
68.1
OFFSHORE
PRODUCTION
REVENUES
AS A % OF
TOTAL
16.8
16.6
17.3
18.1
19.8
18.4
19.0
25.1
26.6
25.8
25.4
Source:   API, 1992, Section I, Tables 3 and 6.
                                3-15
-------
             0\
















$
js
j— 1
<
§3
8
1
0
&3
(•W X"S
pj %
o o\

*"2 *^
§ ON
tQ^
rt
o
t*
wa
I
O
g
i
























A
5*

s
0
"1
a
o>
1


«_
g
T-

O
§
OS
N-
1-
1
fc
os
•o
fe
1


1

i


















CM O
N- in •*
os «— CM
to '

so o in
10 CM ?
o «- in
M o «-
•* *": *.
m CM
N- to so
in • •
CM CM
• i
VI ** in
NO" os so
CM *—
t
tO CM t>-
S in jf
to in o
S ^ £3
to j^
N. 0 CM
to uj •*
f. •* 0.
»O *"" O"»
CM KJ tO
in in o»
~ ?: a
1

in •» CM
CM <) O

>* N.
to • '

0) C
> 0 E O 10 g
_,n^ «^ o —















i- O
sf in in
in to «o


CM CO
° 5 ^
CM fO
*•• *t t
in -T Is-
to o>
§ m o»
O CM
0 J- J^
»O N. ^

•^ >»
in so JM

*~
CO p
in ^3- r*-
to o>
•* o> t;
to CM CO
0 0
S CM R
co co
• •
CM CM O
CM S S


CO Os
CO CM O
CM CM CO

CM SO
^ vt O
CM <- SO
O5
f,
•
O-^ co^'Q--' 10^*001
'o uM to x x «» coxxto
|««4.<> CJIJJUJs^ O1IJUJCOM-















Os in
eo to


CO CO
*~
»- in
^3 Os
CM in
CM sO
CM in
~

CO sQ
a a
sO ts-


~a- CM
CM ?
o o
«* <-^
CM «-
CM r-
tO sO
CO s±
to so
CO so
M sd
CO ff
CM so


CM 0
Os O

in so
in co


§»« cS
v> O xx
ex c to
C. 4J l~ 4-»
3"- 3 0>
4J 3 *« tO
U IT 
(U CO HI i^>
o o — * — *
"'m ^ ro
§ D. t. fe
3J O Q.
8"- g o
4-» O Q.

C g-^ O
11^ 3 C *Z
S*21 g- «
Igl Z
g-_.| £
O 3E ** tfi
t_.| S
||g |
*Si 5
«X « CO
*W «•**— hi
J; c o u,

S rao *~
" o-o .»-

2 en. co Q*
«*Z CO 4J

"if S
'£ _J L- m
g CO  «• in
•So ~ °°
« a • «- 2:
*• C— a °
B u jc — • to 5>
^ to co E 3.
qi ^^ go g
,;E 4-» >* IK — ' SP
oi — ' c D o o>
to O- ^ g_ TJ T3 *~
'c o! S o "g c "^
8- (u g1-- '> to u °
""111 ^1 "3 8
i. o 'c to o
u. a. => 
                                                              3-16
_
-------
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 (Keenan, 1981). The pattern of financial performance
that emerges from a review of financial data from 1973 through 1985 closely tracks 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 of which 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
 (Beck and Smith, 1987). Table 3-10 shows the effect of these changes on principal financial
                                            3-17
-------
                      «
                                 in
                                 CO
                                 o\
                                 CO
                                 CO
to
9
a
                                                           in
                                          ro

                                          oo
                                          in
                                          m
                                          vo
      in
                                                     in
                 ro
                                                           in
                                ro
                                                                    ro
                                          in
in
                                                     ro
                                                     in
\D
•G
in
                                                     vo
                                                     in
                                                     in
                 in
                                                           cr»

                                                           \o
                                                           in
                                cr>

                                in
                                                                         ro

                                                                         CTl
                                                     •H
                                                                         <*>
                                          m
                                          m
                                               H

                                                           a a)
                                                           -H
                                                                    g     g
                                                                                  HI
                                                                               O<
                                                                                0)  C C
                                                                                   9
                                      m
                                      m   «
                                      d)  *
                                                                                  m O
                                      (0 -H W
                                                                                     •d
                                                                                0) Tl
                                                                                        m 73
                                                                                  S aj -S1 §
                                                                                U H
                                                                                        i-H  4J
                                                                                           CO
                                                                                        Oi
                                                                                        -rl 0
                                                                                C  0) Q) N
                                                                                0)  U
                                                                               •H -H
                                                                                     0)

                                                                                     O 0) ro
                                                                                        as C
                                           *  Tf  O
                                           
-------
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 tracked 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 from 1979 to 1981
was financed primarily through internally generated funds and 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 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
                                           3-19
-------
                                  TABLE 3-11

                    DEBT/CAPITAL RATIOS (%) FOR MAJOR
                 INTEGRATED AND INDEPENDENT COMPANIES
YEAR
                             SAMPLE OF
                           MAJOR INTEGRATED
                            OIL COMPANIES8
  SAMPLE OF
 INDEPENDENT
OIL COMPANIES"
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
     "Sample 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.

     bSample 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:   S&P, 1982a and 1986a.
                                      3-20
-------
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 7 percent 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.
3.3    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, given below,
of the majors and independents highlights these recent trends.
       3.3.1  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), and 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 petroleum companies and by petroleum
company executives to  formulate exploration, capital expenditure, and production strategies. The
expected change in these financial ratios that would occur under each alternative regulatory
                                          3-21
-------
 approach is estimated in Section Eight of this report. Thus, the ratios presented here provide
 the basis for part of the economic impact assessment that 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.

       The Debt/Capital Ratio1 measures a company's level of debt or leverage.  While some
 debt can be 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/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, deferred
income taxes, investment credits and minority interest).  The values in Tables 3-19 and 3-23 are
therefore not directly comparable to those in Tables 3-26, 3-22, and 3-32. Values within a given
table are calculated on a consistent basis.
                                           3-22
-------
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.
       3.3.2 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 are 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 EPA 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 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
                                           3-23
-------
                                         TABLE 3-12

                                 RETURN ON EQUITY (%)
             MAJOR INTEGRATED OIL COMPANIES:  19 COMPANY GROUP
                                         (1977-1985)
RETURN OH
COHPAHY YEAR
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oi I (Texaco)
Gulf Oil (Chevron)
Kerr-HcGec
Mobil Oil
Hurphy Oil
Occidental Petroleum
Shell Oil (Royal Dutch Petroleum)
Standard Oil of California (Chevron)
Standard Oil of Indiana (Amoco)
Standard Oil of Ohio
Sun Company
Texaco
lffUU»Ml
ulivcav
Unweighted
Coepany Average
1977
25.5
10. 2
17.9
22.0
12.8
12.9
10.5
12.4
12.6
11.9
18.3
14.7
13.9
15.7
10.1
14.8
10.1
14.6
LJIT - ^i
14.7
1978
14.0
8.2
16.8
15.6
14.0
11.6
10.5
11.3
13.1
10.7
0.5
14.1
13.9
15.5
21.8
13.7
9.0
15.2
•aT i i 1 1
13.9
1979
35.1
20.7
21.2
16.4
20.2
19.0
16.1
13.9
20.7
21.0
52.9
17.0
20.4
19.2
45.9
20.7
17.5
18.0
23.1
1980
26.0
22.3
25.2
17.4
23.7
23.1
14.3
14.3
23.8
24.9
41.4
20.4
23.6
21.8
47.3
18.1
19.4
20.1
23.7
1981
8.9
14.2
21.3
16.8
20.6
19.2
12.9
14.8
17.5
22.2
26.7
19.6
20.0
19.1
37.0
23.8
17.9
20.8
19.5
EQUITY
1982
6.7
9.2
18.3
10.8
14.7
14.2
9.4
13.1
9.6
18.7
2.6
10.6
10.6
16.6
28.5
10.7
9.2
18.1
13.1

1983
8.1
9.6
15.0
MM
17.2
--
--
7.0
10.5
14.0
4.2
14.9
11.6
15.7
19.7
8.6
8.5
12.6
11.1


1984
6.7
7.2
10.9
8.2
19.0
--
--
3
9
11
11
16
10
17
18
10
1
12
11


.7
.2
.8
.9
.8
.6
.5
.1
.2
.8
.9
.1

1985
NH
NM
4.3
NM
16.8
--
--
7.9
7.5
7.9
8.3
12.2
10.2
16.2
3.8
9.9
9.1
8.9
8.1

1986
NM
NM
11.7
NM
16.7
--
--
NM
9.2
NM
4.2
6.2
4.6
6.6
NM
7.3
5.3 .
10.5
NC
NH * Hot meaningful, negative net income for that year.
NC = Hot calculated.  The large number of firms reporting a net loss for 1986 make this average meaningless.

Source:  S&P, 1982a and 1986a; Beck,  et al. 1987.

Hote:  1986 data may not be strictly  comparable to 1977-1985 data.

    'Simple average of the ratios for the sample.
                                              3-24
-------
P«(





%
o  5f£
J_  •< r-t
              CA
















!H
H
H
D
O

S5
O

J2
3
D
1


















S3 o
W A
T §
rH SC
VO
oo
en

in
CO
cn
rH

*3*
co
en
rH


P>
CO
cn
rH


O!
oo
cn
rH

tH
00
cn
H
o
CO
en
tH
cn
cn
rH



CO
en
rH

^
rH






1


t-
"?
tH

•
co
•o
PJ
•
H
H
•D

•
rH


VO
*
01
rH


01
•
01
rH

CO
•
(O
tH
•>*
•
01
0»
o
•vi-
oi



01
PI
rH

co
rH

id
s
id
A
e
*
4|
0) ft
01 3
id O
A U
O O

in
^
H
t~
•
"*

in
•
o
rH

cn
•
PI


^*
•
PI
tH


O]
•
in
H

CO
•
cn
rH
CO
•
o

01



cn
PI
rH

f.
*
rH

>t
Of
g
o
-------
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 EPA's sample peaked in 1980. Note that the Return on Assets
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 from 1979 to 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 EPA 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 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
                                          3-26
-------
                                        TABLE 3-14
                                RETURN ON ASSETS (%)
           MAJOR INTEGRATED OIL COMPANIES:  19-COMPANY EPA GROUP
                                         (1977-1985)
RETURN OH ASSETS
COMPANY YEAR:
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
Unocal
Unweighted
Company Average*
1977
6.0
4.6
6.8
9.4
6.5
8.0
5.4
6.9
5.1
3.7
5.0
9.5
8.3
7.1
8.4
2.3
6.6
5.0
7.0
6.4
1978
4.2
3.5
6.7
6.7
6.9
7.4
5.4
6.1
5.2
3.2
0.2
11.1
8.4
7.0
8.0
5.0
6.8
4.4
7.3
6.0
1979
11.3
8.0
8.9
7.0
9.5
11.2
8.2
7.3
8.0
6.1
10.9
11.5
9.1
10.2
9.6
13.4
10.2
8.1
8.7
9.3
1980
9.6
9.2
10.7
7.5
10.7
12.2
7.8
7.1
9.3
7.2
11.1
11.7
8.8
11.9
10.4
17.0
7.8
9.1
10.1
10.0
1981
3.5
6.4
9.1
7.5
9.4
9.6
6.5
6.8
7.2
6.4
9.0
8.3
9.0
10.4
8.9
14.0
9.5
8.7
1LO
8.5
1982
2.7
4.7
8.0
4.8
6.7
7.2
4.6
5.8
4.0
5.5
1.3
5.5
7.7
5.8
7.3
11.3
4.5
4.7
10.0
6.0
1983
3.3
4.3
6.9
m
7.9
--
--
3.1
4.2
4.6
3.5
5.7
5.9
6.7
7.5
9.3
3.7
4.5
Ld
5.2
1984
2.7
2.9
5.0
4.2
8.8
—
--
1.7
3.3
4.3
4.7
5.4
7.0
5.1
8.5
8.8
4.3
0.9
7.2
5.0
1985
MM
NM
1.6
NH
7.4
--
--
3.7
2.5
3.0
3.8
3.8
5.4
4.1
7.7
1.7
4.1
3.3
3.1
3.2
1986
NM
NM
2.8
NM
7.7
--
--
NM
3.6
NM
1.0
1.8
3.4
2.1
3.2
NM
3.3
2.1
1.7
NC
NM = not meaningful.
NC = Not calculated.  The large number of firms reporting a net loss for 1986 render this
    average meaningless.
Source:  S&P, 1982a and 1986a; Beck, et al. 1987.
Note:  1986 data may not be strictly comparable to 1977-1985 data.
    'Simple average of the ratios for the sample.
                                            3-27
-------
in
to

9
               o\
                               CO
                               CO
                               CO
                                                 US
                                                 00
                                                 en
                                                 CO
                                                 en
                                                 oo
                                                 en
                                                 en
                                                 oo
                                                 en
                                                 CN
                                                 co
                                                 oo
                                                 01
                                                 co
                                                 01
                                                 en
                                                 t-
                                                 en
                                                 oo
                                                 r-»
                                                 en
                                                O
                                                                   vo
                                                                    •
                                                                   vo
                                                                          in
                                                            o
                                                           en
in
 •
co
                                                                   in
                                                                   vo
                                                                   vo
en
 •
en
              CM
                •
              vo
              CN

                •

              VO
              en
                •
              vo
en
 •
co
              en
                •
              en
vo
 •
CO
                                                                                    CO
                                                                                    vo
                                                                                     vo
       VO
                                                                   VO
                         VO
                          •
                         VO
                                                                                    vo
                                                                          •a
                                                           en
                                                           W
                                                                          -H
                                                                          -  -H

                                                                          3 °
                                                                          en
                                                                                    •O
                         as
                         w
                             VD
                             oo
                             en
oo
en
oo
en
                                                                                               •o
                                           oo
                                           en
                                                  vo
                                                  co
                                                                                                              P4
                                                                                                              m
                                                                                                              co
                                    CN
                                    CO
                                    en
                                                                                                              til
                                                                                                              ra
                                                                                                                     eo
                                                                                                                            in
                                                                                                                            co
                                                                                                                            co
                                                                                                                            en
                                                                           •a
                      •a

                      •o
                                                                                                                                Oi
                                                                                               CO
                                                                                    3-28
-------
                                  TABLE 3-16

                                CURRENT RATIO
          MAJOR INTEGRATED OIL COMPANIES?  19-COMPANY EPA GROUP
                                  (1977-1985)
1977 1978 1979 1980 1981 1982 1983 1984 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*
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
1.7
_ - *-
1.5
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
1.7
1.4
1.3 1.4 1.3
1.5 1.5 1.4
1.6 1.2 1.2
1.9 2.2 2.0
1.3 1.4 1.3
1.2 0.9 0.9
1.3 1.3 1.1
1.7 .1.4 1.7
1.1 1.1 1.1
1.1 1.2 1.1
1.1 1.1 1.1
1.3 1.2 0.9
1.0 1.0 1.0

1.4 1.5 1.4

1.3 1.1 1-0

2.0 1.2 0.7
1.3 0.9 1.1
1.5 1.7 1.7
1.7 1.3 1.1
1.4 1.3 1.2
1.4 1.5 1.4 1.3
1.4 1.2 1.2 1.1
1.2 1.3 0.9 0.6
1.7 1.4 1.2 1.1
1.2 1.2 1.1 0.9
1.0
1.1 — —
1.5 1.3 1.3 1.2
1.0 1.1 1.0 1.0
1.1 1.2 1.2 1.2
1.1 1.0 1.4 1.2
1.1 1.0 0.9 1.0
1.0 1.6 1.4 1.4

1.3 1.4 1.0 1.1

1.1 1.2 1.1 0.9

0.8 1.0 0.8 1.1
1.1 1.2 1.0 1.2
1.5 1.5 1.2 1.0
1.2 1.3 1.2 1^4
1.2 1.3 1.1 1.1
Source:   S&P, 1982a; S&P, 1986a.

     "Simple average calculated from the ratios  for all companies in the sample.
                                       3-29
-------



























to
1
H












































g
to
CO
i
RENT RATIO
F AVERAGE YI
go
R 55
Qo
cn
S
CM
8


































3
M
,^j
^
8
sa
o
INTEGRATED
1977-1985)
(A^
0
"3
*£l
ta
O
I

3
CO
^t


































s
1
§












53 o
pq (02
l W
rH <


(O
oo
on
rH

in
00
cn
rH
<*
00
cn
rH
CO
CO
cn
rH
CM
00
cn
H
rH
CO
cn
H
o
co
cn
rH

cn
cn
rH
co
cn
rH
t*-
cn
i-H





cu
D
O
K
S







m.
rH



rtj
Si



H
•
rH

rH
*
rH

CO
rH
01
rH
rH
CO
rH


«*
rH

<•
rH
in
rH



"ft
g
o
H
O
&
a
*
8
cn
rH

(3j
pi
H







ro
rH



ro
•
rH


rH
•
rH

•o
OJ
•
rH

CO
H
04
rH
CO
rH
rH


**
rH

ro
rH
^
rH


&
1
VI
hattan G
I
0)
m
id
£
o







01
H



01
•
H


0
•
rH

O
t
rH

rH
rH
rH
rH
O
rH
rH
rH


' ro
rH

in
rH
in
rH





o
rH
•H
45°
.p ij
m 0)
0) -P
€ (d
Q &
0)
ID 43
- C
CU H

rH

^
A
01
oo
cn
rH
(C
(it
w
o




iJ
O
c
0)
VI
n)

m
0)

rH
id
in
00
cn
rH

•O
C
cd
^?
00
a>
rH
4J
cd

4J
means
m
Income" entr
 ^
^2
•rl
Vl
^J
(0
3-30
-------
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 compare 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
EPA'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 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
                                            3-31
-------
                       TABLE 3-18

                 DEBT/CAPITAL RATIO (%)
MAJOR INTEGRATED OIL COMPANIES IN 19-COMPANY EPA GROUP
                        (1977-1985)

Amerada Hess
American Petrof ina
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
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.
45.
34.
38.
13.
4.7
14.
16.
25.
40.
39.
16.
18.

19.

23.

65.
19.
24.
28.
27.
0
8
6
4
3

1
6
6
5
4
3
4

7

5

4
4
8
6
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
40.3
31.4
26.2
37.0
10.5
—
—
27.1
24.4
15.1
34.0
23.3
19.1

10.6

20.1

29.2
24.8
14.1
17.6
23.8
1984
40.1
39.1
26.9
28.1
11.6
—
—
23.5
40.9
14.3
43.3
26.0
17.3

43.4

17.3

26.4
25.3
41.0
15.3
28.2
1985
40.
40.
43.
40.
10.
—
—
23.
35.
13.
47.
64.
14.

28.

16.

25.
20.
31.
6
8
9
7
4


4
8
7
6
3
6

9

9

4
7
6
64.1
33.
1
Source; SSP, 1982a and 1986a.
•Simple average

calculated


from the


ratios
3-32
for all

companies in


the sample.


1
-------
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 (because, for example, firms are not required to report reserves of
minerals other than oil and gas, and estimates of proven reserves and of future development and
production costs are uncertain), but will nonetheless facilitate a much more realistic assessment
of a firm's real wealth than that provided by the standard financial statements.

       A  rough asset valuation for six major integrated U.S. oil companies (Amoco, ARCO,
Exxon, Mobil, Shell, and Texaco) was  performed based on the supplementary reserve data
published in each firm's 1986 annual report. Total gross assets were calculated 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). This calculation provides an alternative estimate of corporate value
that relies more upon the mineral reserves than the traditional book value.  This valuation
approach  is used to draw attention to the fact that financial statements do not necessarily reflect
the corporate wealth for oil and gas companies.

       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
                                            3-33
-------
                                            TABLE 3-19
                                    RETURN ON EQUITY (%)
              INDEPENDENT OIL COMPANIES IN EPA 17-COMPANY SAMPLE
                      QUANT.  UNITS
                                           PRICE  UNITS
                                                              CONVERSION  UNITS
                                                                                           VALUE
GROSS ASSETS
RESOURCE RESERVES
Oil
Nat Gas Liquids
Nat Gas
Coal
Sulfur
Carbon Dioxide
Phosphate
TOTAL GROSS VALUE
CURRENT ASSETS


. 20,146
876
103,9999
5,400
8,293
7,673
132,000


HHBbl
HHBbl
Bcf
HHtons
Htons
Bcf
Htons


$15.00
$9.83
$2.50
$22.50
$100.00
$0.45
$21 .50


/Bbl
/Bbl
/Mcf
/ton
/ton
/Hcf
/ton


Gross
Gross
Gross
Gross
Gross
Gross
Gross


• 1,000,
1,000,
1,000,
1,000,
1.
1,000,
1.


000
000
000
000
000
000
000


bBL/mmbBL
Bbl/HHBbl
Hcf /Bcf
tons/HHtons
tons/Htons
Hcf /Bcf
tons/Mton
OF RESOURCES










$302,
8,
259,
121,

3,
2,
$699,
50,


190,
608,
997,
500,
829,
452,
838,
416,
022,


000,000
965,517
500,000
000,000
300,000
850,000
000,000
615,517
000,000
    TOTAL GROSS VALUE OF ASSETS

COSTS AND LIABILITIES
    Total Liabilities
    Liquidation of Preferred Stock
    Future Oil/Gas Production and Development Costs
    Future Production/Development Costs, Other Comnodities
    (75X of Gross Value)
TOTAL COSTS AND LIABILITIES

NET ASSET VALUE
  $749,438,615,517


($119,952,000,000)
     (128,751,000)
 (183,905,000,000)
  (96,465,112,500)

 ($400,450,863,500

  $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: EPA estimates based on values reported in the 1986 Annual Reports of six oil  companies specified in
the text.
                                                3-34
-------
estimated to be $280 billion. Subtracting these totals from 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 earnings (S&P, 1986a), 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.
       3.3.3 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 1983 is due solely to the entry of Pauley Petroleum. The
                                           3-35
-------
                                TABLE 3-20

                           RETURN ON EQUITY (%)
          INDEPENDENT OIL COMPANIES IN EPA 17-COMPANY SAMPLE

Apache Corp.
Cabot Corp.
Conquest Exploration
Damson Oil
Hamilton Oil Corp.
Helmerich & Payne
Howell Corp.
Lear Petroleum Corp.
LA Land S Exploration
Mitchell Energy S Dev.
Noble Affiliates, Inc.
Pauley Petroleum
Plains Resources, Inc.
Pogo Producing
Sabine Corp.
Triton Energy Corp.
Wainco Oil Corp.
Unweighted Company Average*
1981
14.0
19.6
NH
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:   SSP,  1986a.

     'Simple average calculated from the ratios of the sample.

                                      3-36
-------
                                TABLE 3-21

                          RETURN ON ASSETS (%)
          INDEPENDENT OIL COMPANIES IN EPA 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.
•a
Pogo Producing
Sabine Corp.
Triton Energy Corp.
Wainco Oil Corp.
Unweighted Company Average*
1981
6.1
9.1
NM
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
0.3
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:   S&P,  1986a.

     'Simple average calculated from the ratios of the sample.
                                     3-37
-------
                                TABLE 3-22

                              CURRENT RATIO
          INDEPENDENT OIL COMPANIES IN EPA 17-COMPANY SAMPLE

Apache Corp.
Cabot Corp.
Conquest Exploration
Damson Oil
Hamilton Oil Corp.
Helmerich & Payne
Howell Corp.
Lear Petroleum Corp.
LA Land S Exploration
Mitchell Energy fi 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
1.5
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
1.3
1.4
1985
1.1
1.9
0.7
1.0
1.2
4.6
1.0
0.8
1.1
i.i
1.3
1.2
0.7
1.2
2.3
2.1
1.2
1.4
NA = Not available.

Source:  SSP, 1986a.

     •Simple average calculated from the ratios of the sample.
                                    3-38
-------
                                 TABLE 3-23

                          DEBT/CAPITAL RATIO (%)
          INDEPENDENT OIL COMPANIES IN EPA 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
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
75.3
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
67.1
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:   S&P,  1986a.

     asimple average calculated from the ratios of the sample.
                                     3-39
-------
 other measure of profitability, return on assets, shows the same downward trend, from 5.8
 percent in 1981 to 1.6 percent in 1985 (Table 3-21). The impact of falling oil prices is clearly
 evident from these tables.

       The Current Ratio data for EPA's sample of independents shown in Table 3-22 exhibits
 no clear overall trend.  It 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,however, the
 average is highly skewed by the inclusion of Helmerich & Payne.  This indicates that the
 independents maintain a slightly higher degree of liquidity than the majors. The higher liquidity
 does not automatically translate to a larger amount of working capital for the independents.
 Given the relative size of the asset base between the independent and the major oil companies, it
 is possible for a major  to have a current ratio close to 1.0 yet still have more working capital (in
 an absolute sense) than an independent with a higher current ratio. The independents also
 utilize a higher level of debt.  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. 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 PennWell Maps b£
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 Eight to illustrate the potential impacts of the NSPS regulations
on the two major categories of industry participants. The financial profiles for majors are
   1ARCO (Atlantic Richfield), Exxon, Mobil, Shell (Royal Dutch Petroleum), Standard Oil of
Indiana (Amoco), and Texaco.
   ^nexco Oil, Sabine Corporation, and Pogo Producing.
                                          3-40
-------
presented for selected years from 1973 to 1986.  For independents, a time period of 1980-1985 is
used. 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 that 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 declined; an unprecedented volume of
merger and takeover activity has been the direct result.
       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" major are:
              Profitability peaked in 1980 and declined through 1986, as shown by the return on
              assets and return on equity values.
              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.
              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 the long-term debt-to-equity and
debt-to-capital ratios jumped 9 percent and 54 percent, respectively, from 1983 levels. The
majors are becoming increasingly leveraged in response to or as a result of corporate takeover
actions.
                                           3-41
-------
9
9
' u
       1  
                                       H -rl
                                                         <-l   U
                                                             g   3
                                                                              -S
                                                                    I
                                                                                         rH  -0
                                                              3-42
-------












£
§

2
0
J
o

t3
3i
in m w
O tH H
in r- in
in co M
«3> m


MHO
o o ***
CO t- ^
u) m CM



« ^J* CO
o ts in
m co 
r- in PI
o on H
r- ^ PI


CO VO PI
vo r* on
t^ t^ on
ro H ' H


00 iH O
vo • on l>
VO H •*
« PI PI

m , r- vo
pi m co
rH in in
in PI PI


on o on
on vo m
PI 0 PI
ro P) rt

in ro PI
m on o
on oo H
PI rt H


vo vo o
co mm
H PI on




•g
a

Be
O 0)
•H -H n to a
11 ±j O Q> Q)
m « 
B Jj
" p
*O »s
H O •
(I)
i oil conpany.
tandard Oil of
for "typical"
s in the sampl
a to m o
• E -H
lit » to C
o in u 3
rS 1 W 1
* M S °
03 fc S ^
Si— { fl) -H
•rl U 0
™ . ° ^
s HI
g . - ^
H U (71 O
43 gj C *r»
^ -o S x
g VH O -rl

iri 01
U 4J O (D
Q H U Si
S °< 2 "
ti pj 13 O
0 rH 0 **
"§ i o S
3 3 U-H
\f
™ 8
g
CO
3-43
-------



1 •


!£
0
u
d
0
1
0
w

2*
H
§
r
l_3
i
P

\o •<

Jj 52
M IX,
3 to
§ 1
£i
P


8
1
0
rW
Q
Z

O
1
§
2jj
1












VD
CO
cn


in
CO
en




CO
s


ro
co
cn
rH

CM
00
cn
tH
tH
CO
en


o
CO
cn
•H


CO
p.
cn
tH

p-
a


s
cn
iH
s
8
g
H
g
w
8


g
Q
H
£

1
cn
s
1
f-f
o
CO

ID
CM
ID




«*
ID
to

p-
cn
in
rH

in
to
*
CM
CM
tH

CM
O
CO
in
CM
tn
ro
CO
iH
cn
p-

in
ro

H




ST
to-


< a
4J
•H
f

CJ<
B
•^
1
1

*i
rt
ro
cn

0



CO
o

CM
CM

H

iH
CM
"
in
CM

tH

cn
CM
tH

ro
ro

H
P.
tH

to
"•
tH











Q

JJ
&
«
CD
H
3
O
in
in
ro
tn

CO




cn
o

r-

in
CM

o
ro.
CM
o

*4*
CM

CM
CM

_.

P-
CM
in
co
CM

CM
ro
CM

£
o
•H
41
&
J51
•d
&

o

^
CD
a
g
CD
I
CO
ro
CM
«

ro
CM



CO
ID
CM

«*

P-
tH

tH
in
tH
o

in
tH

rH

^

p-
H
CM
CO
rH

Ul
to
tH




^^
dp
0
•r(
41
a

rH
id

Ol
5
o
41
41
ja
0)
a
in
,j

CO

f




f
tn

in

u>


CM
to

O

CO


tH
at

rl

ID

IA
<0

in
CO




d?
to
•Jj
a
o
)4J

•g
H

a)
X
§
g
I
tH
iH
iH
O

CM




CO
CM
rH

CO

ro
rH

„.
ro
rH
in

p-
rH

o
CM

0

CO
H
CM
to
rH

tH
in
rH



y
^
ij
&
H

"g
H
i
0)
X
g
1
4J
a)
K
-------
       3.4.2  Financial Profile of "Typical" Independents


       A balance sheet and incoihe statement of a "typical"  independent oil company for the

years 1980 to 1985 are provided in Tables 3-27 and 3.28. These financial statements were used

to develop the series of performance indicators in Table 3-2§.


       The most important points about the financial performance and condition of the "typical"
independent are:
              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.

              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.

              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 majors.      .              •..- -  • -.••._•
       3.4.3 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 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 (return on revenues, see Table 3-30).  From 1980 to 1984, return on assets
                                           3-45
-------
                              •  TABLE 3-27

        BALANCE SHEET FOR A "TYPICAL" INDEPENDENT OIL COMPANY
                    (IN MILLIONS OF CURRENT DOLLARS)
                        3,980
1981
                                        1982
                                                1983
                        1984
                                                                1985
Assets
Current Assets
Property, Plaint and
Equipment (net)
Other Assets
TOTAL ASSETS

55 87
387 543

5 5
. 447 635

71
647

4
722

55
613

4
671

55
626

4
686

53
528

3
583
friabilities
Current Liabilities
Long-Term Debt
Other Liabilities
TOTAL LIABILITIES
Shareholder's Equity
TOTAL LIABILITIES AND
NET WORTH

52
148
46
247
200
447

82
246
73
401
233
635

64
311
102
477
245
722

51
269
139
459
212
671

47
280
152
479
207
686

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 fqr "typical" company are calculated by simple averaging of
        balance sheet items for three independent oil companies.
                                     3-46
-------
                                 TABLE 3-28

      INCOME STATEMENT FOR A "TYPICAL" INDEPENDENT OIL COMPANY
                    (IN MILLIONS OF CURRENT DOLLARS)
                                   1980    1981   1982   1983   1984   1985
Revenue
Expenses
Depletion, Depreciation,
and Amortization
Income Before Taxes
Net Income
Domestic Exploration and
Development Expenditures"
164
106
51
58
34
193
236
163
65
73
42
187
231
181
75
50
31
173
172
133
71
39
24
101
179
176
71
3
3
105
161
239
69
(78)
(41)
69
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 fqr three independent oil companies.

     'Defined  as sum of property acquisition,  exploration, and development
expenditures.
                                     3-47
-------
                            oo
                            at
                                            00
                                                   00
                                            iH     ID
          00
          CN
                            oo
                            at
en
 •
in
                            oo
                            at
                                            vo
U)
                 VO

                  •

                 CO
                                                                          ro     O
                            03
                            at
a
                            oo
                            at
                                      in
                                                             at
                 to
                  *
                 vo
                                                                                 00
                       00
                            oo
                            at
                                      o

                                      o>
                         a
          CO
            •

          co
          tn
                                                       -^     o
                                                       £•     o
                                                                    •
t~     o
                                                                           H
                                                                           a
                                                                                           00
                                                                                            i
                                                                           w    —

                                                                                            Cn
                                                                3-48
-------
I





CO
NH
O
O
..a
o
o
H
1
i
c
1
1 '
M

I
CO
^
P^J
§
0
U
P*1
H
13
1
i
r*4












oo
rH

CO
0>
rH

ro
00

rH


CM
CO
en
rH
rH
CO
cr>
rH


O
CO
en
rH























co a o a cn a
a -a -a
<• CM m
«* «* .00 ^" rH t—
« • • 0 • •
in O CM rH 
rH
O VO in O VD 00
• • * • * *
oo vo r- oo ^t t-
rH rH rH



.rH VO "* O CM • r- .
or* o r* in o
. CM rH ^







H H
Of c*>
m >
t! & --S & &
CD td 3 (d -^ *d
a ft o ft * ft
•a o c -a o c m o c
c n) c a a) ' id
M *r( Qi Eel *O QJ D *O P4
i m s i a) & c a) e
Vl .p O Vi 4J O 0) -P O
ido
Q) S-( 0) >H 01 V4
>H CTl 4J tH Cn -P « Oi-P
(DC Q) C Q) C
C -P Q) C-PQ) C -P Q)
OCTf OC"O OC*O
M C M C M C
C (DC Q) C 0)
hlHft KV4ft hVlft
3OO) 3OO>3O(U
4J i-» "O -P i~> "O -P -r-> •O
aiidc oiata aiidc
K s n osan oi a H
















, in
00
CTi
rH
C
0)
0
u
c
-M
IB
c
0)
>
"•2
i? .
c m
0)
VM *H
0> -P
C m
•H 0)
C
id rij
0) 04
4J
O
jgj . Qj
U
H H
a B
S CO
                                               3-49
-------
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 as a drop in
profitability for both major and independent companies. Majors reduced capital and exploration
expenditures after 1982, due to decreasing 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
borrowing 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 the period 1980-1985. The overall  financial strength of the majors relative to the
independents is evident by their maintaining 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
                                           3-50
-------
                                 TABLE 3-31

    LIQUIDITY COMPARISONS BETWEEN "TYPICAL" OFFSHORE OIL COMPANIES
                         1980
1981
                                            1982
                  1983
Change in Working Capital
Capital m

Major Integrated Company

Independent Company
-0.1

 0.7
-0.2

 0.4
 0.0

-0.6
                                                              1984
                                      1985
Current Ratio
Major Integrated Company 1,29 1,25 1,21 1.22
Independent Company 1-05 1.06 1.12 1.06

1.08 0.93
1.19 1.08
-0.6

 2.0
  NM

-0.6
NM = not meaningful,  negative  net working capital in 1985.

Source:  EPA estimates.
                                      3^51
-------
                                       TABLE 3-32




          LEVERAGE COMPARISONS BETWEEN "TYPICAL" OFFSHORE OIL COMPANIES
                                       1980
         1981
1982
                                                                  1983
1984
                                            1985
          Debt -ho Equity Ratio  f%>




Major Integrated Company




Independent Company






DBbte to capital Ratio f%V




Major Integrated Company




Independent Company
       to Total Assets (%>
Source:  EPA estimates.
24.2     24.0     23.0     25.7




74.2    105.4    127.2    126.9
                  40.9     38.5




                 135.3    168.3
14.7     15.0     15.1     17.4     26.8     23.4




58.8     77.9    101.0    102.2    110.4    128,7
Major Integrated Company
Independent Company
44.6
44.7
45.4
36.7.
46.1
33.9
.47.2.,
31.6
42.3
30.2
39.9
27.3
                                           3-52
-------
long-term debt. As can be seen for the period from 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.

       The other data in Table 3-32 serve to support this observation.  Equity to total assets is a
measure of how soundly the company is capitalized.  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 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.
                                            3-53
-------
i






£
^P
co ^j
?H ^
O H
>~4 O
So
flu N»l
^f*j ^5
8g
* 22
«A *s ffi
a ii
§ 1?
C^ CA y
S o
«3 s
s
53 !^
c*5 ^^
> z
ig
Op
(d
W


|
in
CO
rH

00
at
•H
en
00
at
tH




CM
00
at
r-l


CO
at
r-t





o
00
at
tH






in a. »o H o a.
« 2 ? s ^s
en 1
CM tO , CM H «*J ^
• PJ ^ •* o oo
ff- ^ •* H in
rH CM rH W 00 t-
c^ * oo' • •« o> W
CM ^ '7
1



« 2 *. 1 °. ' °i
" r! T 7 ^ *
I


OH « « « «
" • ' 2 * 3 m • *




> ii in t"
il I! . .
Ii ' oo f-
r-i
H


o tn —
3^1 1 3 £ 1s» S1
*^ 1 *l ^sst
-II ! | IS 1 «S!I S 1
f! 1 t ' H "13 H
IP, t I ill ?i* 1 I
I «! : ! * 11 3§" M8 1
-Hi v 1 5 I 1 si! § !
il s s I ". if! s H
8S8S 5 " oc^
S wlwlw o ° rt rt

















•
Rl
id
•o
Vl
id
rH
r-l
O
•d

^
0)
VI
Vl
3
U
e
M-l
•d
(U
ti
Note: All values calcul
Source: EPA estimates.
3-54
-------
3.5    CURRENT FINANCIAL CONDITION AND FUTURE OUTLOOK

       This analysis has attempted to capture a picture of the industry for purposes of
establishing a financial baseline with which to assess potential economic impacts.  The year for
that snapshot is 1986 which marks a nadir for the industry.  The financial profiles developed
above were used to examine potential changes in financial health that may result from the
regulatory options in the 1988 Notice of Data Availability, the 1991 reproposal, and Section
Eight of this report.  The financial profiles have not been changed since the 1988 Notice of Data
Availability. The different sets of company impacts presented in these various reports, then, vary
due to changes in regulatory options and associated costs rather than changes in the company
financial statements.

       The oil and gas industry has seen several shifts since the profile presented above. This
section updates the financial profile for the industry since 1986. Although the outlook for
domestic oil companies is mixed, the industry is in a more favorable financial position than it was
in 1986 due to increased oil prices and industry restructuring.  This implies that updating the
balance sheets for the typical major and typical independent oil company would result in more
favorable and larger  baseline values for the financial ratios. The economic impact analysis for
typical companies focuses on the change from the baseline value, rather than on the baseline
value itself. A change in a parameter  results in a larger proportional impact for the smaller
baseline value (e.g., a $5 thousand decrease in the net present value of the project is a 20
percent decrease for a project with a baseline net present value of $25 thousand, but only a 2
percent decrease for a project with a baseline net present value of $250 thousand.) In other
words, because 1986 was a nadir for the industry, we can continue to use the 1986 balance sheets
for estimating the impacts of the final rule on a typical major and typical independent oil
company with the understanding that the impacts will not be underestimated.
        3.5.1  1986 to Present

        The record low oil prices experienced in 1986 severely impacted the financial health of
 many oil and gas producers.  An ensuing period of mergers, bankruptcies, and consolidations

                                            3-55
-------
resulted in a significantly smaller number of companies producing in the United States. In 1991,
the Oil and Gas Journal 400 (OGJ 400), an annual report on the finances of the 400 largest
publicly traded oil and gas producers in the United States, became the OGJ 300 for this very
reason.

       In recent years the health of the industry improved significantly over the dismal
performance seen in 1986.  The Iraqi invasion of Kuwait, which brought production from both
countries off of world markets, prompted a temporary spike in oil prices, thus benefiting industry
profits in 1990. The U.S. economy, however, fell into a recession the following year.  This
decline in economic activity led to a reduced demand for petroleum.  The OGJ 300 profits fell
28 percent from $23 billion in 1990 to $17  billion in 1991 (Beck and Sanders, 1992).  These
conditions, however, were far better than those experienced during the 1986 nadir. The group's
profits have averaged roughly $21 billion between 1988-1991.  This  compares with group profits
of only $5.2 billion and $9.4 billion in 1986 and 1987, respectively.  In contrast, the OGJ group
earned roughly $28 billion in 1983 (Beck and Sanders,  1992).

       According to various profitability indicators, the industry is  faring better than in 1986, but
not quite as well as in 1982 when oil prices were strong. Return on assets for the group was 3.4
                                                                                     was
percent in 1991 (down from 4.7 percent in 1990).  This compares with the recent low of 1
percent in 1986 and the recent high of 5.7 percent in 1982.  Similarly, the return on revenue
3.3 percent in 1991, down from 4.3 percent in 1990. These figures compare to return on
revenues of 5.1 percent in 1982 and 1.2 percent in 1986. Return on equity currently stands
around 9.8 percent (compared to 13.6 percent in 1991, 3 percent in 1986, and 13.8 percent in
1982) (Beck and Sanders, 1992).
        Capital spending among the largest U.S. oil companies has actually declined since the
•early 1980's. Between 1988-1991, capital and exploration spending averaged $52 billion per year.
 Prior to 1985, capital outlays for the group averaged $65 billion. This decline in exploration
 investment can be seen in well drilling activity.  There were 9,146 wells drilled in the U.S. in
 1991 (down 16 percent from 1990). In comparison, there were 10,993 U.S. wells drilled in 1986.
 In general, U.S. drilling activity has been slow since the oil price collapse in 1986  (Beck and
 Sanders, 1992).

                                           3-56
-------
       The top 20 U.S. producers represent the vast majority of U.S. oil and gas market.  In
1991 the top 20 producers in the OGJ 300 accounted for 95 percent of the profits, 83 percent of
the assets, 91 percent of the revenues, and 85 percent of U.S. liquids production. Major oil
producers, however, aren't quite as dominant in gas production. The top 20 companies
represented only 68 percent of U.S. gas production (Beck and Sanders, 1992).

       The largest oil and gas companies in the U.S. produced a large percentage of worldwide
petroleum production, however, their access to undeveloped reserves does not bode well for their
continued dominance.  In 1991 the OGJ 300 accounted for 13 percent  of worldwide liquids
production and 20 percent of worldwide gas production. However, OPEC member countries and
other national oil companies control a vast share of the worldwide oil  and gas reserves.  The
OGJ 300 controls only 3.1 percent of worldwide liquids reserves and 3.7 percent of natural gas
reserves (Beck and Sanders, 1992).

        The producers listed in the OGJ 300 account for a large portion of the U.S. economy;  In
1991 this group of companies generated $507 billion in revenues, which represents approximately
8.9 percent of U.S. gross domestic product (GDP).  The industry's significance has declined,
however, since the early 1980s. In 1983, the revenues of the top 400 oil and gas producers
accounted for 18.4 percent of GDP (Beck and Sanders, 1992). The  decline is due, in part, to
lower oil prices, which average $26/bbl for 1980-1985 and $14/bbl for 1986-1990 (see Table 3-4)..
        3.5.2   Outlook

        A trend that is expected to continue in the oil and gas industry is the increasing shift
 away from domestic exploration and production.  Overseas opportunities abound as many of
 former eastern block countries as well as smaller developing countries encourage U.S. capital and
 expertise to develop their oil and gas reserves.  The United States is a mature region in term of
 hydrocarbon exploration and development. An overall depletion in domestic hydrocarbon
 reserves, coupled with restricted leasing of new regions (e.g., California offshore and the Arctic
 National Wildlife Refuge (ANWR)), has prompted a shift of investment to overseas
 opportunities by major oil companies. For the independent producers, this has led to domestic
                                            3-57
-------
opportunities as the majors liquidate U.S. production interests (Tippee, 1991).  Many
independent producers have also taken part in the international movement, although to a lesser
degree.

       The outlook for the U.S. oil and gas producers is mixed.  Gas producers, of which many
are independents, have recently been hit with an extended period of low prices. This lull in
prices has recently begun to turn around with increasing demand and prices for natural gas
(although some of the price hikes have been attributed to temporary capacity shutdowns resulting
from 1992's hurricane Andrew). Demand is expected to increase when the U.S. economy begins
to emerge from its recessionary period. New energy legislation has recently been passed which
includes provisions to help support domestic oil and gas production. Among the provisions are
changes to the alternative minimum tax (AMT) which should increase drilling activity, especially
among smaller independent producers (OGJ, 1992). The legislation will reportedly provide for
legislative reform and incentives for the use of natural gas.  At the same time, restrictions and
moratoria remain  in place, preventing the leasing of state and federal areas containing potential
oil and gas resources. A recently-announced^ajor discovery by ARCO approximately 16 miles
off shore from ANWR is certain to re-open debates to allow leasing in the area (Rose, 1992).
These uncertainties in future outlook led to the investigation of three oil prices scenarios in the
 economic impact analysis associated with the 1991 reproposal.  The analysis for the final rule
 (i.e., this  report) is based on an oil price of $21/bbl — the most likely of the three scenarios
based on 1992 oil  prices.
 3.6    REFERENCES

 API. 1986.1985 Joint Association Survey on Drilling Costs. American Petroleum Institute.
        Table 3.
 API. 1988. Basic Petroleum Data Book. American Petroleum Institute. Volume Vin, Number 1,
        January.
 API. 1992. Basic Petroleum Data Book. American Petroleum Institute. Volume XII, Number 2,
        May.
                                           3-58
-------
Beck, R.J., and V. Sanders, 1992. "Financial, Operating Results Sag for OGJ 300 Companies,"
       Oil & Gas Journal. 28 September, pp. 49-79.

Beck, R.J., and G.E. Smith. 1982. "Profit Decline for OGJ Group Trims Key Economic
       Indicators," Oil and Gas Journal 31 May, pp. 43-48.

Beck, R J., and G.E. Smith. 1983. "Recession Trims 1982 Earnings for OGJ Group by 22.2%,"
       Oil and Gas Journal. 21 March, pp. 39-42.

Beck, R.J., and G.E. Smith.  1984. "1983 Results Set Stage for Year of Recovery by OGJ
       Group," Oil and Gas Journal. 11 June, pp. 43-48.

Beck, R.J., and G.E. Smith.  1985. "Restructuring Helps Take Slice Out of OGJ Group
       Earnings," Oil and Gas Journal 20 May, pp. 25-30.

Beck, R.J., and G.E. Smith.  1986. "Restructuring and Writedowns Trim OGJ Group's 1985
       Profits." Oil and Gas Journal. 26 Mav. pp. 25-30.

Beck, R.J., and G.E. Smith.  1987. "Oil, Gas Price Collapse Cuts OGJ Group's Profits  One
       Third in 1986," Oil & Gas Journal. 25 May, pp. 19-21.

Bureau of the Census. 1973-81. Annual surveys of oil and gas.

CMB. 1981.  1981: Financial Analysis of a Group of Petroleum Companies. Energy Economics
       Division, Chase Manhattan Bank, New York, New York.

CMB. 1982.  1982; Financial Analysis of a Group of Petroleum Companies. Energy Economics
       Division, Chase Manhattan Bank, New York, New York.

CMB. 1983.  1983; Financial Analysis of a Group of Petroleum Companies. Energy Economics
       Division, Chase Manhattan Bank, New York, New York.

CMB. 1985a. 1984:  Financial Analysis of a Group of Petroleum Companies. Energy
       Economics Division, Chase Manhattan Bank, New York, New York.

CMB. 1985b. 1985;  Financial Analysis of a Group of Petroleum Companies. Energy
       Economics Division, Chase Manhattan Bank, New York, New York.

CMB. 1985c. 1984:  Capital Investments of the World Petroleum Industry. Energy Economics
       Division, Chase Manhattan Bank, New York, New York.

CMB. 1986.  1986; Financial Analysis of a Group of Petroleum Companies. Energy Economics
       Division, Chase Manhattan Bank, New York, New York.

Council of Economic Advisors. 1986. Economic Report of the President. February. Table B3.

Keenan, P. 1981. "Financing the Petroleum Industry 1980-1990:  $3.17 TRILLION!," Ocean
       Industry. October, pp. 52-58.

                                         3-59
-------
OGJ, 1992. "AMT rules change seen boon for U.S. drilling," Oil and Gas Journal 5 October,
       1992, pp. 44.

PWell. 1986.  PennWell Directories.  Offshore 1986: Worldwide Offshore Contractors and
       Equipment Directory. April.

Rose, R, 1992.  "Arco Oil Find in Beaufort Sea Is Likely To Renew Debate Over Wildlife
       Refuge," The Wall Street Journal. 15 October, pp. A3.

S&P. 1982a.  "Oil, Basic Analysis," Standard and Poor's Industry Surveys, November.

S&P. 1982b.  Analyst Handbook. Official Series, Standard and Poor. 1982 Edition.

S&P. 1986a.  "Oil, Basic Analysis," Standard and Poor's Industry Surveys, November.

S&P. 1986b.  Analyst Handbook. Official Series, Standard and Poor. 1986 Edition.

S&P. 1986c.  "Oil-Gas Drilling and Service — Basic Analysis," Standard and Poor's Industry
       Surveys. March.

S&P. 1987. Analyst Handbook. Official Series, Standard and Poor. 1987 Edition.

Smith, G. 1986. "Fiscal 1985 Returns for OGJ 400 Mixed,"  Oil & Gas Journal. 8 September,
       pp. 55-95.

Tippee, B., 1991.  "JDPAA chairman-elect: coping and changing," Oil and Gas Journal. 7 October,
       pp. 51-56.
                                          3-60
-------
                                  SECTION FOUR
                STRUCTURES AND WELLS INCURRING COSTS


       An integral part of an economic impact analysis is the estimation of the number of
entities that will incur increased pollution control costs. For drilling fluids, drill cuttings, and
treatment, workover and completion fluids, the entity is a well.  Each well drilled has an
increased cost for drilling fluids and drill cuttings whether or not it goes into production. All
productive wells bear incremental costs of additional pollution control on completion fluids when
they go into production, and on treatment and workover  fluids periodically throughout their
productive life.  For several waste streams (Le., produced water and produced sand), the entity is
the structure, facility, or platform.  (The terms are used interchangeably in this report.)

       Section 4.1 reviews the data and procedures used to estimate the number of existing
structures likely to incur BAT costs. Section 4.2 reviews  the information for well and platform
projections for both BAT and NSPS costs. Section 4.3 presents the data for  forecasting NSPS
platforms.  The total number of platforms and wells are subdivided by a boundary based on
distance from shore. For platforms, profiles are presented for 3-mile and 4-mile boundaries.
For wells, a third boundary, located at 8-miles from shore, is also considered.
4.1    EXISTING STRUCTURES (BAT)

       For a structure to incur increased BAT pollution control costs under this rulemaking, it
must be all of the following:

       •      In the offshore subcategory.
       •      In production.
       •      Discharging.

This section discusses the various data sources used to compile this profile.
                                           4-1
-------
       4.1.1 Gulf of Mexico

       4.11.1  State Waters

       The count of BAT structures presented in the EIA associated with the March 1991
reproposal did not include a count of structures in Gulf of Mexico state waters (EPA, 1991a,b).
This information gap is addressed in this analysis.

       Louisiana, Alabama, and Mississippi were granted jurisdiction over offshore lands to a
distance of 3 nautical miles from their coasts by the Submerged Lands Act (43 U.S.C. 1301, et
seq.).  For historic reasons, however, Texas and Florida (its Gulf coast side only) have
jurisdiction to 3 marine leagues (about 9 nautical miles).  Therefore, the inclusion  of structures
in state waters will affect the count of structures both within and beyond the 4-mile boundary
presented in EPA (1991a,b).

       First, well data were licensed by Eastern Research Group, Inc. (ERG) from Tobin
Research, Inc. The data included all wells completed from January 1980 to February 1991 in the
Gulf State offshore and coastal region.1

        Second, wells in the offshore subcategory were identified.  This is not always  a
straightforward determination. In general, wells may be defined as offshore by states if the well
produces from beyond natural shorelines (e.g., API, 1991).  The Agency defines the subcategory
of a well by its wellhead location, not the bottom hole location; thus a well's classification may
differ  depending upon whose definition is used. For example, a well designated as "offshore" by
a state will fall into one of three Agency subcategories:

        •      Onshore—if the wellhead is on land but the production zone is beyond the
               natural shoreline.
        •      Coastal—if the wellhead is located within an inland bay or harbor (landward of
               the inner boundary of the territorial seas).
    1There may be a few wells completed prior to 1980 that are still active today, but they are
 expected to form a small percentage of the wells.
                                            4-2
-------
              Offshore—the wellhead is seaward of the "baseline" separating the coastal and
              offshore subcategories (seaward of the inner boundary of the territorial seas).
The baseline is an imaginary line running along the coast and across the mouths of open bays
and harbors.  It is defined in the Clean Water Act and the Submerged Lands Act as the line of
ordinary low water along that portion of the coast which is in direct contact with the open ocean
and the line marking the seaward limit of inland water. Information on the baseline was
compiled by Avanti Corporation (Avanti, 1991).  The baseline was programmed into the data
base.  The wells were then electronically classified into offshore and coastal subcategories.  The
baseline also formed the basis for identifying wells within 3 nautical miles of shore, and, for
Texas wells, between 3 and 4  miles from shore, and beyond 4 miles from shore.

       Third, each well in the data base was checked against 1":4,000' scale maps prepared by
Tobin Research, Inc. The mapping effort served to:

       •      Verify each well  in the  data base against a hard-copy information source.
       H      Verify the "coastal/offshore" classification of each well.
       •      Identify multi-well structures.

These three steps established the number of single-well and multi-well structures in state waters.
In addition, the Tobin data were used to determine which wells were productive at the time of
completion.

       Fourth, each state offshore well that was productive at the time of completion was
checked to see if it was still in production at this time. If a structure was no longer in
production, it should not be included in  the estimate of structures that would incur increased
pollution control costs for produced water, produced sand, or treatment/workover fluids. To
perform this check, Petroleum Information (PI) was provided with a list of 10-digjt API numbers
representing the wells that were in production at the time of completion. PI returned the  file
with a current status flag denoting whether the well was active, currently plugged and abandoned,
or permanently plugged and abandoned.
                                           4-3
-------
       The final step was the allocation of active wells among economic models. All active
single-well structures were assigned as Gulf la models. Structures that had two wells, at least
one of which was active, were assigned as Gulf Ib models.2  The remaining wells were allocated
on the basis of the number of wells on the structure.3

       Table 4-1 summarizes the well data for the state Gulf of Mexico offshore waters. About
1,296 wells have been completed since 1980.  Of these, only 567 were productive at the time of
completion and only 339 remain active today. These 339 wells are located on 284 structures (see
Table 4-2).  Table 4-3 shows the distribution of these structures within 3 miles of shore, between
3 and 4 miles of shore, and beyond 4 miles of shore. Only structures in Texas state waters are in
the last two categories.
       4.1J3 Federal Waters

       In the report, the term "federal waters" refers to the Outer Continental Shelf (OCS)
 region under the jurisdiction of the U.S. Department of the Interior, Minerals Management
 Service (MMS). The estimate is based on the data in the Minerals Management Service
 Platform Inspection System, Complex/Structure data base as of March 1988 (MMS, 1988a). This
 analysis, however, deals with structures, not complexes (a collection of one or more structures
 that are connected by at least a catwalk). The only structures that were considered appropriate
 for inclusion in the count:
                                           •s
        •     Had productive wells.
    2Neither set of (data includes information on the presence or absence of production equipment.
 It was assumed that a structure with more than one well would be more likely to have production
 equipment than would a single-well structure.
    3The following  break points were used for classification:  between 3 and 5 wells = Gulf 4,
 between 6 and 11 wells = Gulf 6, and between 12 and 20 wells = Gulf 12. There were no structures
 with more than 20 wells. This allocation pattern results in more than 339 productive wells being
 back-calculated from the economic models.  This was deemed preferable to several allocation
 schemes based on the number of active wells; all these underestimated the number of productive
 wells.
                                           4-4
-------
TABLE 4-1
SUMMARY OF WELL DATA
GULF OF MEXICO STATE WATERS
                                                Hunter of Wells
                            Mississippi Alabama Louisiana   Texas    Total
All
Tobin data - active*
PI data - active
3
0
0
700
334
211
592
233
128
1,296
  567
  339
Note:  (*)0bservation has a class of oil, gas, multiple oil,
          multiple gas, or multiple oil and gas.
                                                 4-5
-------
TABLE 4-2

SUMMARY OF PLATFORMS IN GULF OF MEXICO STATE WATERS
STRUCTURES ESTIMATED TO BEAR COSTS
                       Type of Production
                                                          Louisiana
                                                                                        Texas

Model
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Total
Note:

Total
220
34
24
5
1
284
Oil
Only
81
11
3
1
0
96
Gas
Only &
137
20
12
3
0
172
Oil
Gas
2
3
9
1
1
16

Total
153
13
10
3
1
180
Oil
Only
74
9
3
1
0
87
Gas
Only
79
2
2
2
0
85
Oil
& Gas
0
2
5
0
1
8

Total
67
21
14
2
0
104
Oil
Only
7
2
0
0
0
9
Gas
Only
58
18
10
1
0
87
on
& Gas
H
1
4
1
0
8
Includes only active structures.
          Designation as State offshore waters based upon Agency definition.
                                               4-6
28-Oct-92
-------
 TABLE 4-3

 SUMMARY OF PLATFORMS  IN GULF OF MEXICO STATE WATERS
 STRUCTURES ESTIMATED  TO BEAR COSTS
                   Within Three Miles
   Distance From Shore

Between Three and Four Miles   Beyond Four Miles
Model
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Total
Total
165
19
13
3
1
201
Oil
Only
76
10
3
1
0
90
Gas
Only
89
6
4
2
0
101
Oil
& Gas
0
3
6
0
1
10
Total
9
2
1
0
0
12
Oil
Only
0
0
0
0
0
0
Gas
Only
9
2
1
0
0
12
Oil
& Gas
0
0
0
0
0
0
Total
46
13
10
2
0
71
Oil
Only
5
1
0
0
0
6
Gas
Only
39
12
7
1
0
59
Oil
& Gas
2
0
3
1
0
6
Note:     Includes only active structures.
          Designation as State offshore waters based upon Agency definition.
                                                  4-7
28-Oct-92
-------
       •     Were active as of March 1988.
       n     Had a known type of production.
       •     Had a known number of drilled well slots.

       Table 4-4 describes the data-cleaning process used to identify structures that should be
included in the estimate.  First, any structure with an entry in the "year removed" field was
excluded from the count, leaving 3,562 structures for .consideration.  Second, the costs of
pollution control equipment depend upon estimated water production. Thus, structures that
produce no water should be excluded from the count. The 465 structures with production
equipment described as having no well slots were excluded from the count.  Another 721
structures were known not to be in production as of March 1988 (i.e., both product fields had V
entries). Another 88 structures were excluded because they had zero drilled well slots and
therefore  could not be in production. Finally, 55 structures had insufficient information to
classify them among the economic models.  As a result, 2,233 structures in the federal Gulf of
Mexico were estimated to bear costs of incremental pollution controls on produced water.

       These structures were then allocated among the economic models based on the number
of producing wells. The MMS data set, which has information on the presence or absence of
production equipment, was used to differentiate between the Gulf la and Gulf Ib models.  The
breaks between the categories were chosen to create the best correspondence between the actual
number of wells and the number of wells back-calculated from the economic models.

        The final, subcategorization was whether the structure is located within or beyond the
boundary. All structures  in federal waters lie beyond the 3-mile boundary. Table 4-5
summarizes the information for the federal Gulf of Mexico for the 4-mile boundary.
       4.1.2 Pacific

       Table 4-6 lists the 32 structures considered in the Pacific BAT count, as well as their
 distances from shore. Not included in Table 4-6 are Grissom, White, Chaffee, and Freeman
                                           4-8
-------
TABLE 4-4

IDENTIFICATION OF STRUCTURES ESTIMATED TO BEAR INCREASED POLLUTION CONTROL COSTS
MINERALS MANAGEMENT SERVICE PLATFORM INSPECTION SYSTEM
COMPLEX/STRUCTURE DATA BASE
MARCH 1988
Category
All structures
structures classified as
Count
3562
465
Remaining
Count
3562
3097
production structures,
i.e., with zero well slots
available and with
production equipment

Structures known not
to be in production

Structures with zero
drilled well slots

Structures with missing
 information  on number
of well slots drilled

Structures with missing
 information  on product
 type (oil or gas  or both)

 Structures whose drilled
 well slots are used solely for
 injection, disposal,  or
 as a water source
721


 88


 33



 16
2376


2288


2255



2239



2233
 Source:   Minerals Management Service Platform
           Inspection System, Complex/Structure
           See printouts, kre_bat.out,
           kre_bat2.out, and kre_bat4.out.

 21-Dec-92
                                                    4-9
-------
TABLE 4-5

STRUCTURES ESTIMATED TO BEAR INCREASED POLLUTION CONTROL  COSTS
FEDERAL WATERS - GULF OF MEXICO REGION
Structure
Type
         Oil Only

  <= 4 miles  > 4 miles
       NUMBER OF STRUCTURES

           Oil and Gas
       .-*.......•.-.-..--<.
       <= 4 miles> 4 miles
                      Gas Only

                <= 4 miles> 4 miles
                                   Total

                              <= 4 miles> 4 miles  Total
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58

Total
         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
Note:
Source:

21-Dec-92
Structures in the Gulf of Mexico have been classified according to the number of producing wells.
KMS, 1988a; SAS printout kre_bat6.out; SAS runs dated July 1990.
                                                 4-10
-------
TABLE 4-6

BAT Structures In California Waters
Location by Distance From Shore and Water Depth
Platform Name
         Number of
Region  Well Slots
Model      Distance   Water Depth
 Type    From Shore      (Meters)
A
B
C
Edith
Ellen
Eureka
Gail *
Gi Ida
Gina
Grace
Habitat (Gas-Only)
Harmony *
Harvest *
Henry
Heritage *
Hermosa *
Hidalgo *
HHlhouse
Hogan
Hondo
Houchin
Irene *
Holly
Belmont/Monterey (Is.)
Emmy
Eva
Hope
Heidi
Hazel
Esther (Is. to Plat.)
Hilda
Rincon (Is.)
DCS
DCS
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
ocs
State
State
State
State
State
State
State
State
State
State
57
63
60
72
80
60
36
96
15
48
24
60
50
24
60
48
56
60
66
28
60
72
30
70
30
30
60
60
25
128
24
68
40
70
70
70
70
70
40
70
16
40
16
70
40
16
70
40
70
70
70
16
70
70
16
70
16
16
70
70
16
70
16
70
4+
4+
4+
4+
4+
4+
4+
4+
3-4
4+
4+
4+
4+
3-4
4+
4+
4+
.4+
3-4
4+
3-4
4+
<3
<3
<3
<3
<3
<3
<3
<3
<3
<3
57
58
59
49
81
213
225
63
29
97
88
366
206
53
328
184
131
58
47
257
49.7
74
64
13
13
18
43
39
30
11
32
14
                         Totals:
              1,720
                                                               32
Notes:    Grissom, White, Freeman, and Chaffee fall within the baseline, and are therefore in
          the coastal subcategory.  Elly is a processing platform with no Hells.
          (*) Installed 1985 or later.

Source:   CCC,  1988; MMS, 1989; MMS, 1990; CDC, 1991a,b.

pacbat.MkS                                              07-Oct-92
                                            4-11
-------
(artificial islands in the Wilmington field).  These are assumed to be in the coastal subcategory,
that is, they lie landward of the baseline that marks the seaward limit of inland water (Avanti,
1991). Platform Elly is not included because it is a processing platform with no wells.
Although Platform Elly would be likely to incur costs if new equipment were needed to meet
increased pollution control requirements, the costs associated with that equipment and its
operation are assigned to the production platforms that feed into Platform Elly.  This  is
conservative in that no economies of scale are considered for the use of a centralized  processing
platform.
       4.1.3  Alaska

       The platforms in Copk Inlet are in the coastal subcategory and are not included in the
analysis for the offshore category. Production is occurring from two gravel islands in the
Beaufort Sea in the Endicott field. These structures are in state waters in the offshore
subcategory, but are not included in the count of structures estimated to bear increased pollution
control costs because current state requirements mandate the reinjection of produced water.
        4.1.4 Summairy

        Table 4-7 is a summary of the count of existing structures estimated to bear incremental
 pollution control costs for a 3-mile boundary. Table 4-8 presents the same total count of
 structures, but subdivided by a 4-mile boundary.
                                             4-12
-------
TABLE 4-7

BAT STRUCTURES IN OFFSHORE WATERS
ALL STRUCTURES ESTIMATED TO BEAR INCREASED POLLUTION CONTROL COSTS
BASED ON 3 NAUTICAL MILE BOUNDARY
Number of Structures
Oil Only
Project Type
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 16
Pacific 40
Pacific 70
Pacific Totals
Totals
Within
76
10
3
1
0
0
0
90
0
0
0
0
90
Beyond
69
11
41
18
22
5
1
167
0
0
0
0
167
Gas Only
Within
89
6
4
2
0
0
0
101
0
0
0
0
101
Beyond
438
264
172
158
104
39
0
1,175
1
0
0
1
1,176
Oil and Gas
Within
0
3
6
0
1
0
0
10
5
0
5
10
20
Beyond
222
95
114
127
218
196
2
974
3
5
13
21
995

Total
Within
165
19
13
3
1
0
0
201
5
0
5
10
211
Beyond
729
370
327
303
344
240
3
2,316
4
5
13
22
2,338
Total
894
389
340
306
345
240
3
2,517
9
5
18
32
2,549
 Notes:      There are currently no facilities in the Atlantic region.

            Facilities -£3 KeTnne? JESS'S StSSS&l.l seas in the Beaufort Sea  Masfc, area are
            required by the State to  re-inject produced water and will not incur incremental costs.

 Sources:   EPA estimates;  MMS, 1988,  CCC, 1988, SAS runs dated July 1990.

        21-Dec-92     prof_bat.nk3
                                                      4-13
-------
TABLE 4-8

BAT STRUCTURES IN OFFSHORE WATERS
ALL STRUCTURES ESTIMATED TO BEAR INCREASED POLLUTIOM CONTROL COSTS
BASED ON 4 NAUTICAL MILE BOUNDARY
Project Type
 Oil Only

Within   Beyond
                                                             Number of  Structures

                                               Gas Only             Oil and  Gas

                                             Within   Beyond       Within   Beyond
                                                         Total

                                                     Within   Beyond    Total
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40

Gulf Totals
   102
    11
    26
     1
     0
     0
     0

   140
 43
 10
 18
 18
 22
  5
  1

117
151
 30
 13
  3
  0
  0
  0
376
240
163
157
104
 39
  0
197    1.079
27
16
16
 2
 4
 8
 0

73
195
 82
104
125
215
188
  2

911
280
 57
 55
  6
  4
  8
  0

410
614
332
285
300
341
232
  3
894
389
340
306
345
240
  3
                                          2,107   2,517
Pacific
Pacific
Pacific
Pacific
Totals
16
40
70
Totals

0
0
0
0
140
0
0
0
0
117
0
0
0
0
197
1
0
0
1
1,080
7
0
7
14
87
1
5
11
17
928
7
0
7
14
424
2
5
11
18
2,125
9
5
18
32
2,549
Notes:     There are currently no facilities in the Atlantic region.
           Facilities in Cook Inlet are in the coastal subcategory.
           Facilities seaward of the inner boundary of the terretorial seas in the Beafort Sea, Alaska area are
           required by the State to re-inject produced water and will not incur incremental costs.

Sources:   EPA estimates; HHS, 1988. CCC, 1988, SAS runs dated July 1990.

       21-Dee-92     prof_bat.wk3
                                                 4-14
-------
4.2    PROJECTED WELLS


       This section presents projections of offshore oil and gas activity for the 15-year period

following the promulgation of the rule4. These projections are used in later sections to calculate

total costs of the alternative regulatory options for BAT/NSPS wells and NSPS platforms.  Two

different methods are used for the projections:
              MMS data form the basis for projections in the Gulf of Mexico and Alaska.
              Efforts in state waters are scaled from efforts in federal waters.

              Future production for the Pacific and Atlantic is based on Presidential decisions
              determining where drilling is prohibited.
       Presidential actions also have deferred the leasing of an area offshore Florida until the

year 2000, and another area is being set aside for study for the next 5 years.  Both of these areas

are in the Eastern Gulf of Mexico. The projections provided by MMS did not include a detailed

breakdown of production within the Gulf of Mexico. The MMS projections are based on 1985

data. At that time, the conditional mean estimate of undiscovered, economically recoverable

resources in the Eastern Gulf of Mexico  was about 5 percent of the estimated resources from the

Western and Central section of the Gulf (MMS, 1988b, Table 63).  Although the proportion of
resources assigned to the deferred areas  is unknown, even if the entire Eastern Gulf of Mexico
was deferred, it would result in no more than a 5 percent change in the projections.  Because the

Eastern Gulf of Mexico is a small proportion of the resources, and because the data needed to

adjust the MMS forecasts appropriately is lacking, no change was made to the well and platform

projections for  the Gulf presented in the March 1991 proposal. The projections for the Gulf and
    "At the end of the 15 years, the number of structures coming into production is assumed to be
equal to or less than the number of structures going out of production. The initial proposal for
effluent guidelines for the oil and gas offshore subcategory appeared in 1985. Hence, the NSPS time
frame was originally established as 1986-2000.  Shifting the starting year for the 15-year projections
to 1991 and  1993 resulted in a variation  in the number of wells of  approximately  ±3 percent
(Kaplan, 1992). Since the variations were both higher and lower than  the estimates made for the
1986-2000 period, it is assumed that the estimates for the 1986-2000 period were representative of
the 15-year period following promulgation of the rule. The economic impact analysis for the 1991
reproposal investigated the effects of three oil price scenarios where the regional number of wells
varies much more widely than 3 percent. The reader is directed to the 1991 EIA for a discussion
of the sensitivity of the results to different oil price scenarios.

                                           4-15
-------
Alaska are presented in Section 4.2.1; those for the Pacific and the Atlantic are discussed in
Section 4.2.2 and Section 4.23, respectively.
       4.2.1  Gulf of Mexico and Alaska

       The projections presented below begin with the MMS production projections (Section
4.2.1.1), which serve as a basis for the well projections (Section 4.2.1.2). These projections are
for the Outer Continental Shelf area, i.e., federal water under U.S. Department of the Interior,
Minerals Management Service. Estimates of future activity in state offshore waters follow.
Finally, estimates of unproductive efforts  are included to generate the total number of wells
drilled.
       42.1.1 MMS Projections—Productive Wells in Federal Waters

       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
                                           4-16
-------
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.

       Based on this methodology, MMS published 30-year projections  of OCS oil and gas
production for four major regions: the Atlantic, the Gulf of Mexico, the 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. 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.5  Based on these resource estimates, these are the ratios of $21 to $32 per barrel
resources for the Gulf of Mexico and Alaska:
              Region
              Gulf
              Alaska
Ratio of
$21/bbl to
$32/bbl
Resources
0.965
0.098
These ratios mean, for example, that using the MMS resource estimates for the Alaska OCS at
$32 per barrel (i.e., MMS projections at $32 per barrel equal 100 percent), the Agency estimates
that 9.8 percent of these Alaskan resources would be developed if the price of oil fell to $21 per
barrel.  These ratios were used to develop alternative forecasts from the $32 per barrel forecast.
Table 4-9 presents the MMS production projections based on an oil price of $21/bbl (1986
dollars).
    5See MMS, 1987, Appendix F, p. F-75.  The oil prices in the SID are in 1984 dollars 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.

                                           4-17
-------
TABLE 4-9

HHS FEDERAL DCS HOOEL OUTPUTS:
TOTAL 1993. 1995, AND 2000 PRODUCTION
$21/BBL OF OIL - 1986 DOLLARS
                                      Region

Production    Year          Gulf of Mexico         Alaska
                                                    Total
Oil (Barrels per Day)

              1993'
              1995
              2000
                    807,000
                    851,000
                    846,000
     0
 9,400
38,000
807,000
860,400
884,000
Gas  (Trillions of Cubic Feet per Year)
               19S3
               1905
               2000
                       3.04
                       3.11
                       3.09
     0
  0.01
  0.02
   3.04
   3.12
   3.11
 Source:   HNS,  15'87; HHS,  1985a.
                                                   4-18
  t4-9.ufc3
21-Dec-92
-------
      Four sets of projections, based on oil price and development assumptions, were presented
in EPA, 1991a, and the reader is referred to that document for more details.  Only one set of
projections is presented in this report in order not to obfuscate changes due to re-costing of
pollution control options.

      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:
Oil Production
Gulf
Alaska
Initial
Rate of
Production
Barrels/Day
    500
  1,960
Years
at Peak
Production
Years
    2
    2
Annual
Decline
Rate
Percent
  15
  10
 Gas Production
 Gulf
 Alaska
   MMCFD
     4.0
     15
    4
   16
Percent
  15
  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 rate of gas production
 in the Gulf is based on data provided by MMS.  The decline rates were developed from several
 information sources. For Alaska, MMS used unique decline rates for each year of production;
 the EPA analysis used 10 percent and 15 percent for oil and gas, respectively, which are the
 averages of the MMS decline rates (MMS, 1985b).

       Table 4-10 shows the OCS production from pre-1986 sources over time.  Although there is
 production from the Endicott field in Alaskan state offshore waters, there is currently no OCS
 production in the Alaska region.  In Table 4-10, pre-1986 oil production declines from 285,000
 barrels per day in 1993 to 91,000 barrels per day in 2000. Pre-1986 gas production declines from
 1.47 trillion cubic feet in 1993 to 0.47 trillion cubic feet in 2000.
                                            4-19
-------
TABLE 4-10

OCS PRODUCTION FROM PRE-1986 SOURCES
$21/BBL OF OIL - 1986 DOLLARS

Production Year
Oil (Barrels per Day)
1993
1995
2000
Gas (Trillions of Cubic
1993
1995
2000
Region
Gulf of Mexico

285,000
206,000
91,000
Feet per Year)
1.47
1.06
0.47

Alaska

0
0
0

0
0
0

Total

285,000
206,000
91,000

1.47
1.06
0.47
Notes:    Gulf: calculated using a 15 percent decline rate.
          Ho OCS production from Alaska.

Source:   EPA estimates based on pre-1986 production levels in the HHS
          forecast.
 T4-10.UK3    2'!-Dec-92
                                                 4-20
-------
      F..i..ra PCS Prod..^in« fa»m 1986 *nd T^ter Sources. Although there is production from
the Production levels in 1986 and later were developed by subtracting the pre-1986 sources of
production (Table 4-10) from total projected production (Table 4-9).  Table 4-11 illustrates this
calculation for total production.  The MMS data on which the projections are based indicate oil
production from wells drilled in  1986 and later will rise from 522,000 barrels per day in 1993 to
793,000 barrels per day in 2000.  The same data indicate gas production will rise from 1.57
trillion cubic feet in 1993 to 2.62 trillion cubic feet in 2000.

       Table 4-12 shows the 1986 and later sources of production for each region. These
production amounts were'developed in the same manner as the total 1986 and later production
levels shown in Table 4-11.                                                        .,  ..
       4.2 J.2 Productive Wells in State Waters

       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-td-federal oil and gas activity in
 Alaska was found to be 3:1.

       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 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.  The only state waters where
 gas production will be significant will be in the Gulf of Mexico. Table 4-13 presents estimates of
 state water  wells for 1986-2000. There are an estimated 538 projected wells for the Gulf of
 Mexico, and 69  for Alaskan state waters.

        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

                                             4-21
-------
TABLE 4-11

DCS PRODUCTION FROM 1986 AND LATER SOURCES
S21/BBL OF OIL - 1986 DOLLARS

Production . Year

Pre- and
Post-1986
Sources
Production
Pre-1986
Sources

1986 and
Later
Sources
Oil (Barrels per Day)
                      1993
                      1995
                      2000
                           807,000
                           860,400
                           884,000
285,000
206,000
 91,000
522,000
654,400
793,000
Gas (Trillions pf Cubic Feet per Year)
1993
1995
2000
3.04
3.11
3.09
1.47
1.06
0.47
1.57
2.05
2.62
Notes:
Source:
Pre- and Post-1986 production from MMS projections; see Table 4-9.
Pre-1986 production; see Table 4-10.
             EPA estimates.
T4-11.W3
 21-Dec-92
                                                4-22
-------
 TABLE  4-12

 1986 AND  LATER PRODUCTION
 S21/BBL OF OIL -  1986 DOLLARS
 Production   Year
                       Region

              Gulf  of Mexico
  Alaska
                                                                   Total
.Oil  (Barrels per Day)

               1993
               1995
               2000
                     522,000
                     645,000
                     755,000
       0
   9,400
  38,000
522,000
654,400
793,000
 Gas (Trillions of  Cubic  Feet per Year)

              1993                   1.57
              1995                   2.05
              2000                   2.62
                                         0
                                      0.01
                                      0.02
                   1.57
                   2.06
                   2.64
 Source:    EPA estimates developed using Table 4-9 and Table 4-10.
 T4-12.WK3
21-Dec-92
4-23
-------
 projected wells, however, does not affect the per-well costs (see Section Six) used in the
 economic impact analysis of model projects (discussed in Section Seven). If no or minimal
 impacts are seen on representative projects or companies that bear these costs (Section Eight),
 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 is about 8 percent  of all activity  (see Table
 4-13). 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 8 percent; although 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.
       4.13,3 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 approximately 60 percent. This
 value was used to forecast the number of dry holes in our projections.
       4.2.2 California

       4.22.1  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 (DOI,
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
                                           4-24
-------
TABLE 4-13

PRODUCTIVE WELL PROJECTIONS, 15-YEAR PERIOD
GULF OF MEXICO AND ALASKA
$21/BBL OIL

Region
Wells
Jurisdiction Oil Gas Total
Gulf of Mexico   Federal
                 State
                 Total
                   3,102    2,812    5,914
                     283      255      538
                   3,385    3,067    6,452
Alaska
Total
Federal
State
Total
23
69
92
6
0
6
29
69
98
                   3,477    3,073    6,550
Source:  EPA estimates.

       21-Dec-92
 T4-13.WK3    21-Dec-92
                                                 4-25
-------
Channel, will not be available until at least 1996, and then only if further studies indicate that
development appears viable in relation to the environmental impacts and economic
considerations.  This means that the only likely exploration and development will occur on
existing federal leases.
             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 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"). Additionally, the State Lands Commission has declared other designated areas
(calendar items adopted 10/26/88 and 12/6/89) to be off limits for new oil and gas leasing and
development.  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 blowout 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 1990 supporting the Lands Commission's decision to deny
the permit (Meier, 1990).  ARCO filed quitclaim deeds for the two Coal Point leases (OGJ,
1992).  Given these actions, EPA assumes no future activity in Pacific state waters.
                                          4-26
-------
       4.23.3  Pacific Well Projections

       Activity in federal waters off California will be limited to development drilling on existing
platforms and exploratory effects on existing leases.  The average annual number of wells drilled
in the Pacific during the 1986-1989 period is 32 (see Table 4-14). EPA 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.
       4.23 Atlantic

       The President's decision also cancels lease sale 96, in the Georges Bank region of the
North Atlantic, and essentially prohibits any activity in 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
assumed no Atlantic activity in these projections.
       4.2.4 Summary
      4.2.4.1  Distance From Shore
       Some of the regulatory requirements for the disposal of drilling fluids and drill cuttings
also depend on the distance from shore. For this effluent stream, three boundaries are
considered — 3 miles, 4 miles, and 8 miles. For the Gulf of Mexico, the March 1988 MMS
complex/structure data base for existing projects forms the basis of determining the distance from
shore for future projects (see Kaplan, 1990). For the Pacific, no activity is assumed to occur
within state waters. Since drilling can occur on existing leases, the distance from shore for the
seven Pacific platforms installed in 1985 or later was examined (Table 4-6).  The number of
projects in a given distance category is multiplied by the appropriate number of productive wells
for that model. The values provide an estimate of the proportion of wells by distance from shore
(Table 4-15).  Drilling efforts in Alaska are exempt from the zero discharge requirements and
                                            4-27
-------
 TABLE 4-14
 ACTUAL DRILLING RATES FOR THE PACIFIC - 1986-1989

Type
Exploratory
Development
Total

1986
3
34
37
Ye
1987
4
39
43
ar
1988
3
29
32

1989
5
11
16

Average
4
28
32
 Source:  MMS, 1990.
                                             4-28
T4-14.WK3
07-Oct-92
-------
 TABLE 4-15
 BREAKDOWN OF PACIFIC  BAT UELIS
 Model
 Project Type
          Total Number of Wells
4-6 Miles  6-8 Miles  8+ Hiles
Total
 Pacific 40             66          0         33         99
 Pacific 70             180         60          0        240
 Total                   246         60         33        339
 Percent of Wells      72.6%      17.7%       9.7%     100.0%
 Avg. Annual #           23          63         32

 Note:    Distances are  based upon Nautical Miles.
 Source:  MMS,  1989.
                                          4-29
T4-15.WK3   12-Oct-92
-------
no breakdown is necessary for this region. Table 4-16 summarizes the average annual number of
wells drilled (BAT and NSPS) by region and distance from shore.  Well projections by distance
are back-calculated from platform projections. Slight rounding errors between earlier tables and
Table 4-16 may be noticed.
      4.2A.2  BAT and NSPS Drilling Efforts

      The final step in the well projections is to distinguish between BAT and NSPS efforts.
The 759 wells drilled per year includes all wells — productive, non-productive, exploratory, and
development.  The well projections therefore include both BAT and NSPS wells. BAT wells
encompass exploratory wells in addition to wells drilled on platforms installed prior to the
regulation. NSPS wells are drilled on platforms where site preparation and installation take
place after the regulation goes into effect.

      The breakdown between exploratory and development drilling is given in Table 4-17.  The
original projections for Alaska and the Gulf of Mexico derived the number of productive wells
from MMS estimates of future production.  The number of unproductive efforts was estimated
based on API data (API, 1988). API data also are used to subdivide the wells into exploratory
and development (API, 1992).  The API data are for all wells producing beyond the natural
shoreline and therefore include coastal efforts, but it is the best data available.  For Pacific,
drilling data for 1986-1989 were used to determine the average annual numbers of wells as well
as identify which of those efforts are exploratory (MMS, 1990).

      BAT wells include wells drilled on platforms  installed at the time  of the rule and which
complete their drilling program after the regulation  goes into effect. For analyzing the relative
proportion of new wells that would fall in this situation, Gulf of Mexico platforms with multi-year
drilling programs, i.e., the Gulf 12, Gulf 24, and Gulf 40 models, were considered.  Table
4-18 illustrates what might happen with these models. A Gulf 40 installed  a year before the
regulation goes into effect would have its last year of drilling (8 wells) occur one year after the
regulation goes into effect. A Gulf 40 installed in the year of regulation  would have two years of
drilling after the regulation (12 and 8 wells,  respectively). A Gulf 12 and a Gulf 24 installed in
                                           4-30
-------
TABLE 4-16

AVERAGE ANNUAL NUMBER OF WELLS DRILLED,  BAT AND  NSPS
S21/BBL SCENARIO
15 YEAR PERIOD
Scenario                                               Gulf
                                                                       Region

                                                               Pacific     Alaska*
                                      Total
3-Mile Boundary
      Average Annual Number of Wells
      Percentage Within 3 Miles of Shore
      Number Within 3 Miles of Shore
      Number Beyond 3 Miles of Shore
4-Mile Boundary
      Average Annual Number of Wells
      Percentage Within 4 Miles of Shore
      Number Within 4 Miles of Shore
      Number Beyond 4 Miles of Shore
8-Mile Boundary
715
8.4X
 60
655
715
 10X
 72
643
32
 OX
 0
32
32
 OX
 0
32
12
na
na
na
12
na
na
na
759
  8%
 60
687
759
  9X
 72
675
Average Annual Number of Wells
Percentage Within 8 Miles of Shore
Number Within 8 Miles of Shore •
Number Beyond 8 Miles of Shore
715
19X .
136
579
32
90X
29
3
12
na
na
na
759
22%
165
582
 Note:   Alaska  is exempt from zero discharge requirements for drilling fluids and drill cuttings.

 Source: EPA estimates.
 T4-16.WK3    21-Dec-92
                                                   4-31
-------
TABLE 4-17
OFFSHORE EXPLORATORY EFFORTS



Region
Alaska
Pacific*
Florida
Louisiana
Texas
H. COM
Mississippi
Alabama
Total COM



Exploratory
113

24
5,446
.2,440
412
1
12
8,335


Percent
Total Exploratory
449 25X

24
24,375
4,027
653
1
24
29,104 28.6%
Average
Annual
Number
of Wells
12
32




715
Average
Annual
Number of
Exploratory
Wells
3
4




205
Notes:  (*)   Estimates for the Pacific ore taken from drilling records for

                  1986-1989 from HHS, 1990.            .......   .««,
             Estimates for Alaska and Gulf of Mexico taken from API,  1992.


explore.wk3
    12-Oct-92                                          --..,..
                                                  4-32
-------
the year of the regulation would have the last year of drilling occurring after the regulation. The
next columns in Table 4-18 contain the total and average annual number of such platforms. The
right-hand column contains the number of productive wells that might be BAT. These 144 wells
are approximately 2.2 percent of the estimated productive wells for the Gulf of Mexico (see EIA,
Table 4-13).

      The overall percentage would be lower. Development wells have a higher discovery
efficiency than exploratory wells (71 percent, Table F-4). Accounting for dry development well,
BAT wells would form 1.9 percent of the Gulf of Mexico wells (i.e., (144/.71)= 203 wells out of
10,752 wells (715 wells/year * 15 years)).  Approximately 30 percent of the projected wells for the
Gulf of Mexico, then, could be BAT wells.  The projections for Alaska do not have new projects
coming on line until after 1993.                  .     .

      Table 4-19 is a summary of the BAT and NSPS wells by region, about one-third of the
wells may be considered BAT. All wells in the Pacific are considered BAT wells because they
are either exploratory or occur on existing platforms. (The actual percentage of BAT wells will
vary in time. Most will be exploratory efforts. The number of BAT wells drilled on existing
platforms will decrease in time as those platforms complete their drilling programs. The
numbers given in Table 4-19 reflect the annual average number  of wells during the 15-year
period after the regulation.) Since there is no difference between BAT and NSPS requirements
and costs for drilling fluids and drill cuttings, no distinction is made for BAT and NSPS costs for
these effluents.
43    PLATFORM PROJECTIONS, 15-YEAR PERIOD
       43.1 Total Platforms

       To convert projections of well drilling in each region into projections of platform
 installations, EPA used selected model project sizes. Table 4-20 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
                                           4-33
-------
TABLE 4-18

ESTIMATED  PRODUCTIVE BAT WELLS IN  THE GULF OF KEXICO
                   Wells Drilled
Hodel
Platform
Gulf 40
Gulf 40
Gulf 24
Gulf 12

Year •
Regulation
Year Goes Into
Before Effect
12 12
12
12
6 *
BAT Wells
Year
After
8
12
6
4
Two
Years
After
8
Projected
Platforms
(15 years)
27
27
114
180
Average
Annual
Number
of
Platforms
1.8
1.8
7.6
12
BAT
Wells
14
36
46
48
Total Productive BAT wells in the Gulf of Mexico
                                                                                 144
Notes:"~~For conparison, 6,452 productive wells and 10,752 total wells are estimated
          for the Gulf of Mexico during the 15-year period.
 batwcll.wkS
 12-Oct-92
                                                  4-34
-------
TABLE 4-19            ,
SUMMARY OF BAT AND NSPS WELLS BY REGION

Region
Gulf
Pacific
Alaska
Total
Percent:
Number
Total
715
32
12
759
of Wells
BAT
215
32
3
250
33X

NSPS
500
0
9
509
67%
 TAB4-19.WK3
                   30-Oct-92
                                                4-35
-------
  TABLE 4-20

  PLATFORM CONFIGURATION SUMMARY
 ALASKA
                                PERCENT ALLOCATION OF REGIONAL  PLATFORMS

                                  FEDERAL WATERS         STATE  WATERS
                                                               PERCENT ALLOCATION OF REGIONAL  WELLS

                                                                FEDERAL WATERS         STATE WATERS
REGION
GULF
KCLL
SLOTS
1
JU.IIVC
WELLS
1
OIL
5X
GAS
15X
OIL
5X
: GAS
15%
OIL
0.4X
GAS
2%
OIL
1%
GAS
3%
 4
 6
 12
 24
 40

 24
 12
48(a>
 4
 6
10
18
32

18
10
40
32X
 8X
?5X
20X
10%

15X
 OX
85X
 35X
 17X
 22X
 11X
  OX

  OX
100X
  OX
 32X
 38X
 25X
  OX
  OX

  OX
  OX
100X
53X
SOX
 OX
 OX
 OX

 OX
 OX
 OX
 9X
 4X
22X
35X
29X

15X
 OX
85X
 18X
 13%
 34X
 34%
  OX

  OX
100X
  OX
 19X
 35X
 45X
  OX
  OX

  OX
  OX
100X
31X
66X
 OX
 OX
 OX

 OX
 OX
 OX
 Note:    (a) For platforms within 4 miles,  a gravel  island was utilized.

 Source:  EPA estimates based upon KHS data.
                                                         4-36
T4-20.WK3   21-Dec-92
-------
 the Gulf and three in Alaska. 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 total platform projections for the Gulf of Mexico and Alaska are shown in Table

 4-21.  For the period 1986-2000, the total number of platforms for the Gulf of Mexico is

 expected to be 755 and 4 for Alaska. As mentioned in Section 4.2, EPA varied the starting year

 for the 15-year projections, and found the estimate sufficiently accurate that there was no need
 to revise it.
       4.3.2 Platforms Within and Beyond the 3-Mile and 4-Mile Boundaries


       Certain regulatory options require different pollution controls depending on whether the

 platform is located within a specified distance of shore. The two boundaries analyzed for

 platforms are  3 miles and 4 miles from shore.  Tables 4-22 and 4-23 show the projects as

 categorized by the 3-mile boundary. Table 4-22 presents all structures, while  Table 4-23 shows
 only the oil-producing structures.
       For the NSPS projections, 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." For the Gulf, the MMS data base was used to determine the percentages of wells and
    The Clean Water Act (CWA) gives EPA jurisdiction over discharges to state and federal waters.
Under the CWA, state waters extend three miles from shore. Federal waters extend seaward of the
three mile mark.  Separate statutory authority exists for mineral  leasing rights.  The offshore
authority for mineral rights for Texas and Florida (on its Gulf side only) extends to three marine
leagues. The Department of the Interior Minerals Management Service has leasing authority for
waters beyond three marine leagues in Texas and Florida.

       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 is approximately 8 percent of all projected activity (see Tables 4-13)'.
Historically, more development has been off Louisiana (see Table 4-1). The approach taken in this
analysis, then, would lead to only a small overestimate of regulatory costs.

                                           4-37
-------
TABLE 4-21

PLATFORM PROJECTIONS - TOTAL
($21/bbl of oil - 1986 dollars)
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
60
11
28
32
47
61
59
68
55
60
59
58
54
54
3r
38
42
32
29
26
25
21
9
19
11

9
7
11115
759
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
GULF
1 4 6 12 24 40
WELL WELLS WELLS WELLS WELLS WELLS
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
1
1
1
0
1
1
6 109
4 76
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
1
1
1
1
1
0
1
0
1
0
0
41 1109
27 755
                                                4-38
 T4-21.UK3   07-Oct-92
-------
TABLE 4-22

PLATFORM PROJECTIONS - WITHIN 3-HILES
($21/bbl of oil - 1986 dollars)
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
8
10
1
5
4
8
9
7
9
5
9
7
7
7
8
2
5
2
6
2
2
2
2
0
1
2
1
0
0
0
131
104
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 .
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
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
1 4 6 12 24 40
WELL WELLS WELLS WELLS WELLS WELLS
0
1
1
0
0
0
1
1
1
1
0
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3 11
2 11
0
3
3
0
2
2
3
3
2
3
2
3
2
2
2
2
1
2
1
2
1
0
0
0
0
0
1
0
0
0
0
42
34
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
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
0 128
0 102
                                                 4-39
T4-22.WK3    12-Oct-92
-------
TABLE 4-22 (Cent.)

PLATFORM PROJECTIONS - BEYOND 3 MILES
($21/bbl of oil - 1986 dollars)
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
45
50
10
23
28
39
52
52
59
50
51
52
51
47
46
36
40
36
36
30
27
24
23
21
8
17
10
5
9
7
984
655
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
GULF
1 4 6 12 24 40
WELL WELLS WELLS WELLS WELLS WELLS
0
5
5
0
2
2
4
6
5
6
5
5
5
5
5
5
4
4
4
4
3
3
2
2
2
1
1
1
0
1
1
3 98
2 65
0
14
15
3
7
9
12
16
16
18
15
16
16
15
15
14
11
12
11
11
10
8
8
7
6
3
5
3
2
3
2
303
201
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
1'1
9
10
9
9
7
7
6
5
5
2
5
3
1
2
2
248
166
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
41 981
27 653
                                                4-40
T4-22.WK3    12-Oet-92
-------
TABLE 4-23

PLATFORM PROJECTIONS - WITHIN 3-MILES
<$21/bbl of oil - 1986 dollars)
OIL PRODUCING 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
3
6
0
3
2
3
3
3
3
3
4
3
3
3
4
0
3
0
4
0
1
1
1
0
0
2
0
0
0
0
58
46
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
b
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
. 0
0
0
0
0
0
0
0
0
0
Q
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
1 4 6 12 24 40
WELL 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
3 0
2 0
0
1
2
0
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
0
0
0
0
0
1
0
0
0
0
18
15
0
1
2
0
1
1
1
1
1
1
1
1
1
1
1
1
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
1
1
1
1
1
1
1
d
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 55
0 44
  T4-23.WK3    07-Oct-92
                                                    4-41
-------
TABLE 4-23  (Cent.)

PLATFORM PROJECTIONS - BEYOND 3 MILES
($21/bbl of oil - 1986 dollars)
OIL PRODUCING PROJECTS
ALASKA
GULF
24 12 48 1 4 6 12 24 40
YEAR TOTAL UELLS WELLS WELLS WELL WELLS WELLS WELLS WELLS WELLS
1985
1986
1987
1988
1985'
1990
1991
1992
1993!
1994
1995
1995
1997
1998
1999
2000
2001
2002!
2002
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
1985-2015
1985-2000
0
20
22
8
10
11
15
18
21
22
22
20
22
19
17
-18
15
16
12
15
9
12
9
10
8
0
7
3
5
3
0
389
265
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
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 00
0 1 6
0 1 6
0 02
0 03
0 03
0
o
0
0
0
o
0
0
o
o
o
o
o
0
4
5
6
6
6
6
6
5
5
5
4
4
3
4
0 03
0 1 3
0 03
1 0 3
0 02
0 00
0 02
0 0 1
0 02
0 0 1
0 00
1 ' 2 17 109
0 1 12 74
0
1
2
1
1
1
1
1
1
2
2
1
2






1
1
1
1
1
1
0
0
0
0
0
0
28
19
0
5
6
2
3
3
4
5
6
6
6
5
6
5
4.
4
4
4
3
4
2
3
2
2
2
0
2
1
1
1
0
101
70
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
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
41 387
27 264
                                                 4-42
T4-23.WK3    07-Oct-92
-------
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
              Gulf 4
              Gulf 6
              Gulf 12
              Gulf 24
              Gulf 40

(See Kaplan, 1990.)
20.9%7
12.7%
 1.4%
 0/7%
 2.7%
 0.0%
       For Alaska, 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 adjoins state waters.  In the platform
projections, wells 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 4-13. These
islands are considered within 4 miles of shore for this analysis.


       Table 4-24 provides the breakdown of NSPS projects in the Gulf of Mexico and Alaska
that are within and beyond 4 miles of shore.  Table 4-25 shows the oil-producing platforms
within 4 miles of shore  and beyond 4 miles of shore for these regions.  No new platforms are
projected to be installed within the next 15 years in the Pacific or the Atlantic. Table 4-26
summarizes this information for the 3-mile boundary, while Table 4-27 presents the data for the

4-mile boundary.
    7This 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 because the per-project impacts are so similar.  This approach
 does not change the total estimated cost of an option.
                                            4-43
-------
TABLE 4-24

PLATFORM PROJECTIONS - UITHIH 4 MILES
(S21/bbl of oil - 1986 dollars)
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
11
13
1
6
5
11
12
10
12
8
12
10
10
10
11
4
8
4
8
4
4
3
3
1
1
3
1
0
0
0
186
142
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
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
1 4 6 12 24 40
WELL 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










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
T4-24.WK3
07-Oct-92
                                                         4-44
-------
 TABLE 4-24 (Cont.)

 PLATFORM PROJECTIONS- BEYOND 4 MILES
 ($21/bbl of oil - 1986 dollars)
 ALL PROJECTS
ALASKA
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
24 12 48
TOTAL WELLS WELLS WELLS
0
42
47
10
22
27
36
49
49
56
47
48
49
48
44
43
34
37
34
34
28
25
23
22
20
8
16
10
5
9
7
929
617
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



I


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
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
12
WELLS
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
24 40
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
1
1
1
1
1
0
1
0
1
0
0
41 926
27 615
T4-24.WK3
07-Oct-92
                                                        4-45
-------
TABLE 4-25

PLATFORM PROJECTIONS - WITHIN 4-HILES
($21/bbl of oil - 1986 dollars)
OIL PRODUCING 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
4
7
0
3
2
4 '
4
4
4
4
5
4
4
4
5
1
4
0
5
0
1
1
1
0
0
2
0
0
0
0
73
!58
0
0
0
• o
0
0
0
0
b
0
0
, 0
0
0
0
0
0
. 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
; 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
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
1 4 6 12 24 40
WELL 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
3 0
2 0
0
2
3
0
1
1
2
2
2
2
2
2
2
Z
2
2
1
2
0
2
0
0
0
0
0
0
1
0
0
0
0
33
27
0
1
2
0
1
1
1
1
1
1
1
1
1
1
1
1
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
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
 T4-25.WK3    12-Oct-92
                                                 4-46
-------
 TABLE 4-25 (Cont.)

 PLATFORM PROJECTIONS - BEYOND 4 MILES
 ($21/bbl of oil - 1986 dollars)
 OIL PRODUCING PROJECTS
ALASKA
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
24 12
TOTAL WELLS WELLS
0
19
21
8
10
11
14
17
20
21
21
19
21
18
16
17
14
15
12
14
9
12
9
10
8
0
7
3
5
3
0
374
253
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
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
GULF
1 4 6 12 24 40
WELL WELLS WELLS WELLS WELLS WELLS
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
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
0
1
2-;'
1 ,
1
1
1
1
1
2
2
1
2




i







0
0
0
0
0
0
23
19
0
5
6
2
3
3
4
5
6
6
6
5
6
5
4
4
4
4
3
4
2
3
2
2
2
0
2
1
1
1
0
101
70
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
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
41 372
27 252
                                                4-47
T4-25.WK3    12-Oct-92
-------
TABLE 4-26
TOTAL PROJECTED NSPS STRUCTURES
15 YEAR PERIOD
THREE HILE BOUNDARY
All Platforms
Region
Gulf







Alaska




Model

Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals

Cook Inlet K
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms - All Regions
Total

76
235
123
180
114
27
755

1
1
2
4
759
Oil

12
89
34
84
62
27
308

0
1
2
3
311
Gas

64
146
89
96
52
0
447

1
0
0
1
448
Within 3-Miles
Total

11
34
43
14
0
0
102

0
0
' 2
2
104
Oil

0
15
15
14
0
0
44

0
0
2
2
46
Gas

11
19
28
0
0
0
58

0
0 .
0
0
58
Beyond 3-Miles
Total

65
201
80
166
114
27
653

1
1
0
2
655
Oil

12
74
19
70
62
27
264

0
1
0
1
265
Gas

53
127
61
96
52
0
389

1
0
0
1
390
Note: (*) Oil only; all other projects are assumed to produce oil and casinghead gas.
   12-Oct-92          PROF NS.WK3
                                                          4-48
-------
TABLE 4-27

TOTAL PROJECTED NSPS STRUCTURES
15 YEAR PERIOD

FOUR MILE BOUNDARY
All Platforms
Region
Gulf







Alaska




Model

Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals

Cook Inlet 12
Cook Inlet 24
B. Gravel Island*
Alaska Totals
Total Platforms - All Regions
Total

76
235
123
180
114
27
755

1
1
2
4
759
Oil

12
89
34
84
62
27
308

0
1
2
3
311
Gas

64
146
89
96
52
0
447

1
0
0
1
448
Within 4 Miles
Total

23
60
43
14
0
0
140

0
0
2
2
142
Oil

0
27
15
14
0
0
56

0
0
2
2
58
Gas

23
33
28
0
0
0
84

0
P
0
0
84
Beyond 4 Miles
Total

53
175
80
166
114
27
615

1
1
0
2
617
Oil

12
62
19
70
62
27
252

0
1
0
1
253
Gas

41
113
61
96
52
0
363

1
0
0
1
364
Note: (*) Oil only; all other projects are assumed to produce oil  and casinghead gas.

   12-Oct-92          PROF NS.WK3
                                                         4-49
-------
 4.4    REFERENCES
 API. 1988. Basic Petroleum Data Book. American Petroleum Institute. Volume VIIL
       Number 1.  January.

 API. 1991. Basic Petroleum Data Book. American Petroleum Institute. Volume
       XI. Number 2. Stay. Section XI. Table 7.    ,

 API. 1992. Basic Petroleum Data Book. American Petroleum Institute. Volume
       XH. Number 2.  May. Section XI. Table 7.   .

 Avanti. 1991.  Delineation of the Baselines of Selected Coastal States.  Avanti
       Corporation. Vienna, VA. August.

 CCC. 1988.  Oil and Gas Activities Affecting California's Coastal Zone: A
       Summary Report. California Coastal Commission. December, pages 31-33.

 CDC. 1987. 72nd Annual Report of the State Oil and Gas Supervisor;  1986. California
       Department of Conservation. Division of Oil and Gas. Publication # PR06.
 CDC. 1991a. California Department of Conservation. Division of Oil and Gas. Point Fermia,
      Newport Beach, Offshore Map #01-1.

 CDC. 1991b. California Department of Conservation. Division of Oil and Gas. Rincon,
      West Montalvo, Offshore Map #02-1.

 DOI. 1990.  U.S. Department of the Interior.  Statement by the Secretary of the Interior
      Manuel Lujan Concerning the President's Decisions Regarding America's Offshore Oil
      and Gas Program. New Release. 8 June.

 EPA. 1985.  U.S. Environmental Protection Agency. Economic Impact Analysis of Proposed
      Effluent Limitations and Standards for the Offshore Oil and Gas Industry.
      EPA 440/2-85-003. July.

 EPA. 1991a.  U.S. Environmental Protection Agency. 40 CFR Part 435: Oil and Gas Extraction
      Point Source Category, Offshore Subcategory; Effluent Limitations Guidelines and New
      Source Performance Standards; Proposed Rule. Fed. Reg. 56(49): 10664-10715. March 13.

EPA. 1991b.  U.S. Environmental Protection Agency. Economic Impact Analysis of Proposed
      Effluent Limitations Guidelines and Standards of Performance for the Offshore  Oil and
      Gas Industry. February.

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.
                                         4-50
-------
Kaplan. 1992. Letter from Maureen F. Kaplan, Eastern Research Group, Inc., to
      Mahesh Podar, U.S. Environmental Protection Agency, dated September 14,1992.

Meier. 1990. Personal Communication between Eric M. Sigler, EPA, 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 the Interior, U.S. Minerals
      Management Service, 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.

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.

MMS. 1987. Secretarial Issue Document. Proposed Final, U.S. Department of the
      Interior, U.S. Minerals Management Service, April 1987.

MMS. 1988a. Complex/Structure Database, U.S. Department of the Interior, Minerals
      Management Service.

MMS. 1988b. Federal Offshore Statistics: 1986. U.S. Department of the Interior, U.S. Minerals
      Management Service, MMS 88-0020.

MMS. 1989. MMS Map #89-0100, Southern California Area, U.S. Department of the Interior,
      Minerals Management Service, December 1.

MMS. 1990. Pacific Update August '87 - November '89. U.S. Department of the Interior, U.S.
      Minerals Management Service, MMS 90-0013, Tables  11 & 13.

OGJ. 1992.  "ARCO Returns Tracts Containing Giant Oil Field to California," Oil and Gas
      Journal. 10 February, page 44.
                                          4-51
-------
-------
                                    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-two 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 32 baseline projects.
Section 5.1 presents a description of the economic simulation methodology while the 32 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-
                                           5-1
-------
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).

       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:

       •      Lease Cost - Bonus payments to federal or state governments or to private
              individuals for the land.
       •      Geological and Geophysical Cost - Cost of analytic work prior to drilling.
       »      Drilling Cost per Well.
       •      Cost of Production Equipment.
       •      Discovery Efficiency - The number of wells drilled for one successful well.
       •      Production Rates - Initial production rates of oil and gas and production decline
              rates.
       •      Operation and Maintenance Costs.
                                           5-2
-------
                                     INPUTS
Project Specific Inputs

•   Location

•   Cost characteristics

•   Production profile
General Exogenous Inputs

a   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-.   -
                                         I
                                     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 EPA economic model.

                                          5-3
-------
              Tax Rates - Rates for:  federal and state income taxes, severance taxes, royalty
              payments, depreciation, and depletion.
              Price - Wellhead selling price of oil and gas (also called the "first purchase price"
              of the product).
              Cost of Capital - Real rate of return for the industry.
              Timing - Length of time required for each project phase (i.e. leasing, exploration,
              delineation, development, and production).
The parameter values used in the analysis are summarized in Section 5.2 and described more
fully in Appendices A through I.
       5.13  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
                                           5-4
-------
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., incurred in the construction of offshore
platform be considered as intangible drilling costs (Houghton, 1987). Firms with both "upstream"
activities — exploration, developments 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.
                                            5-5
-------
       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.
       5.1.4 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:

       •     Internal rate of return (IRR).
       •     Corporate cost per unit of production.
       •     Production cost per unit of production.
       •     Net present value (NPV).
       •     Present value equivalent of production.
       •     Present value of all project costs.
       •     Present value of all project revenues.
       •     Present value of additional pollution control costs.
                                            5-6
-------
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.

       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.
                                             5-7
-------
        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.
 S3,    CONSTRUCTION OF REGIONAL OFFSHORE OIL AND GAS PROJECTS

        5.2.1 Overview

        Three regions are analyzed in this study — the Gulf of Mexico, the Pacific, 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-only. In all, 32 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 5-6. 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 years after lease sale
                                            5-8
-------
                                     TABLE 5-1

           DISTRIBUTION OF OIL, OIL/GAS, AND GAS PRODUCING PLATFORMS
                                BY REGION AND SIZE
                     PRODUCTION TYPE
REGION AND
WELLSLOT SIZE
Gulf
Gulf
Gulf
Gulf
Gulf
Gulf
Gulf
la«
lba
4
6
12
24
40
OIL OIL/GAS
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
, Yes
Yes
Yes
Yes"
Yes
GAS COMMENTS
;'t f • . _
Yes
Yes
Yes ' . '' • '• . ,..•„„
Yes -•-., •- . •"•<'. .".-••
, \ir-S •• ^
Yes
Yes •'• ''" '' ' * - "•• '•••••' '••'
No No gas-only platforms among large Gulf
Gulf 58             Yes     Yes    No


Pacific 16          No      Yes    Yes

Pacific 40          No      Yes    No


Pacific 70          No      Yes    No
                         f

Cook Inlet 12/24    No      Yes    Yes"

Beaufort Sea 48
platforms.             i  -   -  '

No gas-only platforms among large Gulf
platforms.
No gas-only platforms among large Gulf
platforms.            '

No gas-only platforms among large Gulf
platforms.           "
- Gravel island
- Platform
Norton Basin 34
Navarin 48
Yes
Yes
Yes
Yes
No
.No
No
No
No
No
No
No
No
No
No
No
infrastructure
infrastructure
infrastructure
infrastructure
for
for
for
for
gas
gas
gas
gas
delivery.
delivery.
delivery.
delivery.
Source:  EPA 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.

                                        5-9
-------
Gulf_dsc.wk1


BASELINE PARAMETERS FOR GULF OF MEXICO PROJECTS  IN  STATE WATERS

oi
Parameter
Timing'
lease to exp.
exp. to del.
del. to ctev.
dcv. to cp
Total-yrs to op.
Exploration
Lease Bid ($000)
G & G expenses
Discover)' eff.
Well cost ($000)
Platform/disc.
Delineation
Number of wells
Uell cost: ($000)
Development
Lease Eq. ($000)
Uell cost: ($000)
Nurpber of wells
Wells/yr installed
Production
oil (bopcl)
gas (HHcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 & H ($000)
Financial
oil (S/bbl)
gas (S/Hcf)
Corporate Tax Rate
Royalty
Severance - oil
Severance - gas
C
oil

0
0
0
1
1
$586
110.5X
14X
$4,355
4.3

0
$4,355
SO
$4,906
1
1

500
2
15%
$372

$23.82
34%
22%
6.19X
6.19X
iulf 1a
oi I/gas

0
0
0
1
1
$586
110.5X
14%
$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
6.19%

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
C
oil

0
0
0
1
1
$586
110.5%
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
oi I/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
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
22%
6.19X
6.19X
Note:   1986 dollars.
Source:  EPA estimates.
                                                 5-10
-------
Gulf_dsc.wk1

TABLE 5-3
BASELINE PARAMETERS FOR GULF OF MEXICO PROJECTS IN STATE  WATERS  (cont.)

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 - oil
Severance - gas
(
oil

0
0
1
1
2

$2,271
110.5%
14%
$4,355
4.3

0
$4,355

$4,664
$4,906
4
4

500
-
2
15%
$689

$23.82
-
34%
22%
6.19%
6.19%
iulf 4
oil/gas

0
0
1
1
2

$2,271
110.5%
14%
$4,355
4.3

0
$4,355

$4,664
$4,906
4
4

500
0.835
, ,. 2
15%
$689

$23.82
$2.57
34%
22%
6.19%
6.19%

gas

0
0
1
1
2

$2,271
110.5%
14%
$4,355
4.3

0
$4,355

$4,664
$6,302
4
4

-
4.000
4
15%
$689

-
$2.57
34%
22%
6.19%
6.19%
C
oil

0
0
1
1
2

$3,407
110.5%
14%
$4,355
4.3

1
$4,355

$6,996
$4,906
6
6

500
•,
2
15%
$910

$23.82
" -
34%
22%
6.19%
6.19%
iulf 6
oi I/gas

0
0
1
1
2

$3,407
110.5%
14%
$4,355
4.3

1
$4,355

$6,996
$4,906
6
6

500
0:835
2
15%
$910

$23.82
$2.57
34%
22%
6.19%
6.19%

gas

0
0
1
1
2

$3~;407
110.5%
14%
$4,355
- 4.3

1
$4,355

$6,996
$6,302
6
6

'
4.000
4
15%
$910

'-
$2.57
34%
22%
6.19%
6.19%
G
oil

0
1
0
2
3

$5,678
110.5%
14%
$4,355
4.3

2
$4,355

$11,660
$4,906
10
6

500
, • -
2
15%
$2,312

$23.82

34%
22%
6.19%
6.19%
iulf 12
oi I/gas

0
1
0
2
3

$5,678
110.5%
14%
$4,355
4.3

2
$4,355

$11,660
$4,906
10
6

500
0.835
2
15%
$2,312

$23.82
$2.57
34%
22%
6.19%
6.19%

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
15%
$2,312

-
$2.57
34%
22%
6.19%
6.19%
Note:  1986 dollars.
Source:  EPA estimates.
                                               5-11
-------
  gulf_dsc.wk1

  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)
Nurcber of wells
Wells/yr installed
Production
oil (bopd)
gas (HHcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 & M ($000)
Financial
oil ($/bbl)
gas ($/Hcf)
Corporate Tax Rate
Royalty
Severance - oil
Severance - gas

oil

0
1
0
2
3

$10,221
110.5%
14%
$4,355
4.3

2
$4,355

$20,988
$4,906
18
12

500
2
15%
$3,311

$23.82
34%
17%
-
Gulf 24
oi I/gas

0
1
0
2
3

$10,221
110.5%
14%
$4,355
4.3

2
$4,355

$20,988
$4,906
18
12

500
0.835
2
15%
$3,311

S23.82
$2.57
34%
17%
-

gas

0
1
0
3
4

$10,221
110.5%
14%
$4,355
4.3

2
$4,355

$20,988
$6,302
18
12

4.000
4
15%
$3,311

$2.57
34%
17%
-
Gulf
oil

0
1
0
2
3

$18,170
110.5%
14%
$4,355
4.3

2
$4,355

$37.312
$4,906
32
12

500
2
15%
$4,688

$23.82
34%
17%
-
40
oi I/gas

0
1
0
2
3

$18,170
110.5%
14%
$4,355
4.3

2
$4,355

$37,312
$4,906
32
12

500
0.835
2
15%
$4,688

$23.82
$2.57
34%
17%
-
Gulf 58
oil

o

2

6

$28,391
110.5%
14%
$4,355
4.3

2
$4,355

$58,300
$4,906
50
12

500
2
15%
$6,471

$23.82
34%
17%
'
oi I. /gas





6

$28,391
110.5%
14%
$4,355
4.3

2
$4,355

$58,300
$4,906
50
12

500
0..835
2
15%
$6,471

$23.82
$2.57
~34%
17%
-
Note:  1986 dollars.
Source:  EPA estimates.
                                               5-12
-------
  pac_dsc.wk1
21-Dec-92
  TABLE 5-5
  BASELINE PARAMETERS  FOR PACIFIC PROJECTS

Parameter
Timing
lease to exp.
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 (HHcf/day)
Yrs. at Peak Prod.
Prod. Decline rate
Annual 0 & M ($000)
Financial
oil ($/bbl)
gas ($/Hcf)
Corporate Tax Rate
Royalty
Severance - oil
Severance - gas
Pacific
oi I /gas

1
1
2
5

$2,236
110.5%
14%
$5,888
2

2
$5,888

$16,324
$2,357
14
12

900
0.478
2
33.0%
$4,008

$17.50
$1.89
34%
17%

16
gas

1
1
2
2
6

$2,236
110.5%
14%
$5,888
2

2
$5,888

$16,324
$5.157
14
12

5.000
4
22.0%
$4,008

$1.89
34%
17%
~
Pacific 40
oil/gas

1
2
3

8

$5,272
110.5%
14%
$5,888
2

2
$5,888

$38,478
$2,357
33
12

900
0.478
2
33.0%
$6,872

$17.50
$1 .89
34%
22%
.
Pacific 70
oi I /gas

!


10

$9,585
110.5%
14%
$5,888
2

2
$5,888

$69,960
$2,357
60
12

900
0.478
2
33.Q%
$11,212

$17.50
SI .89
34%
17%
-
Note:  1986 dollars.
Source:  EPA estimates
                                                  5-13
-------
akjdsc

TABLE 5-6
BASELINE PARAHETERS FOR ALASKA PROJECTS
                                Cook
                            Inlet 24
                                             Cook
                                          Inlet  12
Beaufort
  Gravel
             Beaufort
             Platform
                                      Navarin
                                     Platform
                                                                   Norton
                                                                 Platform
Parameter
  U«L Bid ($000)
  G & G expenses
  Discovery eff.
  Hell cost ($000)
  Platform/disc.

Delineation
  Hurfcer of wells
  Well cost ($000)
            ($000)
  Well cost ($000)
  Nuifcer of veils
  Wells/yr installed


Pl'o1lC(b?d)
  gas (HHef/day)

  Prld^DeclinV'rlte
  Annual 0 & H
    gas ($/Hcf)
  Corporate Tax Rate
  Royalty
  Severance - oil
  Severance - gas
                             oiI/gas
                                              gas
                                                           oil
                                                                        oil
                                                                                     oil
                                                                                                  oil
Timing
lease to exp.
exp. to del.
del. to dev.
dev. to op
Total-yrs to op.
1
1
2
2
6
1
1
2
2
6
2
3
3
3
11
2
3
4
3
12
2
3
3
3
11
2
2
2
3
9
     $56
   107.7%
      27%
 $13.851
       1
       2
 $13,851
$100,000
  $5,612
      20
      12
   1,960
     0.9

      10%
  $5,230
  $19-58
   $2.11
      34%
      22%
    $56
  107.7%
     27%
$13.851
      1
      2
$13.851
$50,000
 $3,188
     10
      6
  15.00

     15%
 $3.677
  $2.11
     34%
     22%
  $7.097
   107.7%
      27%
 $13,851
       1
       3
 $13,851
$270.000
  $5,612
      40
      12
   1,960

       2
      10%
 $18,100
  $14.80
       -
      34%
      22%
               $7.097
                107.7%
                   27%
              $13.851
                    1
                    _
                    3
              $13,851
             $303.700
               $5,612
                   40
                   12
                1,960

                    2
                   10%
              $25,300
               $14.80
                    -
                   34%
                   17%
                                                                                  $7,097
                                                                                   107.7%
                                                                                      27%
                                                                                 $13.851
                                                                                       1
                                                                                       3
                                                                                 $13,851
                                                                                $524,400
                                                                                  $5,612
                                                                                      40
                                                                                      12
                                                                                   1,960

                                                                                       2
                                                                                      10%
                                                                                 $19,900
                                                                                  $14.80
                                                                                       -
                                                                                      34%
                                                                                      17%
                                                                                               $4.968
                                                                                                107.7%
                                                                                                   27%
                                                                                              $13,851
                                                                                                    1
                                                                                                    3
                                                                                              $13,851
                                                                                             $174,500
                                                                                               $5,612
                                                                                                   28
                                                                                                   12
                                                                                                1.960

                                                                                                    2
                                                                                                   10%
                                                                                              $19,000
                                                                                               $14.80

                                                                                                   34%
                                                                                                   17%
Hote: 1986 dollars.
Source: EPA estimates.
                                         21-Dec-92
                                                        5-14
-------
 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 5-5). 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 5-6).  Appendix B contains a more complete description of timing assumptions.

       Lease costs are based on 1986 OCS sales in the Gulf, on previous sales for the other
 regions, and other factors (see Table 5-7 and Appendix C). They range from $56,000 for a Cook
 Inlet 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. Discovery
 efficiencies for the Gulf, Pacific, and Alaska are 14 percent, 14 percent, and 27 percent,
 respectively (see Table 5-8 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 5-9 and Appendix D). The average cost for an offshore 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 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, 1987b); see Table 5-10. Alaska development costs are based on the

                                           5-15
-------
$lease.wk1
21-Dec-92
TABLE 5-7
LEASE PRICES FOR HODEL PROJECTS
Region
Gulf






Pacific


Alaska


Number of
Model Producing Production
Project Wells Ratio
1
4
6
12
24
40
58
16
40
70
Cook Inlet
Cook Inlet-gas
Beaufort-gravel
Beaufort-plat.
Norton
Navarin
1
4
6
10
18
32
50
14
33
60
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
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
$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
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
$568
$2,271
$3,407
$5,678
$10,221
$18,170
$28,391
$2,236
$5,272
$9,585
$56
$56
$7,097
$7,097
$4,968
$7,097
Note:  1986 dollars.
Source:  EPA estimates.
                                                5-16
-------
disc eff.uk!
TABLE 5-8
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
GRAND TOTAL
Oil
20
44
0
0
0
44
0
0
267
45
0
312
376
Gas
7
10
0
0
0
10
2
0
349
273
0
624
641
Dry
73
294
8
6
38
346
0
24
3999
1732
241
5996
6415
Number of
Exploratory
Discovery, Wells Per
Total Efficiency Discovery
100
348
8
6
38
400
2
24
4615
2050
241
6932
7432
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.14
3.70




7.41





7.41
7.31
Note:  Well count includes wells in both Federal  and State waters.

Source:  API, 1988;  MHS, 1986b.
                                                    5-17
-------
S
1
         3
               CO —*
               O 0
               U 31
               CO
               O 4J
               o o
                  o
               Q.X-
               Q> ««^

               O
              Q.H-

              o
               .  *

              SLS
              S.^
CO
O 4->

"8
              Q-H-
              CJ %^
              a
       «— o ro co in    r^ c
                                            co
                                              «

                                            C3
                                            O
                          o» N. »-o CM co ro   r^«-c
                          cocON-«o«oino   rvj«o«
                                    •* -
                                    CO »
                          •4-co ro ro co co co   >-<
                                               5£i
                         *o    ro «— co j

                         I-    ro«-M
                                 s
                         o o£ in o NO *
                               - .   -  , .  .    o ro <-
                               roroco **• O£ ** OS   v- "^- -*
                         OOONT-ajinos   OSO.N.
                         co o co -* uj co uj   cooro
                                      a
 u\ co o-D-az t^ tz   in CO in
 i>«—CM in oc«-os   o«— o
  •  •••UJ«UJ    ••«
                                              ro e\io
                                              CM N- **•
                                              vtwvt
                         «— N. co in a: ro os
                         f\j K -» g> cu S. o:
                         N. •* co 6. UJ co uj
           o^ >o in
          * as in o«
           UJ CM *4-
           to c
           h* >
           N- »
«-   o
ro   o
                                 in   CM in
                        ro«-CM(vi   eo ro
                        vna vi vt   v> v>
                        N- N. ro o a: r^ ro
                        sr o> »- •* on CM ro
                     N- CON-
                     -* oro
tno»-»co    o£. co r
                        co eo >o ro UJ in
                       i rviin   o
                       SfeS   5!
                           ••-co    it
                           C c    co
                         _ Jr <0    CO
                         CO O •—    —'
                        ^£ «4- CO  CO ^
                         CO 'r- ••-  CO I

                        —• "co o  a> 5 *  o
                o   < t °    u-
                eo   t O •—    t
                a.   o t- i    O
                                                                    X
                                                                    c.
                                                                    O
                 u

                4-> '
                 CD
                                                      O
                                                    > c

                                                   CO CO
                                                   t- cy
                                                   CO 4J



                                                   II


                                                   ££
                                                   O Ul
                                                   1_
                                                   t_

                                                   U'GJ

                                                      O
                                                i
                                                CO
                                                      5-18
-------
Equip.wkl

TABLE 5-10
LEASE EQUIPMENT COSTS - GULF AND PACIFIC REGIONS
Region f
Gulf






Pacific


1
1
Toject
1b
4
6
12
24
48
58
16
40
70
dumber of
'reducing Lei
Wells Co:
1
4
6
10
18
32
50
14
33
60
ase Equipment
its ($MH 1986)
$1.166
$4.664
$6.996
$11.660
$20.988
$37.312
$58.300
$16.324
$38.478
$69.960
Source:  EPA estimates.
                                                5-19
-------
Steelhead platform in Cook Inlet and on data in Oil and Gas Technologies for the Arctic and
Deepwater (OTA, 1985); see Table 5-11.

       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 5-12).
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
5-13 and 5-14, 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), or 16
years (Cook Inlet, Alaska). Appendix G contains an expanded discussion of these parameters.

       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 5-15 summarizes the projected O&M costs for Gulf of Mexico projects.
                                           5-20
-------
      (A
      h-
      O
      S

      I
c   in uj
Q> -^ \O
3 O
4-» »~
3E
CJ Z
D) t- E
C  *-"
§ 44

O







8
'o*
£_
Q.
t> v- ro in o o
in *— CM P*«- o o
N- ro NO ^O in tn

o o co o o o
** s^ CM. Ntf- t ** o o o
o CM N- N- o in
tf? 40  •- CO
(0 •*- C (O O O>
«* CO •>- L.
Q_ CO CO O 4^ 4^
CD (0 Q) O
4J CO 4J — • — •-
t_ C I- C C
0 •- C 0 -- *-
H- L. O H-
3 CO 4J 3 -^ ^
(D > (- CO O O
CU CO O O O O
00 Z Z 00 U U

•







c
o
4j
c
CO
CO
o
en
(-
Q
H-
2
o
CO

«*-
01
•o

0)
0
L.
a.


u
.I?
o a.





•° ^1
U) >5 J2
C- -4- CO
CO • C.
= °€
CO
^O "O t-
CO 0) 0)
O 4-» O



•^ 0) U
"° a

£- CO L.
CO 01 O
O H-
co ••-
4-* t- 4-*
8 *S


. ?ii


u
a)
o


















»
o>

4J
c-
a
0)
Q:

u
§
o
o
U)
I
*~

0)
L.
O
J=
CO
tfr-
O

g
*~






m
a
(>
<





u
c.
g
CO
                                              5-21
-------
TABLE 5-1?.

DEVELOPHEMT WELL COST - 1986 DATA*
Number of
Development
Uells Per
Type of Producing
Region
Gulf

Pacific

Alaska

Production
oil,
gas
oil,
gBS
Oil,
gas
oi I/gas

oi I/gas

oi I/gas

Well


1
1
1
1
1.4
1.4
.09
.09
.12
.12
Average
Depth
(ft)
9,
11*
6,
6,
10,
7,
885
174
872
477
868
721
Cost per foot ($/ft>

Productive
$340.37
$408.05
$267.98
$721.18
$335.47
$231.95


Composite Cost
per
Development
Dry
$389
$389
$833
$833
$1,507
$1,507
.81
.81
.59
.59
.90
.90
$4
$6
$2
$5
$5
$3
Well ($)
,905,866
,301,845
,357,117
,157,007
,612,431
,187,985
Note:    <*) Current dollars.
Source:  EPA estimates, see Table D-2.
                                                  5-22
-------
                                 TABLE 5-13

                PEAK OFFSHORE PER-WELL PRODUCTION RATES
                                               OIL AND GAS
REGION
Gulf






Pacific


Alaska3
Cook Inlet

Beaufort Sea -
Beaufort Sea -
Norton
Navarin
PROJECT
1
	 4
6
12
24
40
58
16
40
70

12
24
Gravel 48
Platform 48
34
48
OIL ONLY
BOPO
500
500
500
500
500
500
500
900
900
900

—
1,960
1,960
1,960
1,960
1,960
BOPD
500
500
500
500
500
500
500
900
900
900
-
—
1,960
— •.
. 	 .
__
--
MCF/DAY
835
835
835
835
835
835
835
478
478
478

—
900
—
—
—
—
GAS-ONLY
MCF/DAY
4,000
4,000
4,000
4,000
4,000
4,000
4,000
5,000
__
—

15,000
—
— -



Source;  EPA estimates.

     'There is no infrastructure to transport produced gas  from the Arctic
scenarios.
                                   5-23
-------
                                 TABLE 5-14




                        PRODUCTION DECLINE RATES
                                            PRODUCTION DECLINE RATES  (%)
REGION
Gulf






Pacific


Alaska




OIL-ONLY
PROJECT OIL/GAS
1
4
6
12
24
40
58
16
40
70
Cook Inlet
Beaufort Sea - Gravel
Beaufort Sea - Platform
Norton Basin
Navarin Baein
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
—
— —
— —
—
— * Not applicable.




Source:  EPA estimates.
                                    5-24-
-------
gulf_o&m.wk1

TABLE 5-15
OPERATING COSTS FOR GULF OF MEXICO PLATFORMS
Project
Number of
Uellslots
Water
Depth (ft)
Cost
($1986)
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6

Gulf 12
Gulf 24
Gulf 40
Gulf 58
 1
 1
 4
 6

12
24
40
58
 33
 33
 33
 33

 66
100
200
590
  $372,213
  $199,882
  $689,324
  $910,137

$2,311,861
$3,310,725
$4,688,455
$6,471,456
Source:  EPA estimates.
                                                5-25
-------
       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 5-16). 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 for comparability with all the other data in the
economic models (Table 5-17). 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 uncertainly around the point estimate used in the computer simulations.
Table 5-18 lists the annual average wellhead price for oil from 1980 to 1990, The price for a
barrel of oil rises by additional 50 percent from $21.59 in 1980 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 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 (1986 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 5-19).  For the  past five years, gas prices per Mcf have averaged 10.8 percent of the
price  of a barrel of oil (Table 5-20), and this factor is  used to estimate regional wellhead prices
for gas.
                                           5-26
-------
gulf_o&ni.wk1

TABLE 5-16
OPERATING COSTS FOR PACIFIC AND COOK INLET PLATFORMS
Project
Pacific 16
Pacific 40
Pacific 70
Cook Inlet 24
Cook Inlet 12
Number of
Uellslots
16
40
70
24
12
Water
Depth (ft)
300
300
1000
50
50
Cost
($1986)
$2,831,820
$4,772,439
$7,786,100
$3,268,733
$2,298,424
Regional
Cost
Factor
1.44
1.44
1.44
1.60
1.60
Estimated
Cost
($1986)
$4,077,821
$6,872,312
$11,211,984
$5,229,973
$3,677,478
Source:  EPA estimates.
                                                  5-27
-------
ak_oSm.wk1

TABLE 5-17
OPERATION AND MAINTENANCE COSTS FOR ALASKA PROJECTS
Project
                                 Operation and
                                    Maintenance
                                 Cost ($MH 1984)
          Number of
          Islands/
          Platforms
        Cost per
        Platform
      (SHM 1984)
            Cost per
            Platform
          (SHM 1986)
Beaufort platform

Navarin Basin

Norton Basin

Beaufort Gravel
S168.0

$132.0

 $72.0

$120.0
7

4

7
$24.0

$18.9

$18.0

$17.1
$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 5-18

                 CRUDE OIL PRICES, 1980 TO NOVEMBER 1987
Year
Domestic First
Purchase Prices*
1980 Average
1981 Average
1982 Average
1983 Average
1984 Average
1985 Average
1986 Average
1987 Average
1988 Average
1989 Average
1990 Average
21.59
31.77
28.52
26.19
25.88
24.09
12.51
15.40
12.58
15.86
20.03
     *Current dollars.
Source:  API, 1992.
                                    5-29
-------
wellhead.wkl
                       31-Mar-92
TABLE 5-19
WELLHEAD PRICES AND REGIONAL RELATIONSHIPS - 1985 DATA
Region
        1985
    Wellhead
Price (S/bbl)
                                       Ratio
           Estimated Oil
           Price ($/bbl)
           1986-2000
                                                                     Estimated Gas
                                                                     Price  ($/Mcf)
                                                                     1986-2000
National

Offshore Gulf
Offshore CA
AK North Slope
AtC other
      $24.09

      $27.33
      $20.08
      $16.98
      $22.46
1.00

1.13
0.83
o.ro
0.93
$21.00

$23.82
$17.50
$14.80
$19.58
$2.27

$2.57
$1.89
$1.60
$2.11
Source:  DOE, 1986.
                                               5-30
-------
oil^gas.ukl    •                       ,. , "•

TABLE 5-20
RELATIONSHIP OF DOMESTIC OIL AND GAS PRICES - 1982-1987
     Year
    Oil
  Price
<$/bbl)
    Gas
  Price
($/Hcf)
                                                           Ratio
     1982
     1983
     1984
     1985
     1986
Aug. 1987

Average Ratio
 $28.52
 $26.19
 S25.88
 S24.09
 $12.51
 $17.06
  $2.46
  $2.59
  $2.66
  $2.51
  $1.94
  $1.71
 8.6%
 9.9%
10.3%
10.4%
15.5%
10.0%

10.8%
Note:  Current dollars.
Source:  DOE, 1987; DOE, 1988.
                                             5-31
-------
       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
for tax rates, severance rates, depreciation, depletion, inflation, and other financial parameters in
this analysis.
       5.2.3 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 5-21  and 5-22 summarize the financial performance of each NSPS project,
including the internal rate of returri (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 hi 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.

       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.

       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
                                           5-32
-------





















g

w 8
U od
£!;
5s
ss
a:
 V
01 4>* 01
4-< CD ee
cee
S3 o
— • o
S5S
O. ^x
^J
0)
2
iSS
•»• O £B
S5"
3 01
"8
u
0.
o
•*•*•«•» Ul
(0 « O
L> O CD

C- 4)
O CL
CJ
ll
if
o.
co'o
4-* 1
o-i-
1- O
*4— CO
a

.1
rt
2
D.



§
i?
oe
CM CM CM «— CM CM CM



in •*»-«- M CM ?-
CM CM CM CM CM CM

•* O O O CM *O CM
>o2o3>tncoh-
in in M in o CM

iCSSSSFSg
pssasfei;



^orCSQcMOin
j- CO h- CO >O M3 M3






^- CM oo o CM in in
O M •» >O CM CO CM
O> «- CM »- O O> sj-
inotn «-i^ oo o
»- ^  N. O in
«-CMM

C J2 CMsfOCO
4^ M- «4- *»- H- »#- «4- H-
-g (g • co in
OMO
MM CM

M!
in«-f\i

e»m>*
«$«»



vpoeo
CXCOM
CM CM CM






M-J- O
OCMh-
** in r«"
-JTMCM
^sa
sss
o u u
•(— «f— ••-
sss
o. a. a.



u
H-
8
S



o
K

g
i

a
i



CM
CM
M
TT





s
o
e
3.
4-»
O
"c
J^
1



3
at
CO

























§
a
c.
a.
|-
O
1
o

*z
M
8
1?
Q.
O CO O N-
M CMMCM



««,,«
oo om-*

inls-oin
T- orvico
»— M in o
OPON-CM

POK»N»O
in KI *^ o
• • • •
m  w C
C3 (t CO 4J
> c.
• • CO O
m in zz



CD
•s
CO























Si
1
u
01
o
1
CM

n
01

___
S

a.
ui
01
u
s^
&
5-33
-------

tn .-i

2iS
     I o
     > iii
9  £3
in  xix
            ~"*~ E

            E a 3
            0) 4-> S)
            <•-> o of
            coe
         fc1
         o
         u
                 Ui
                 o
             a e> —
             -  OCO
               II
               2S
                      O v *— O* *-
                                   KI  o
                                   t-  CM
                             >£ ^C  14
                  sfCM*»N*3   «-  JT
                                        s
RorvieMO   co   «-
^±«-incvj   o   •*


           2   S
                       «»v» «*«»*»
                       •oroincoco   h.
                       •Jbootoco   m
  •^ rt ^j   fo
  «t* «— «•-   O^
  ^-  -   5
                                    vO



                                    O
                                        I
8

i

N
                        33333
                                     g  5
                                                   5-34
-------
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-equivalent): 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, than 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. This is consistent with the negative net present value
and low IRR seen for this project.

       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 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
                                           5-35
-------
the Federal Gulf of Mexico were obtained (Section Four).  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).  In other words, BAT models for existing structures were run with
existing oil and gas prices while NSPS models for projected structures were run with projected oil
prices.  The BAT runs provided baseline economic lifetimes and production profiles for existing
structures.

       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 5-23 and 5-24.

       Only projects in the Gulf and the Pacific are included in the analysis of BAT regulations.
Current production from Cook Inlet, Alaska is in the coastal subcategory, not the offshore
category.  The only offshore field currently in production in Alaska is the Endicott field on two
gravel islands in the Beaufort Sea.   The state permit requires produced water from these islands
to be injected. 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 BOB for the Gulf la to 21,698,858 BOB for the large Pacific 70 project.
Net present values range from $939,000  to $101,673,000.  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.)

       Note that for a Gulf Ib oil and gas project, the baseline net present value is larger for the
BAT project ($1,159 thousand) than for  the NSPS project ($654 thousand; compare Tables 5-21
and 5-23). This situation occurs only for the Gulf Ib project and indicates that the single-well
structure has not recovered its initial costs by the mid-point of its economic lifetime.  Because of
smaller net present value for NSPS Gulf Ib structures, however, the same absolute decrease in
                                           5-36
-------
e-i
a
0)
3

a
 o o
 wo
 oo
8
u

g
•»-



I1
   -
   0)
   a.
01

4-*

0 CKO,- ,-
                                             coo>o<-

                                  SK

             SrSSSje^Jni^

                           •«-  K?O^«
             §o J>     ru
             «-«-•* >O »-
                                              a J>
                                                      rj-eoeo
•W
|
4_
Q.


U
•g
09
—
O
H-H-<*-*»-M«*f-<4-M-
3SS333SS
o
o
'x
d)
X
*»-
o

"3
ta
•p-
03
a.





o
>C
a
a
a.
w-w
aa
a. a.









                                             UC9C9C9C9UIC9O


                                         §  8
                                         o  S
                                                                   g
                                                                   CO
                                         5-37
-------































CO
CJ
H- =C
c/) O
•>•« ^*
w 8
&£
^ >-
ig ^j
«§
i
"*5
j.
S{2
•* U.O
CVJ UJ
in z o
Ul — 10.
. i uj
CO Vi t~
? ScS
§
O «J
M JJ
ea o
« c.
>- a.
I
«
^
4J
g
V
CO
o *-»
flu o
4-»
S
u
I
4~* UJ
li.

s
u
gg
a.
c_ t-
o v



r*.
ll
O >
11

a o
4-1 1
o **•
h- 0
i-Js
2S



jj
£

O
O.



§

oc



N» O*O*OO^O iN>



** N» O iS- O IO CM
SoREQKSS S
«™ «"• *«* *Q K) IA «~
4^ 4^ W W J~ f>4 £1



>O N- «— tO IA »* 1A
OK1«-O CMCM Kl


Kigsaeg; a
S«f*?fe«JS S








eo«oo*oino *o
O <^ v OJ 00 CO P"
^oorooin.^1 o
S- N. co co ** in eg
*J" Kl K) O *j .CO CO *

«•• w~ "*^ *O CO



o

Q ^) CM *^ O
*™ •" ** *° tr~S** ^
*#- H- H- *l- H- «4- ••-
333333 OJ
t9 O CJ O O C3 flu
O
O
^»
5

*^. u
O •—
«J^ »r>
.H . 0
S £















•
.Q
1
^

a
S4J
U)
a.
«
09
8
1
CO

SQ
01
O w
(M
3
3
X
1
0) •
 0)
81

L. CA
a 01
01 <
> Q,
01 UJ

..s
V I-
4-1 3
o 5
5-38
-------
net present value (due to increased pollution control requirements) will show a proportionally
larger impact for the NSPS project than for the BAT version.
5.3 REFERENCES


API. 1987a. American Petroleum Institute. 1986 Joint Association Survey on Drilling Costs.
       Washington, DC. November.

API. 1987b. American Petroleum Institute. 1986 Survey on Oil and Gas Expenditures.
       Washington, DC. November.

DOE. 1987a. 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.

DOE. 1987b. U.S. Department of Energy. Energy Information Administration. Annual Energy
       Outlook 1986 With Projections to 2000. DOE/EIA-0383 (86). February.

DOE. 1988. U.S. Department of Energy. Energy Information Administration. Petroleum
       Marketing Monthly. November 1987. DOE/EIA-0380(87/11). February. Table 1.

DOE. 1989. U.S. Department of Energy. Energy Information Administration. Petroleum
       Marketing Monthly: March 1989. DOE/EIA-0380 (89/03). June.

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. Office of Technology Assessment. Oil and Gas Technologies for the Arctic and
       Deepwater. Washington. DC. May.
                                        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 U.S. Environmental Protection
Agency, Office of Water, Office of Science and Technology, Engineering and Analysis Division
and are discussed in more detail in the Development Document for this rule. There are five
subsections for the costs of compliance:

       n     Drilling fluids and drill cuttings (Section 6.1)                           .
       •     Produced water (Section 6.2)                             *
       •     Treatment/workover/completion fluids (Section 6.3)
       H     Produced sand (Section 6.4)
       «     Combined cost of selected regulatory options (Section 6.5)

The data and analysis were performed in terms of 1986 dollars.  The record low oil prices of.
1986 severely impacted the financial health of the oil and gas industry. By using 1986 financial  .
statements (e.g., balance sheets) for typical oil and gas companies in the analyses, the impacts of
incremental pollution control costs will not be underestimated. The economic models have all
parameter values set in terms of 1986 dollars and it is necessary to keep the incremental costs on
the same basis.  Where cost components have increased with time, costs were inflated to 1991
dollars using the Engineering News Report Construction Cost Index (ENR, 1992). For a
complete discussion of price level adjustments, see Sigler, 1992.
6,1    PRILLING FLUIDS AND DRILL CUTTINGS

       The incremental costs of increased pollution control are calculated using current permit
requirements as the baseline. Table 6-1 summarizes the current requirements.
                                          6-1
-------
TABLE 6-1

SUMMARY OF CURRENT REQUIREMENTS FOR DRILLING FLUIDS

Requi rement
Ho discharge of oil-based
fluids (BPT requirement)
Mandatory barging based
on distance from shore
Metals limitation
effluent
mercury {mg/kg)
cadmium Cmg/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
Ho**
Yes
30.000


No
Region
Pacific
Yes

No

Yes
barite
1
2



Yes
No**
Yes
30,000
ppm spp*

Yes

Alaska
Yes

No

Yes
barite
11
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 l>e discharged; toxicity limit must be met by remaining fluid.
Source;  FR,, 1985; FR, 1986; and FR, 1988.
                                                  6-2
-------
       In general, under the options considered for the rale, wells within a specified distance of
shore must meet a zero discharge requirement for drilling fluids and cuttings.  Wells beyond that
distance must meet (in addition to BPT and current permit requirements): metajs limitation of 1
mg/kg mercury and 3 mg/kg cadmium in the stock barite, a toxicity limitation (LC50 30,000 ppm
suspended particulate phase), a prohibition on the discharge  of diesel oil, and no free oil
discharge. Drill cuttings from wells beyond the zero discharge boundary must meet the same
requirements as drilling fluids.  The different options are determined by the distance from shore
for each region for meeting the zero discharge requirement.  Boundaries at 3, 4, and 8 miles are
considered for the Gulf of Mexico.  Boundaries at 3 and 4 miles are considered for the Pacific.
The exception is Alaska, which is excluded from the zero discharge requirement in all options,
but must meet limitations on metals, toxicity, diesel oil, and prohibition on free oil discharge.

       The annual average cost associated with each  option is a function of the annual average
number of wells drilled per year, percentage of wells  that incur the zero discharge requirement,
volume of waste generated per well, toxicity failure rates, other compliance failures, and other
assumptions.  The average  annual number of wells by region and the percentage that incur the
zero discharge requirement are given in Table 4-16.

       The total and per-well costs  for each region are summarized in Table 6-2. The fourth
option, with a zero discharge requirement within 4 miles of shore for the Gulf and Pacific,
corresponds to the preferred option considered in the March 1991 proposal.  The costs reflect
the varying percentages of the wells that must meet the zero discharge requirement, i.e., they are
weighted average  costs of the "within" (zero discharge) and "beyond" (metals, diesel oil, toxicity,
and free oil)  requirements. The costs for Alaska include the exclusion from the zero discharge
requirement.  Costs for the Pacific include the costs for emissions offsets in case projected wells
are drilled in air quality non-attainment areas (see FR, 1992). Major cost components such as
barite, boat transportation, and landfill prices have remained stable for several years. The costs
are approximately $199 thousand per well in the Gulf of Mexico and $187 thousand per well in
the Pacific for zero discharge for both 1986 and 1991 dollars.
                                            6-3
-------
TABLE 6-2

NSPS DRILLING  FLUIDS AND DRILL CUTTINGS
SUMMARY OF COSTS

THOUSANDS OF DOLLARS *
Option # Option Name
Option 1 3 Mile Gulf/CA



Option 2 8 Mile Culf/ 3 Hile CA



Option 3 Zero Discharge Gulf/ CA



Option 4 4 Hile Gulf/ CA
(1991 Preferred Option)


Average •
Annual #
Region of Wells
Gulf
Pacific
Alaska
Total
Gulf
Pacific
Alaska
Total
Gulf
Pacific
Alaska
Total
Gulf
Pacific
Alaska
Total
715
32
12
759
715
32
12
759
715
32
12
759
715
32
12
759
Costs
Drilling
Fluids
$12,322
$0
$0
$12,322
$22,822
$0
$0
$22,822
$102,815
$4,235
$0
$107,050
$13,980
$0
$0
$13,980
Drill Emmission
Cuttings Offsets
$6,463
$80
$73
$6,616
$10,300
$80
$73
$10,453
$39,537
$1,500
$73
$41,110
$7,068
$80
$73
$7,221
$0
$16
$0
$16
$0
$16
$0
$16
$0
$261
$0
$261
$0
$16
$0
$16
Total Per-Uell
Costs Costs
$18,785
$96
$73
$18,954
$33,122
$96
$73
$33,291
$142,352
$5,996
$73
$148,421
$21,048
$96
$73
$21,217
$26
$3
$6

$46
$3
$6

$199
$187
$6

$29
$3
$6

Notes:  (*) Costs are presented in 1986 dollars, however,  since the price level  for most of the cost
            components has remained flat, these costs also represent 1991  dollar values.

            Alaska is excluded from the zero discharge limitation under  all options, but must meet
            limitations on free oil, diesel oil, toxicity, and metals contents  in barite.
Source:     Engineering & Analysis Division.

HSCSSUH.W3
26-Oct-92
                                                   6-4
-------
 6.2    PRODUCED WATER

        6.2.1  BAT Produced Water

        6.2.1.1 Structures Incurring Costs

        The cost for BAT produced water options depends on the number of structures expected
 to incur costs. Only existing projects in production in the Gulf of Mexico and the Pacific (i.e.,
 offshore California) are expected to bear incremental costs of additional pollution control under
 BAT. The only offshore field presently in production in Alaska is the Endicott field in the
 Beaufort Sea.  The two gravel islands in the Endicott field must already inject produced water to
 meet state requirements; thus, they will not incur any incremental costs associated with these
 effluent guidelines.

        The existing structures in the Gulf of Mexico and the Pacific include oil-with-gas and gas-
 only projects. The Gulf of Mexico also has a small number of oil-only projects.  Section Four
 discusses the development of the BAT platform profile, and Tables 4-7 and 4-8 summarize the
 BAT projects by region, size, type of production, and location.
       6.2.1.2 Onshore Versus Offshore Treatment and Disposal

       The cost for a given technology to reduce pollution will depend on whether treatment
and disposal of produced water takes place at the platform or at a centralized onshore facility.
Roughly 37 percent of produced water in the Gulf of Mexico is transported to shore for
treatment and disposal (DOI, 1991).  This  occurs because it is often less expensive to treat
production wastes at a centralized location. This analysis assumes that the 37 percent of BAT
structures that are currently piping their produced water to shore will continue to do so. The
costs will therefore be incurred at the centralized treatment facility rather than at the platform.
For each technology, per-project costs were developed for both onshore disposal and disposal at
the platform. When the costs were aggregated over all BAT structures, it was assumed that 37
                                           6-5
-------
percent of every model project in the Gulf would incur the onshore cost, while 63 percent would
incur the offshore cost.

       For the Pacific, the U.S. Department of Interior (DOI) commented that:

              Most Pacific OCS facilities either treat and dispose of their produced water at the
              platform or they ship an oil/water mixture onshore where it is treated.  The
              treated water is then piped back offshore for disposal or reinjection. (DOI, 1991)

No estimates of the percentage of platforms that use onshore treatment or the volume of
produced water that is treated onshore were supplied by DOI. On the basis of these comments,
disposal costs for the Pacific are calculated with the assumption that 100 percent of the
structures dispose of their water at the platform.  Should it be more cost-effective to treat the
water on land but to dispose of it at the platform, the costs—as calculated—will be conservatively
high.
       6.2.1.3 Technologies Considered

       The Development Document examines three basic technologies for the increased
pollution control of produced water, including:

       •      Improved gas flotation (IGF) and discharge
       •      Granular filtration and discharge
       •      Reinjection.

The reader is directed to Section XII.5.1.1 in the Development Document for the basis of the
following discussion on current pollution control priorities. The costs for improved gas flotation
assume that many of the existing structures are already practicing IGF before discharging. It is
assumed, however, that structures that already have IGF equipment will have to increase their
operating and maintenance costs (O&M) to run the equipment more efficiently in order to meet
the new requirements. Thus, a portion of the BAT structures would have to incur both capital

                                           6-6
-------
and O&M costs for this technology, while the remainder would bear only incremental O&M
costs.

       The percentages of facilities expected to incur additional costs under IGF options are as
follows:
       •      Oil-only facilities - 40 percent
       •      Oil and gas facilities - 60 percent
       •      Gas-only facilities - 80 percent.

It is also assumed that 100 percent of the onshore disposal facilities would need new IGF
equipment rather than an increased O&M cost.  For options considering only flotation, the costs
include two years of monitoring for radium in produced water. Radium monitoring is not a
requirement under the option. The costs, however, are included in the economic impact analysis
to evaluate the effects should EPA seek this information through monitoring requirements
imposed in general permits.  For options involving a combination of zero discharge and flotation
requirements, no monitoring costs for radium are included. The costs for reinjection and
filtration were based upon granular filtration technology.  For a complete discussion of the
costing assumptions, see Section XII.5 of the Development Document.
       6.2.1.4 Options Considered

       These technologies have been combined into five alternative regulatory options based on
the location of the platform, technology, and exemptions (Table 6-3). The Flotation All option
includes the cost of two years of monitoring produced water for radium. Structures in the Pacific
must comply with flotation requirements. Single well structures with their own production
equipment would be excluded from the zero  discharge requirement.  The Filter 4 miles option is
comparable to the preferred option in the March 1991 proposal.
                                           6-7
-------
                                      TABLE 6-3

                                 PRODUCED WATER
                             BAT REGULATORY OPTIONS
Regulatory Option
Short Form of Title
BPT - All Structures

Improved Gas Flotation - All Structures

Filter (Granular) and Discharge
- All Structures Within 4 Miles
BPT - All Structures
Beyond 4 Miles

Gulf of Mexico
Zero Discharge Within 3 Miles
(Gulf Ib Structures = Flotation)
Flotation Beyond 3 Miles
California: Flotation - All Structures

Gulf of Mexico
Zero Discharge
(Gulf Ib Structures = Flotation)
California: Flotation - All Structures
BPT All

Flotation All

Filter 4 Miles
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
                                          6-8
-------
       6.2.1.5 Calculation of Costs

       The model-specific capital and O&M costs (explained further in the Development
Document) are entered into the BAT economic models to calculate the annualized cost of the
regulation (see Section Four for a discussion of the number and types of BAT facilities). 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 6-4  through 6-9 list the capital, O&M,  and annualized cost for each project and
technology. Ten sets of costs are given for the Gulf of Mexico, i.e., three technologies, two
locations (onshore and offshore), whether an  upgrade or new equipment is needed, and whether
costs for radium monitoring are included. Note that the costs for onshore disposal are lower
than the costs for handling the effluent at the platform.  Costs for Pacific projects have an
additional component to address potential costs for air emission offsets. This incremental cost is
reflected in the O&M cost component.
       The total costs of the regulatory options are obtained by multiplying the number of each
model project by the per-project cost of each disposal option (see Tables 4-7 and 4-8 for the
number and type of BAT facilities). Figure 6-1 illustrates the logic table for determining the
costs for IGF for the Gulf of Mexico.  These calculations address whether the treatment occurs
onshore or at the platform, the type of project, and whether it needs new equipment or an
upgrade in O&M.  Table 6-10 lists the total capital, O&M, and annualized cost for each of the
regulatory options under consideration.  The annualized costs range from $39 million for the
Filter 4 miles option to $96 million for the Flotation All option to $654 million for the Zero
Discharge Gulf option (1986 dollars; the costs in 1991 dollars are $43 million, $108 million, and
$737 million, respectively.) The inclusion of radium monitoring costs raises the cost for the
Flotation All option by $1.2 million (1986 dollars; about $1.35 million in 1991 dollars), or about
1.3 percent.

       The annualized costs in Table 6-10 represent Year 1 of the regulation when  all structures
will be affected. As existing projects come to the end of their economic lives, the number of
structures incurring BAT costs will decline. The highest cost for BAT pollution control options
will be in the first year of the regulation.

                                            6-9
-------
    .8
    ctl
    w

    i
3  5
    C)
    8
    o
                                                 6-10
-------
 TABLE 6-4

 BAT PER-PROJECT INCREMENTAL  POLLUTION CONTROL COSTS
 OIL AND  GAS PLATFORMS
 GULF OF  MEXICO
Pollution Control Costs <$000, $1986) Pollution Control Costs ($000, $1991)
Project
Gulf 1a









Gulf 1b









Gulf 4









Gulf 6









Gulf 12









Scenario
Zero Discharge
Filtration
IGF 65-New
IGF 35 -Upgrade
IGF 65-New W/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New U/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New U/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New U/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Capital
$549
$175
$86
$0
$86
$0
$83
$47
$23
$23
$2,020
$573
$345
$0
$345
$0
$319
$152
$91
$91
$3,552
$699
$345
$0
$345
$0
$490
$188
$91
$91
$3,589
$699
$377
$0
$377
$0
$501
$188
$98
$98
$2,309
$699
$443
$0
$443
$0
$520
$188
$112
$112
O&M
$48
$25
$8
$8
$8
$8
$37
$12
$2
$2
$169
$80
$32
$32
$32
$32
$146
$40
$9
$9
$260
$99
$32
$32
$32
$32
$166
$48
$9
$9
$264
$101
$32
$32
$32
$32
$173
$49
$9
$9
$270
$103
$34
$34
$34
$34
$183
$52
$10
$10
Annual i zed
$137
$51
$21
$7
$21
$7
$45
$17
$6
$6
$540
$159
$78
$27
$79
$27
$181
$57
$21
$22
$790
$188
• $75
$27
$75
$28
$214
$67
$20
$21
$757
$183
$76
$28
$77
$28
$218
$67
$21
$21
$572
$192
$91
$29
$91
$30
$233
$71
$24
$24
Capital
$618
$197
$97
$0
$97
$0
$94
$53
$25
$25
$2,274
$645
$388
$0
$388
$0
$359
$171
$102
$102
$3,999
$787
$388
$0
$388
$0
$552
$211
$102
$102
$4,041
$787
$424
$0
$424
$0
$564
$211
$110
$110
$2,600
$787
$498
$0
$498
$0
$585
$211
$127
$127
O&M
$54
$28
$9
$9
$9
$9
$42
$13
$3
$3
$190
$90
$36
$36
$36
$36
$165
$46
$10
$10
$292
$111
$36
$36
$36
$36
$187
$54
$10
$10
$297
$113
$36
$36
$36
$36
$195
•$56
$10
$10
$304
$116
$38
$38
$38
$38
$206
$59
$11
$11
Annual! zed
$154
$58
$23
$7
$24
$8
$51
$20
.$6
$7
$608
$179
$88
$30
$88
$31
$204
$64
$24
$24
- $889
$211
$84
$31
$85
$31
$241
$75
$23
$23
$852
$206
$86
$31
$86
$31
$245
$76
$23
$24
$644
$216
$102
$33
$102
$34
$263
$80
$27
$27
Note:  The two years of radium monitoring costs are reflected only in the annualized costs.
                                                   6-11
Pen-Project BAT PU Costs   costsum.wk3
23-Oct-92
-------
TABLE 6-5
BAT PER-PROJECT INCREMENTAL POLLUTION CONTROL COSTS
OIL AHD GAS PLATFORMS
GULF OF MEXICO
                                      Pollution Control Costs ($000,  $1986)
Project    Scenario                        Capital         O&H  Annualized
Pollution Control Costs ($000,  $1991)
     Capital         O&H  Annualized
Gulf 24


Gulf 40



Gulf 58



Zero Discharge
Filtration
IGF 65 -New
IGF 35-Upgrade
IGF 65-New "/Monitoring
IGF 35-Upgrade U/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Honitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgradft
IGF 65-New U/Honitoring
IGF 35-Upgradu W/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrads
IGF 65-New W/Honitoring
IGF 35-Upgrade U/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore • IGF
Onshore - IGF U/Monitoring
$3,479
$821
$497
$0
$497
$0
$812
$222
$124
$124
$4,737
$965
$582
$0
$582
$0
$1,114
$259
$137
$137
$6,713
$1,119
$646
$0
$646
$0
$1,572
$295
$144
$144
$360
$112
$41
$41
$41
" $41
$228
$60
$12
$12
$499
$139
$45
$45
$45
$45
$295
$76
$13
$13
$690
$164
$48
$48
$48
$48
$358
$93
$14
$14
$790
$204
$100
$36
$100
$36
$309
$81
$26
$27
$1,049
$241
$111
$39
$111
$39
$401
$98
$28
$28
$1,430
$281
$121
$42
$122
$42
, $508
$118
$30
$30
$3,916
$924
$559
$0
$559
$0
$914
$250
$140
$140
$5,332
$1,087
S656
$0
$656
$0
$1,254
$292
$154
$1.54
$7,557
$1,260
$727
$0
$727
$0
$1,770
$332
$163
$163
$405
$126
$46
$46
$46
$46
$257
$67
$13
$13
$562
$157
$50
$50
$50
$50
$332
$86
$14
$14
$776
$185
$54
$54
$54
$54
$404
$105
$15
$15
$890
$230
$113
$40
$113
$41
$348
$91
$30
$30
$1,181
$271
$125
$44
$125
$44
$452
$111
$32
$32
$1 ,609
$317
$137
$47
$137
$48
$571
$133
$34
$34
Note:  The two years  of  radium monitoring costs are reflected only in the annualized costs.
                                                      6-12
 Per-Project BAT PU Costs   costsum.wk3
                                             23-Oct-92
-------
 TABLE 6-6

 BAT  PER-PROJECT  INCREMENTAL POLLUTION CONTROL COSTS
 GULF OF  MEXICO   GAS-ONLY PLATFORMS
Pollution Control Costs <$000, S19S6) Pollution Control Costs ($000, $1991)
Project
Gulf 1a









Gulf 1b









Gulf 4









Gulf 6









Gulf 12









Gulf 24









Scenario
Zero Discharge
Filtration
IGF 65 -New
IGF 35 -Upgrade
IGF 65-New W/Moni toning
IGF 35-Upgrade W/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Hpnitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Monitoring
IGF 35-Upgrade W/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Monitoring
IGF 35-Upgrade W/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-Neu U/Monitoring
IGF 35-Upgrade W/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-NeM W/Monitoring
IGF 35-Upgrade W/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Monitoring
IGF 35-Upgrade W/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Monitoring
Capital
$491
$132
$86
$0
$86
$0
$79
$35
$23
$23
$1,945
$497
$345
$0
$345
$0
$316
$134
$91
$91
$1,965
$526
$345
$0
$345
SO
$317
$138
$91
$91
$2,003
$559
$345
$0
$345
$0
$318
$148
$91
$91
$1,405
$623
$345
$0
$345
$0
$322
$166
$91
$91
$2,178
$699
$345
$0
$345
$0
$483
$188
$91
$91
OSM
$31
$11
$8
$8
$8
$8
$21
$8
$2
$2
$110
$29
$32
$32
$32
$32
$60
$27
$9
$9
$122
$40
$32
$32
$32
$32
$79
$29
$9
$9
$129
$45
$32
$32
$32
$32
$89
$31
$9
$9
$150
$64
$32
$32
$32
$32
$122
$36
$9
$9
$235
$78
$32
$32
$32
$32
$162
$40
$9
$9
Annuali zed
$113
$30
$21
$7
$21
$7
$30
$12
$6
$6
$436
$99
$78
$27
$79
$27
$101
$42
$21
$22
$395
$107
$75
$27
$75
$28
$112
$44
$20
$21
$387
$116
$75
$27
$75
$28
$121
$47
$20
$21
$323
$141
$75
$27
$75
$28
$150
$54
$20
$21
$487
$159
$72
$28
$73
$28
$203
$59
$20
$20
Capital
$553
$148
$97
$0
$97
$0
$89
$39
$25
$25
$2,190
$560
$388
$0
$388
$0
$356
$150
$102
$102
$2,212
$592
$388
$0
$388
$0
$357
$156
$102
$102
$2,255
$629
$388
$0
$388
$0
$358
$166
$102
$102
$1,581
$702
$388
$0
$388
$0
$362
$187
$102
$102
$2,452
$787
$388
$0
$388
$0
$544
$211
$102
$102
08M
$35
$12
$9
$9
$9
$9
$24
$8
$3
$3
$124
$33
$36
$36
$36
$36
$68
$30
$10
$10
$138
$45
$36
$36
$36
$36
$89
$33
$10
$10
$145
$51
$36
$36
$36
$36
$100
$35
$10
• $10
$169
$72
$36
$36
$36
$36
$137
$40
$10
$10
$264
$88
$36
$36
$36
$36
$182
$45
$10
$10
Annuali zed
$127
$34
$23
$7
$24
$8
$34
$13
$6
$7
$491
$111
$88
$30
$88
$31
$114
$48
$24
$24
$445
$120
• $84
$31
$85
$31
$126
$50
$23
$23
$436
$131
. $84
$31
$85
$31
$136
$53
$23
$23
$364
$159
$84
$31
$85
$31
$168
$61
$23
$23
$548
$179
$81
$31
$82
$31
$229
$67
$22
$23
Note:  The two years of radium monitoring costs are reflected only in the annualized costs.
                                                     6-13
Per-Project BAT PW Costs   costsum.wkS
23-Oct-92
-------
 TABLE 6-7

 BAT PER-PROJECT INCREMENTAL POLLUTION CONTROL COSTS
 OIL-ONLY PLATFORMS
 GULF OF MEXICO
Pollution Control Costs ($000, $1986) Pollution Control Costs ($000, $1991)
Project
Gulf 1a









Gulf 1b









Gulf 4









Gulf 6









Gulf 12









Scenario
Zero Dischiirge
Filtration
IGF 65-Ncw
IGF 35-Upgrade
IGF 65-Ncw W/Honitoring
IGF 35-Upgrade W/Honitoring
Onshore - 2'.ero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Honitoring
IGF 35-Upgrade W/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Honitoring
IGF 35-Upgrade W/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Honitoring
IGF 35-Upgrade W/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Honitoring
IGF 35-Upgrade W/Honitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Capital
$549
$175
$86
$0
$86
$0
$83
$47
$23
$23
$2,018
$571
$345
$0
$345
$0
$319
$151
$91
$91
$3,551
$699
$345
$0
$345
$0
$490
$188
$91
$91
$3,588
$699
$375
$0
$375
$0
$500
$188
$97
$97
$2,306
$699
$440
$0
$440
$0
$519
$188
$112
$112
OSH
$47
$24
$8
$8
$8
$8
$37
$12
$2
$2
$169
$80
$32
$32
$32
$32
$146
$40
$9
$9
$259
$99
$32
$32
$32
$32
$166
$48
$9
$9
$263
$100
$32
$32
$32
$32
$172
$49
$9
$9
$269
$103
$34
$34
$34
$34
$182
$52
$10
$10
Annualized
$137
$51
$22
$7
$23
$8
$45
$18
$6
$7
$598
$167
$82
$27
$83
$28
$181
$58
$21
$22
$790
$188
$78
$27
$79
$28
$218
$68
$21
$22
$756
$183
$79
$27
$80
$28
$221
$68
$21
$22
$598
$191
$94
$29
$95
$30
$232
$72
$25
$26
Capital
$618
$197
$97
$0
$97
$0
$94
$53
$25
$25
$2,272
$643
$388
$0
$388
$0
$359
$170
$102
$102
$3,998
$787
$388
$0
$388
$0
$552
$211
$102
$102
$4,039
$787
$423
$0
$423
$0
$563
$211
$110
$110
$2,596
$787
$495
$0
$495
$0
$584
$211
$126
$126
O&M
$53
$28
$9
$9
$9
$9
$42
$13
$3
$3
$190
$90
$36
$36
$36
$36
$165
$45
$10
$10
$292
$111
$36
$36
$36
$36
$186
$54
$10
$10
$296
$113
$36
$36
$36
$36
$194
$55
$10
$10
$303
$116
$38
$38
$38
$38
$205
$58
$11
$11
Annualized
$154
$58
$25
$7
$26
$8
$51
, $20
$7
$8
$673
$188
$92
$30
$94
$31
$204
$66
$24
$25
$889
$211
$88
$30
$89
$31
$245
$77
$24
$25
$851
$206
$89
$31
$90
$32
$249
$77
$24
$25
$673
$215
$106
$32
$107
$33
$261
$81
$28
$29
Note:  The two years of radium monitoring costs are reflected only  in the annualized costs.
                                                     6-14
Per-Project BAT PW Costs   costsum.wkS
23-Oct-92
-------
TABLE 6-8
BAT PER-PROJECT INCREMENTAL POLLUTION CONTROL COSTS
OIL-ONLY PLATFORMS
GULF OF MEXICO
Project    Scenario
Pollution Control Costs ($000,  $1986)
     Capital         OSM  Annualized
Pollution Control Costs <$000, $1991)
     Capital         O&M  Annualized
Gulf 24








Gulf 40








Gulf 58








Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New U/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
Zero Discharge
Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New U/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore - Filtration
Onshore - IGF
Onshore - IGF W/Honitoring
Zero Discharge
Filtration
IGF 65-Neu
IGF 35-Upgrade
IGF 65-New U/Monitoring
IGF 35-Upgrade U/Monitoring
Onshore - Zero Discharge
Onshore -. Filtration
Onshore - IGF
Onshore - IGF U/Monitoring
$3,464
$817
$496
$0
$496
$0
$808
$221
$124
$124
$4,726
$963
$581
$0
$581
$0
$1,111
$258
$137
$137
$6,699
$1,116
$644
$0
$644
$0
*1,569
$294
$144
$144
$357
$111
$41
$41
$41
$41
$226
$59
$12
$12
$499
$139
$45
$45
$45
$45
$295
$76
$13
$13
$686
$162
$48
$48
$48
$48
$356
$92
$14
$14
$786
$208
$104
$35
$104
$36
$306
$82
$27
$28
$1,048
$246
$114
$39
$115
$40
$401
$100
$29
$30
$1,466
$280
- $121
$42
$122
$43
$513
$137
$30
$30
$3,900
$920
$558
$0
$558
$0
$910
$249
$139
$139
$5,320
$1,084
$654
$0
$654
$0
$1,251
$291
$154
$154
$7,542
$1,256
$725
$0
$725
$0
$1,766
$331
$162
$162
$402
$125
$46
$46
$46
$46
$255
$67
$13
$13
$562
$157
$50
$50
$50
$50
$332
$86
$14
$14
$772
$183
$54
$54
$54
$54
$401
$104
$15
$15
$885
$235
$117
$40
$118
$41
$345
$92
$31
$31
$1,179
$277
$129
$44
$129
$45
$451
$112
$32
$33
$1,650
$315
$136
$47
$137
$48
$578
$132
$33
$34
Note:  The two years of  radium monitoring costs are reflected only in the annualized costs.
                                                      6-15
 Per-Project BAT PU Costs   costsum.wk3
       23-Oct-92
-------
 TABLE 6-9

 BAT PER-PROJECT INCREHENTAL  POLLUTION CONTROL COSTS
 OIL AND GAS AND GAS-ONLY PLATFORMS
 PACIFIC
Pollution Control Costs ($000, $1986) Pollution Control Costs ($000, $1991)
Project Scenario
Pacific 16 Zero Discharge
(Oil & Gas)G-FHtraticn
IGF 65-New
IGF 35-Upgrade
IGF 65-New W/Honitoring
IGF 35-Upgrade U/Honitoring
Pacific 40 Baseline
(Oil & Gas)Zero Discharge
G-Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-Neu W/Honitoring
IGF 35-Upgrade W/Honitoring
Pacific 70 Zero Discharge
(Shallow) G-Filtration
(Oil & GasJIGF 65-New
IGF 35-Upgrade
IGF 65-New W/Honitoring
IGF 35-Upgrade U/Honitoring
Pacific 70 Zero Discharge
(Deep) G-Filtration
(Oil & Gas)IGF 65-New
IGF 35-Upgrade
IGF 65-New U/Honitoring
IGF 35-Upgrade U/Honitoring
Pacific 16 Zero Discharge
(Gas-Only) G-Filtration
IGF 65-New
IGF 35-Upgrade
IGF 65-New M/Honitoring
IGF 35-Upgrade W/Honitoring
Capital
$6,201
$1,439
$853
$0
$853
$0
$0
$12,034
$1,877
$1,054
$0
$1,054
$0
$28,515
$8,434
$1,259
so
$1,259
$0
$29,732
$9,651
$1,259
$0
$1,259
$0
$3,346
$1,119
$552
$0
$552
$0
O&H
$413
$123
$45
$45
$45
$45
$0
$838
$166
$53
$53
$53
$53
$1,437
$220
$59
$59
$59
$59
$1,437
$220
$59
$59
$59
$59
$241
$82
$34
$34
$34
$34
Annualized
$1,755
$428
$233
$35
$233
$35
$0
$3,081
$508
$253
$42
$254
$43
$6,860
$1,681
$273
$49
$273
$49
$7,104
$1,897
$273
$49
$274
$50
$794
$266
$126
$28
$126
$28
Capital
$6,980
$1,620
$961
$0
$961
$0
$0
$13,548
$2,113
$1,186
$0
$1,186
$0
$32,102
$9,495
$1,418
$0
$1,418
$0
$33,472
$10,865
$1,418
$0
$1,418
$0
$3,767
$1,259
$621
$0
$621
$0
O&M
$465
$138
$51
$51
$51
$51
$0
$944
$187
" $59
$59
$59
$59
$1,617
$248
$67
$67
$67
$67
$1,617
$248
$67
$67
$67
. *67
$272
$92
$38
$38
$38
$38
Annualized
$1,976
$482
$262
$39
$263
$40
$0
$3,468
$572
$285
$47
$286
$48
$7,723
$1,892
$307
$55
$307
$55
$7,998
$2,136
$307
$55
$308
$56
$893
$300
$142
$31
$142
$32
Note:  The two years of radium monitoring costs are reflected only in the annualized costs.
                                                    6-16
Per-Project BAT PW Costs   costsum.wkS      26-Oct-92
-------
   "
   «s
?  fe»
   si
          s

g
I
o-]
                        o*-o
                        PJCOO
                        rjT-O

                                  *  8KB  8ft »
                    U—'  «f- O—•  <•- O—•  N- O—  4-u
                    >»-a  «4H*ei  _«*^a  ^i^a  «f*«»
                    »*- 4-»  3 H- 4J  3*^4^   3 <*- -M  3 H-
                    »-O  CD*»-O  C9*^O  C9*^O  C9**-
                    0°  "d"  "o"  "0°  ™0
                          g
                         a o
                         •K c
                         o —•
                               3.2
                    Ml-


                    23
                    O %^
                    N
                                      Si

                                      I"
                                   g
                                  I

                                 .1
                                 > fl
                         03    5S


                         fcS    =^
                                         «l«
                                         H- *J *J      I. w



                                         si?      Is

                                         S1-0-      0i

                                         •go*      €:
                                         M «—       »l
                                         •^ L. CJ   •   ^>u




                                         li^  •£  fi

                                         0  •g  o   e <
                                          «< M  —   W •

                                          " X   —   _0

                                         £ —"o  c   2
                                       l_ H-*»»  4^

                                       ^?e  2.
                                       ^ W I*O • **"
                                         giu^g   i*
                                         •*-  ** *•    u »
                                         U O U O J=    *"»
                                         s ** .^« S   ** ?


                                         O E &E X«  © "O
                                         fSt-^'o.  Q.O
                                                    •n t,  -
                                                    C t-— • *< +•
                                                    *•« «« u
                                                    a u—<*3—,
                                                    o £ o _ o
                                                              •si
                                                        u xi-  "V <-
                                                       i O-—• 5.  O 3
                                                         C    I- *•
                                                      COJ3 O^U  CLU

                                                      »^ *»t-
g  g   g  -5


O  O   O  I— «>
                                          6-17
-------
       6.2.2  NSPS Produced Water

       The pollution control options being considered for future or NSPS structures consist of
the same three technologies considered for the BAT analysis (see Table 6-11).  There are no
exemptions for Gulf Ib structures and no monitoring requirements for radium under NSPS. The
Filter 4 mile  is comparable to the preferred option in the March 1991 proposal. However,  since
new sources have the option of incorporating new pollution control requirements into the design
of the project, the NSPS analysis assumes that new projects will treat and dispose of their
produced water at the platform.1

       As with the BAT analysis, the per-project capital and O&M costs for each technology are
input into the NSPS economic models to get the annualized costs. Tables ,6-12 through 6-14
display the per-project capital, annual O&M, and the annualized costs for the three technologies
(reinjection, filtration, and improved gas flotation). Section XH.5.1.3 of the Development
Document provides details on current practices and is a basis for the following costing
assumptions for NSPS produced water. It is assumed that 80 percent of new structures would
have been constructed with a gas flotation system regardless of this rulemaking. For these
projects, it is assumed that incremental capital costs will be incurred to upgrade the flotation
system. The  remaining 20 percent of NSPS structures would not have planned an any flotation
system. These structures incur both incremental capital costs and O&M costs for the installation
and operation of an IGF system.

       The number of new projects to go into operation during the next 15 years is summarized
in Tables 4-26 and 4-27.2  The cost for each regulatory option is calculated  as the annualized
cost in the fifteenth or last year of the projections. The annualized costs, then, represent the
    1The additional costs of constructing a pipeline to shore for each new project eliminates the
economic incentive for treating the effluent onshore.  Should cooperative efforts among oil
companies lead to more cost effective pipelines, we presume that the companies would choose to
use onshore disposal for their produced water.  In this situation our costing analysis would be
conservatively high.
    2A 15-year projection period was used because, at that point, the number of structures going into
production is assumed to be equal to or less than the number of structures going out of operation.
                                          6-18
-------
                                      TABLE 6-11

                                 PRODUCED WATER
                             NSPS REGULATORY OPTIONS
Regulatory Option
Short Form of Title
BPT - All Structures

Improved Gas Flotation
- All Structures

Filter (Granular) and Discharge
All Structures Within 4 Miles
BPT - All Structures Beyond 4 Miles

Gulf of Mexico and Alaska
Zero Discharge Within 3 Miles
Flotation Beyond 3 Miles
California: Flotation - All Structures

Gulf of Mexico and Alaska
Zero Discharge - All Structures
California: Flotation - All Structures
BPT All

Flotation All


Filter 4 Miles



Zero 3 Miles Gulf and Alaska
Zero Dischage Gulf and Alaska
                                            6-19
-------
 TABLE 6-12

 NSPS PER-PROJECT INCREMENTAL POLLUTION  CONTROL COSTS
 OIL AHD GAS PROJECTS
Pollution Control Costs ($000, $1986) Pollution Control Costs ($000, $1991)
Project
Gulf 1b



Gulf 4



Gulf 6



Gulf 12



Gulf 24



Gulf 40



Gulf 58



Pacific 16



Pacific 40



Pacific 70



Cook Inlet

,

Scenario
Zero Discharge
Filtration
IGF 20 (Hew)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (Hew)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Fi Itration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (Ni!U)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (Nuu)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Capital
. 1,950
533
317
48
3,471
657
317
48
3,499
657
343
52
3,551
657
398
60
5,434
784
436
65
7,348
910
481
72
10,642
1,037
506
76
6,781
1,374
735
110
13,917
1,743
833
125
24,995
2,284
1,018
153
18,974
2,442
1,116
167
OSM
162
76
32
0
252
95
32
0
256
97
32
0
262
100
35
0
354
110
41
0
497
137
45
0
686
161
48
0
428
122
46
0
855
167
53
0
1,462
221
61
0
975
199
51
0
Annual i zed
$344
$120
$59
$4
$556
$147
$58
$4
$556
$148
$60
$5
$549
$143
$65
$6
$778
$161
$73
$6
$1,051
$193
$79
$6
$1,485
$223
$83
$6
$1,200
$270
$130
$14
$2,362
$341
$143-
$15
$3,953
$429
$162
$17
$2,359
$366
$133
$14
Capital
2,195
600
357
53
3,908
740
357
53
3,939
740
387
58
3,998
740
448
67
6,118
883
491
74
8,272
1,025
541
81
11,981
1,167
570
85
7,634
1,546
827
124
15,667
1,962
938
141
28,139
2,571
1,146
172
21,361
2,749
1,257
189
OSH
183
86
36
0
284
107
36
0
288
109
36
0
295
112
39
0
398
124
46
0
559
155
51
0
773
181
54
0
481
138
52
0
962
188
60
0
1,646
248
68
0
1,098
224
57
0
Annuali zed
* $387
$135
$66
"$5
$626
$165
$65
$5
$626
$166
$68
$5
$618
$160
$74
$6
$876
$181
$82
$7
$1,183
$218
$89
$7
$1,671
$251
$94
$7
$1,351
$304
$146
$16
$2,659
$384
$161
$17
$4,450
$483
$182
$19
$2,656
$412
$150
$15
                                                    6-20
nsps\costsira.wk3     23-Oct-92
-------
TABLE 6-13

NSPS PER-PROJECT INCREMENTAL POLLUTION CONTROL COSTS
GAS-ONLY PLATFORMS
Pollution Control Costs ($000, $1986) Pollution Control Costs ($000, $1991)
Project
Gulf 1b



Gulf it



Gulf 6



Gulf 12



Gulf 24



Pacific 16



Cook Inlet'



Scenario
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Capital
1,873
467
317
48
1,893
484
317
48
1,931
517
317
48
2,006
581
317
48
3,451
657
317
48
3,901
1,052
507
76
4,280
1,314
666
100
O&M
109
29
32
0
119
37
32
0
125
43
32
0
141
57
32
0
227
73
32
0
233
77
34
0
202
52
32
0
Annualized
$284
$70
$59
$4
$283
$79
$58
$4
$289
$86
$58
$4
$302
$101
$55
$4
$464
$111
$51
$4
$606
$174
$82
$8
$520
$151
$81
$8
Capital
2,108
526
357
53
2,131
545
357
53
2,174
582
357
53
2,259
654
357
53
3,885
740
357
53
4,392
1,184
571
86
4,818
1,480
750
113
O&M
123
32
36
0
134
42
36
0
141
49
36
0
159
65
36
0
255
83
36
0
262
86
38
0
228
58
36
0
Annualized
$319
$79
$66
$5
$318
$88
$65
$5
$326
$97
$65
$5
$340
$114
$62
$5
.$522
$125
$57
$5
$683
$196
$92
$9
$585
$170
$91
$9
                                                   6-21
nsps\costsum.wk3     23-Oct-92
-------
TABLE 6-14
NSPS PER-PROJECT INCREMENTAL POLLUTION CONTROL COSTS
OIL-ONLY PROJECTS
PROJECT    SCENARIO
Pollution Control Costs ($000,  $1986}
     Capital         OSM  Annualized
                                                                     Pollution Control Costs ($000, $1991)
                                                                         Capital         O&H  Annualized
Beaufort
Gravel
Island

Beaufort
Platform


Navarin



Norton


Zero Discharge
Filtration
IGF 20 (Hew)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (Hew)
IGF 80 (Upgrade)
Zero Discharge
Filtration
IGF 20 (New)
IGF 80 (Upgrade)
49,016
6,115
2.493
374
47,323
6,060
2,480
372
49,016
6,115
2,493
374
33,598
4,955
2,217
333
1,889
310
62
0
1,800
300
61
0
1,889
310
62
0
1,317
231
54
0
$5,285
$714
$241
$29
$5,136
$708
$242
$29
$5,285
$714
$241
$29
$3,698
$573
$217
$26
55,181
6,884
2,807
421
53,275
6.822
2,792
419
55,181
6,884
2,807
421
37,824
5,579
2,496
374
2,127
349
70
0
2,027
337
69
0
2,127
349
70
0
1,483
260
61
0
$5,950
$804
$272
$33
$5,782
$797
$272
$33
$5,950
$804
$272
$33
$4,163
$646
$245
$30
                                                  6-22
nsps\costsura.wk3     23-Oct-92
-------
total for all projects in the time period.  For example, the cost for the first year is calculated as
follows:

       •      Multiply the annualized costs for a project by the number of such projects going
              into operation that year
       •      Sum the products for 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.

       Table 6-15 presents the total capital costs, total annual O&M, peak annualized cost, and
average single year annualized cost for new projects for the five NSPS regulatory options. The
peak annualized cost of the options ranges from $12 million for the Flotation All option to $347
million for the Zero Discharge Gulf and Alaska option (1986 dollars; the costs in 1991 dollars
are $14 million and $391 million, respectively).

       The peak annualized cost represents the NSPS cost in the 15th year of the regulation,
and is  less than one-half of that for the BAT options.  This is due to three factors;  First, there
are only 759 projected NSPS structures versus the 2,549 BAT structures.  Second, the per-project
annualized costs are lower for NSPS than  for BAT because it is less expensive to design
additional pollution control equipment requirements into a new platform than it is to retrofit an
existing platform. Third, the BAT structures have a shorter remaining lifetime over which to
annualize the costs.               '              .
                                                                                   rV

       The peak annualized cost for BAT projects occurs in Year 1 of the regulation, and will
decline in time as existing projects come to the end of their economic life. The peak annualized
cost for NSPS projects occurs  in Year 15 of the regulation.  Adding two peak costs that are
incurred 15 years apart (as was done in  EPA 1991) will overstate the annual cost of the
regulation. For the purpose of evaluating the, economic impacts of produced water costs, it is
preferable to use the peak annualized cost for BAT projects and add one year of NSPS costs.
When  the regulation goes into effect, the industry must decide whether to upgrade existing
projects to the new requirements (or to close them), and ensure that new projects are also in
                                           6-23
-------
§

^

i
t/J O
8;
i
    1 IB
    n (B
     is
    fi'S
    a N

    li
     1


          oooo  ivioint-  N-oepin
                                           	Os«-  OON.N-

                                           S*»§o  ^WOS

                              §OC
                              «»v
                               «-o.   in  ino  jo  JJJ2
          SSSS  5*»to«-
                                   Kiftob.  &;«»«*'-  s;
                                   v—  o«-  eo  in^  eo
                                             So o* o>
                                             SfCS
                                           M  ino

                                           S  »P
                                            S    S
                            »-   o^-
           OOOO  OO>O^  O^OKI**  *-m*J  3 «t- M <


            '^^|2   "'oifi  "'o—£  "tl —I
                                     i
                                                      »

                                                     si
                                                     si
                                                        §•    o!
                                                        W    •*•:=
                                                               8™  i'5
                                                               •sg  iif

                                                               S*?l
                                                               <«->*-  M) _>.    I


                                                               'I g  si's

                                                               M5  ?S:
                                                               TJ—  D.'O
                                                               C X  i ««
                                                        a <-•
                                                        •* 9
                                                          8
                                                        00.
                                                                      I
                                                        I.I   «...
                                                                                 i
                            6-24
-------
compliance. Hence, the Year 1 costs reflect what the industry will face when the regulation goes
into effect.  To obtain this average single-year NSPS annualized cost, we divide the peak
annualized cost by 15; this value is shown as "Average Annualized" cost in Table 6-15. By using
an average of the NSPS  costs, and the peak BAT cost, the total annual cost of the regulation will
be a more accurate representation of the cost in any given year. The average annualized cost of
NSPS options ranges from $0.8 million to $23 million (1986 dollars; the costs in 1991 dollars are
$0.9 million and $26 million, respectively).
6.3    TREATMENT/WORKOVER/COMPLETION FLUIDS

       BAT structures will only incur incremental costs for zero discharge of treatment and
workover fluids. The assumptions and costs for the zero discharge of these effluents are
presented in the Development Document and Wiedeman, 1992. Key assumptions include:
              Structures with more than 10 operating wells would have sufficient produced
              water volumes to be able to treat treatment and workover fluids within the
              produced water system. These structures would bear no costs for this wastestream
              incremental to meeting produced water discharge requirements.
              Structures that pipe water to shore for treatment would bear no incremental costs
              other than meeting produced water requirements because the centralized
              treatment facility would have sufficient volumes for dilution.
              A well gets treated or worked over every four years. Each job generates 200
              barrels of waste and costs $12/bbl (in 1991 dollars) for disposal.
The cost per project, then, varies by the number of operating wells. Since we do not know when
a BAT project will work over its wells with respect to the implementation of the regulation, each
project is assumed to bear 1/4 of the cost of treatment and workovers every year it operates.
That is, it is treated as an increased operating cost.  The total annual cost is calculated with the
assumption that 1/4 of the BAT wells are treated or worked over in the first year of the
regulation.  BAT costs will decline after the first year as wells become exhausted. These costs
are summarized in Table 6-16.
                                           6-25
-------
TABLE 6-16

SUKHARY OF TREATMENT, WORKOVER. AND COMPLETION FLUID  COSTS
Scenario
                                     Treatment & Uorkover Fluids

                                             $1986         $1991
                                 Completion  Fluids

                                   $1986          $1991
BAT (Wells already in production on existing structures):
   Annual Co«t Per Structure:
         Gulf 1a
         GullF 1b
         Gulf 4
         Gullf 6

   Total Annual Cost
      $533
      $533
    $2,132
    S3,198
  $600
  $600
$2,400
$3,600
$1,504,032    $1,693,200
BAT/HSPS (UeUs drilled on new and existing structures):
Gulf 1b
Gulf 4
Gulf 6
Total Cost (15 Years)
Average Annual Cost
$533
$2,132
$3,198
$5,237,996
$349,200
$600
$2,400
$3,600
$5,896,800
$393,120
$1,599
$6,396
$9,593
$2,804,470
$186,965
$1,800
$7,200
$10,800
$3,157,200
$210,480
Notes:   The per structure costs assume that treatment or workover occurs every fourth year.
         Cost per year will decline as BAT wells become exhausted.
         Costs have been adjusted to $1986 using the ENR Construction Cost Index (4295/4835.2).
         Very few of the existing (BAT) sources still drilling after HSPS is promulgated are
         estimated to be on small platforms (see Section Four).

Source:  U.S. EPA, Office of Science & Technology, EAD.
                                                6-26
SUM TUC$.WK3    27-Oct-92
-------
       NSPS projects will bear the costs for zero discharge of completion fluids for productive
wells, in addition to treatment and workover costs for those wells. As with the assumptions listed
above, only the small Gulf projects would bear costs for transporting treatment, workover, and
completion fluids to  shore and disposal. Based on the projections given in Tables 4-24 and 4-25,
an average of 117 wells per year are completed each year on small Gulf projects (i.e., Gulf Ib,
Gulf 4, and Gulf 6).  Completion fluid disposal costs are based 150 bbls of waste and $12/bbl
disposal costs (1991  dollars). Completion fluid disposal costs are treated as one-time costs for
each productive well drilled in the economic model. Costs for the disposal of treatment and
workover costs do not differ for NSPS projects. These costs are also summarized in Table 6-16.
The costs were developed in 1991 dollars are were deflated to 1986 dollars for use in the
economic model.
 6.4    PRODUCED SAND

       The costs for the disposal of produced sand differ by region and the radionuclide content
 of the sand.  For sand with low radioactive content, the waste is assumed to be transported to
 shore for disposal in a landfill, i.e., the same as drilling fluids and drill cuttings. Regional costs
 for this type of disposal range from $10/bbl to $14/bbl (and have not increased significantly from
 1986 to 1991). For sand with higher radioactive content that must be  disposed as NORM wastes
 (naturally occurring radioactive material), disposal costs are based on transporting the waste to a
 specialized disposal site.  NORM produced sand is assumed to occur only in the Gulf of Mexico
 and the disposal cost is $66/bbl (1986 dollars; $75/bbl in 1991 dollars). See Sigler, 1992 for a
 discussion regarding price level adjustments to produced sand disposal costs and other disposal
 costs.

        Sand volumes, and thus disposal costs for this effluent, are calculated as a function of oil
 production in each economic model project. There are two ramifications from this — produced
 sand disposal costs decline with time as oil production declines, and there are no produced sand
 disposal costs associated with gas-only projects. Produced sand disposal costs are summarized in
 Table 6-17;  more detail is given  in the Development Document.
                                            6-27
-------
 TABLE  6-17

 PRODUCED SAND DISPOSAL  COSTS


Region
Gulf
Gulf (NORM)
Pacific
Alaska
Total
Disposal
Cost per
RRI of SsnH
$1986
$9.86
$66.18
$11.44
$14.00


Total Sand
-------
 6.5    COMBINED COST OF SELECTED REGULATORY OPTIONS


        Three combinations of options, or regulatory packages, have been chosen in order to

 analyze the combined impacts of increased pollution control on both BAT and NSPS produced

 water.  The combinations are as follows:
 Packages

 A
 B
Waste Stream

Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand

Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand
Regulatory Option

3-Mile Gulf/California
Flotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits

Zero Discharge

3 Mile Gulf/California
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits

Zero Discharge
Table 6-18 summarizes the costs for the regulatory packages.  The year 1 costs are $122 million

for Package A and $144 million for Package B (1986 dollars, $134 million and $160 million in

1991 dollars, respectively). Note that the year 1 cost for both Packages exceeds $100 million in
1991 dollars.


       The costs listed in the first column of Table 6-18 are representative of the costs in the

first years of the regulation.  Most of the cost is borne by projects in the Gulf of Mexico, a

mature area for oil and gas activity.  In time, BAT costs will decline as projects reach the end of

their economic life.  At the same time, NSPS costs will increase as new projects come into

production.  During the 15-year period examined in this analysis, however, more old projects wii

cease production than new projects will begin production.  Total costs for the regulation, then,
will tend to decline with time.
                                          6-29
-------
i
eo  8°
~     to

^  s§
III  £ CO
_1  CO 3

S  §1
cu B

3t
*«• 4^
V- tO
UJ
                a o>


                g|
                                        eo
                                    2  C

                                   '*  *•"
                                    *  S
                                    •   B
                                g1

                            U — —- M W M DJ
                            ^.—• —' CO CO CO t-
                            ^ - - -T «j a) -g   "o
                                     h  & 1fl  •   «
                                             S   g
                                                   s  |
                                                   «  *?
                                         t>-   
                                         »-   «M    oS^^  wo_  in^

                                         ^   •*"          1
                                         «*   M
                                                   S   5
                                            is   §
                                            (»"  S
                                         «*   in    -* «* »p •» o N. •*
                                         ii   in    in r- cQ o vt eo j-
                                                        I
                                                         O 3 — *
                                                    oB *l 4-»3  U-
                                "5 "D 8 C CD ^ C
                                —» i> u o E tu co



                                 CO u oi t- Bo
                                — c. a. i-1— u o

                                —   co   co wo
                                ••- H- O- I— O- IX O
                                 t-
-------
       The second column of numbers in Table 6-18 indicates the costs of the waste packages in
the 15th year of the regulation.  This is the point in time when all BAT projects will have come

effectively to the end of their economic lifetimes, and when NSPS costs will have reached their
peak. At this point in time, Package A is estimated to cost $36 million and Package B easts $86
million (1986 dollars; $38 million and $94 million in 1991 dollars, respectively).
6.6    REFERENCES

DOI. 1991. U.S. Department of the Interior Comments submitted in response to the March 13,
       1991, EPA proposed rules for Offshore Oil and Gas, Enclosure #1, receipt by EPA dated
       June 11,1991.                                                         .

EPA. 1991. U.S. Environmental Protection Agency. Economic Impact Analysis of Proposed
       Effluent Limitations Guidelines and Standards of Performance for the Offghori Oil and
       Gas Industry. February.

ENR. 1992.  Engineering News Record. ENR Market Trends, ENR Index Review, 3 February,
       p. 40.

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.  1988.  "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.

FR. 1992.  "Outer Continental Shelf Air Regulations; Final Rule," Federal Register volume 57,
       4 September 1992, 40782 ft       .  .

Sigler, E.M. 1992.  Price Level Adjustments made to Offshore Costs. Memorandum from Eric
       M. Sigler, ERG, to Offshore File, dated 3 March.

Wiedeman. 1992.  Supplementary Information to the 1991 Rulemaldng on Treatment/Workover/
       Completion Fluids.  Memorandum from Allison Wiedeman, EPA, to Marv Rubin, EPA,
       dated 22 January.
                                         6-31
-------
-------
                                  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, EPA assesses the economic impacts of the
 various approaches. Note that the focus is on the change from the baseline caused by the
 additional costs, rather than on the baseline values.  Section Seven is organized according to
 effluent:

        •     Section 7.1: Drilling Fluids and Drill Cuttings
        •     Section 7.2: Produced Water
        •     Section 7.3: Treatment/Workover/Completion Fluids
        •     Section 7.4: Produced Sand.

 Section 7.5 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 well. EPA made its
economic achievability finding for the BAT limitation and NSPS for control of drilling fluids and
drill cuttings on a per-project basis. That is, EPA considered the  relevant phases of oil and gas
activity in making its economic achievability finding. The phases relevant to limits on drilling
                                          7-1
-------
fluids and drill cuttings are the exploratory phase (where drilling occurs in search of hydrocarbon
reserves) and the development phase (where the well is drilled in preparation for production.)

        EPA believes that to assess the economic impacts of the BAT limitations and NSPS for
drilling fluids and drill cuttings, it is necessary to assess the costs incurred at both the exploratory
phase and the development phase. While exploratory activity is always considered existing source
activity, development activity may be considered new source activity if significant site preparation
for development occurs after promulgation of the Offshore Guidelines.  Thus, to assess the
economic achievability of the BAT limitations and NSPS for drilling fluids and drill cuttings on a
per-project basis, it is appropriate to include both the costs of BAT and NSPS compliance
associated with each project. The economic models incorporate the incremental costs of
pollution  control for drilling fluids and drill cuttings for all wells associated  with the platform,
both exploratory  and development.  (Note that  the per-well costs of compliance with the BAT
limitations or NSPS are the same since BAT equals NSPS.)  The per-project impacts  discussed
below, therefore, incorporate both BAT and NSPS effects.

        The per-well cost does not change, but  the total cost borne by a project depends on the
number of wells associated with the project. The tables in this section show the impacts where
all wells associated with a  project are drilled under the new requirements.  If only some of the
wells for  a project are drilled  under the new requirements, the impacts will be lower  because the
total costs for that project will be lower.  For example, if an existing platform still has to drill
three wells to complete its drilling program when the regulations go into  effect, the project will
bear the incremental pollution control costs for those three wells. The impacts for that project
will be less than  those shown  for a comparably-sized project presented in this section because the
 impacts are calculated assuming all wells associated with the project bear incremental costs.

        Table 7-1 lists the impacts for the oil and gas projects for the Gulf of Mexico. Table 7-2
 lists the impacts for the oil and gas projects in  the Pacific. Oil-producing projects in Alaska and
 their impacts are presented in Table 7-3. Impacts on gas-only projects are  presented in Table 74
 for the Gulf of Mexico and in Table 7-5 for the Pacific and Alaska.
                                             7-2
-------
    too

    O i
•s
i£
>z:
T  Si
N-  -o.
_
          &

              £5
               "

              04*
                s
                 •
              L. 0)
              O. CL
         sg

         &. c.
         82
                8
                    -     oogg    oooo     oooo    oooo    oooo     oooo     oooo
                          oooo    oooo     oooo    oooo    oooo     oooo     oooo
                        ooooo  «-«-«-«-«-   «-*-«-•-«-  OOOOO  «-«-«-«-«-   to to to to to   ininininin
                        CMCMCMCMCM  CMCMCMCMCM   CMCMCMCMCM  «-«-«-«-«-  CMCMCMCMCM   CMCMCMCMCM   CMCMCMCMCM
                                                                                        oooro    OOOCM
                                           »-^   »-OOO«-  "-OOOK1  tOCMCMy--*   CM^-«-«-lT>  N- r—   tooeoto
                                            •*-*'>*-*'O  5»Sj5jo«-  *-*-*-*-!*

                                            8SSJSS  888SS  88888   ^^N;
                                                               oooo     oooo     oooo    oooo
                                     coeoeocooo   N-s-N-r^f--  eooocoooco
                                                 S5S55  MM«»M«»   55555  55555  55555
                          gggg     gggg     gggg    gggg     gggg    gggg     gggg
                          OOOO     OOOO     OOOO    OOOO     C5OOO    C9OOO     OOOO
                                                                     ;C>   CMCMC
                                                                                      M rO fO OT fO   00.0 C^ C^
                        OOOOO   '•-•-•-•-•-  CMCMCMCMCM
                        ininininin   ooooo  	
                         «1 (U
                                                   ...... g,

                                                   MM
     . _     a a a u     co co ra"o
     i _w   o m co m co   ummcaco

0) t) 0> '£   •- 01 01 0) 5  —OOOO
                                                  CO I  I  •  V   CO I I I
                                                  	• IN   coro«3-oo i
                                                                       S.^*^M-O   V*^*^-*^O   u>*-^-***O
                                                                       aczx t.   cazzzt.   «xxx>-
                                                                     OJiiiV   OfiiOl   aiitfli
                                                                     co to »» COM   mto^eoN
                                     •* •* «* <* »*  t>-o-0*0-0
                         «*-*•<•-«»-«•-   «§-«•-«•-«>-«•-
                                                         CMCMCMCMCM   »*«*S»^^	
                                                         »-«-«-•-»-   CMCMCMCMCM  -»-»-»•» »!•
                                                       OOOOO
                                                        — ~- -~- ^ ^f


                                                                <+•   «*• H» M- H-. H-
                                                                                                     »aco
-------
    il
    S i
(M  SO

tl  Sg  o

8
                ^
              S.
  £
  m
  %x

*a c
•M O
                            gggg

                            OOOC3
                            Sxxx     «x«>«
                            000     0000
                                                  CMfMIMCMCM
                            MttXX
                                   -
                            ooin*
                             iiii     iiii     iiii
                                              S   SSSJSS
                                             jio   fu oi r>j «C»(»t     MM

                                        *~*T%^°^     *^*7
                                        ooforo
                          K.ioir\in^   ^oc>JK-   ^tp-v-iniM
                          rooSKK   SKIKIPJO   «-inin^-«o
                          KiKiioinio   £   —
                     a> ai u
              m ra D) a
      L..C     K. L. (. f
      ao     0 a a o



      tio   ••- « « «i'o

            a i
            co to

            •O-O-OVJsO


            u o u u u
                                                    S^.M-.^ O

                                                    9C3EX "-
                                                  ID I I I fl>

                                                  mKiotra N
ooooo


u u o u u
                                                  u u u u u
                          0.0.0.0.0.   0.0.0.0.0.
t
4->

I
+*

3
                                                                g
                                                                (O
                                                       7-4
-------
 to



en u-


1^ Q.




d?


is
N.

Ul
   O i
   £ c/>

   ss

   —i a.
   03E
   oo
   UIU

   gi
            o
           H- M-
           O V


           "> 3
           L. *fi
           a o
           01 C.
           >- a.
            ;s
           8.°
           C. L.

           O V
           CJ O.
        o c
        S.2
           >
           a.
                     xxxx
                     oo
                        >oo

                     oooo'
                            gggg


                            OOOO
                    gggg   gggg    gggg
                    oooo   oooo
                     gggg
                                                           oooo
                                   OOOOO  OOOOO  N-N.N.N.N.
                                   tomtom*!  fo w in i»» to  CM CM CM CM CM
                            XXXX    XXXX   XXXX   XXXX
                            oooo    «-•-»-»-   oooo,  »-«-«-«-
                     oooo
                      1 1  '1  1
                    co co co co co
                               1  1 1  1
                          in in in in in
                          ooooo
                          CM CM CM CM (M
                  OOOOO  CMtMCMCMCM
                  ooooo  in in in in in
                  fO tO tO tO tO  ^~ ^— *"* *"* •'""
                    ooooo  ooooo  ooooo  ooooo  ooooo
                     XXXX    XXXX    XXXX   XXXX    XXXX
                     «—«-«—*-    OOOO    OOOO   *- «^- w «-    OOOO
                                        oooo
                    N- in in in in
                                        o
                   01 £1 01 i.
                   a> D> o> o
                   u fc. u .c
                    CD CO ID
  (. U C..C    I- L. C..C
  aCDCBU    fflCBCOU



— 0) «l 01(3  -5 0> 0) 0)0
                    •«««?
                    an cp a

                    CD CD O U
                   01 CO CD CD CO

                   •— t> -------
B
5?
u. c/>
toS
s.
        U
        C)
        4-*
        O lAl



        Ifc
        cj a.
                   gggg   gggg    gggg    gggg
                   dddd   dddd    dodo    oooo    oooo
                  MCMCMCMfM  CMtMCMCMfM  CM CM CM CM M

                                                         CM CM CM CM CM
                  ododd  ddddd  dddd
                        s;   777?:   777?   77
                              dddcM    dddc<3   OOOCM   OOOCM
                                                          fcfcfcfcfc
                    ooo«-    ooo«-
                                                 oooo   oooo
                                       CMK»t*»KI«3-

         MMIOIOM  IOMMMJJ  Mfjjp
         5»55»3»5J  5J3?3»5«»
 gggg
 dodo
                              gggg    gggg    gsgg   gggg
                              oooo    oooo    oooo   oooo
 111     111

 £•«£•     *r«"»r
 CO CD CD     CD CD CD

 K>MK»     IOK>W
  ITcT *Tu    cT dTcTi
  O) CS Dl CD    O) W t» I
  &. t- £. JC    t. IU t. J
  o a ffl u    CD a a i
gcacacata  |2CDCOCD<
co cam

IOMM
• •. •« ••, 0)    ••• •« ••> Ol
d)0«iu    a> « o u

S??J    ???J
                                        ro «> oi"5    a a a o
                                       g co m co w  g co co co _w  g
                                       41 •,. *^ •*. o  41 •»• *p» •*• O  fl) •*- »^ "" O

                                       l"iS  -«-«!*  •"**
     01
• »» •-D)
0) 01 01 U
D> O) D) <0

a a a u
- -- CD «

   
-------
LLING FLU
PLATFORMS
ON
LUTION CONTROL OPTIONS
EL PROJECT IMPACTS - G
<   o!
f-   a.:






















































3
_J

O
ac
<
CJ
u.
CJ
£

§
*-•—
o <••
2|
o o
01 L.
>• O.

01
4-*
a
-E
22
L. 01
OIK
S*-
— O
s

I
*J
o ++
1- o
O.O

4-» *-
G)«ft
SB ^

«v
g
u
g
is
3 fia
o <-
(. 01
a. a.
44
0)
o
u
01
•4*
2g
8.01
i. L.
SO)
CL.

4>H
g
*•*
ll
1— W

°i
zt









V
t
c
a
g

X
a
a
o

01
§
J=
u
X
a
4^
a
0

c
a
g
X
a
44
a
o



01

j:
u
*«
a
a
o


i

.c
u
M

a
a
0
01
i
a
j=
u
3
a
e>

O
i
Ul
u
CO
<3
IU


                            oooo    ooo^

                            oooo    oooo
                            XX MM
                            XX M
                            «-«-oo
                          eowjo»3«3  ^^_^.,_^.
                          ^7^*E^^  Jj^^j^jjj

                          ooooo  ooooo
                                        gggg
                            O O *O CO    OOOO
                             t  I ^«—     till
                                 f  I
                          ~,V«M««  SSPS!?
                                      «» *»*»•»««
                            O C3 <^" fO    O C) O O

                            OOCNJCNJ    OOOO
                          85SS58
                                        gggg
                          g§S2S   5
                          ooooo
                          «»«»«*«»«»
                              g
o£>£>o    gggg

oooo    oooo
                                       NIMIMOK
                          MIOMMKI  •«»•*»» «
                          O^ O* O* Ot O^   ^N v* ^N
                          in in in tn in
                             01 01 01 t-
                             0)0>0)

                          M- 01 01 0> O
                           OI*^*x«*»-O   0)*»-*^*«-O
                           MIZX L.   (AXZK «-
                           - 1 I  i «   01  i  I  01
                           CCIO-icON
                           o u o u u   ccccc
                         (0
                         Ul


                         2
                         i
                                                        7-7
-------
        Present Value (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 Barrel-of-oil-equivalent (BOE): Even if a project must barge all of
its drilling wastes, the corporate cost of production changes less than 1.5 percent or 32 cents per
BOE.  The weighted average impacts for the options under consideration are less than half those
seen for a zero discharge requirement.  Under the 3 Mile Gulf/California option, the corporate
cost per BOE increases by 5 cents for the Gulf Ib, the project that shows the highest impact.  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 3
Mile Gulf/California option, production  cost increases by'less than 0.5 percent or 6 cents per
BOE for the most affected project, the Gulf Ib.

        Internal Rate of Return (IRR): This parameter varies greatly depending upon the size
of the project and the pollution control option.  The IRR for the Gulf Ib gas-only project shows
the greatest range in impacts for drilling waste pollution control options.  Under the preferred
option,  the IRR declines by about two percent.  If all drilling wastes fall under the zero discharge
requirement, the IRR for this project declines by 13 percent.

        For other projects in the Gulf of Mexico, the impacts are smaller.  The IRR declines by
less than two percent for most options considered, and by less than five percent if all drilling
wastes fall under the zero discharge requirement. In the Pacific, the model projects show IRR
                                           7-8
-------
declines from 0.1 to 6.1 percent for the options considered.  Because Alaska is excluded from the
zero discharge requirement, all projects show less than a 0.1 percent decline in IRR.

       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 the Gulf Ib models, the NPV declines by three to
seven percent for the 3 Mile Gulf/California  option, depending on the type of production.  The
declines are even larger if all the drilling wastes from a Gulf Ib project must be barged. The
declines seen for zero discharge, however,  are not sufficient t.o change the sign of the NPV from
the baseline value. For the remaining Gulf of Mexico projects, gas-only projects show declines
about twice those seen for the same option in similarly sized oil-producing projects. For the 3
Mile Gulf/California option, the declines are up to 0.6 percent for oil-producing projects and 1.5
percent for gas-only projects.

       For the Pacific, declines in NPV range from 0.1 percent  to nearly 4 percent for the
options considered for oil-producing projects. Gas-only projects in this region show declines
ranging from 0.3 to 16 percent.  Alaska is exempted from the zero discharge requirement and
shows declines in NPV of 0.1 percent or less.
7.2
PRODUCED WATER
       A project will be under either BAT or NSPS regulations; there is no need to examine the
combined effects of BAT and NSPS regulations  for produced water on a single project.  Impacts
of incremental pollution control costs for existing (BAT) structures are presented in Section
7.2.1, while impacts on projected (NSPS) structures are given in Section 7.2.2.

       7.2.1 Produced Water — BAT
        Section Four describes the process for estimating the number and type of structures to
incur incremental costs of pollution control for produced water. There are no structures in the
Atlantic, and even though offshore production is occurring from the Endicott field in northern
Alaska, state requirements mandate reinjection of produced water.  Hence, no incremental costs
                                           7-9
-------
are estimated for Alaska. Therefore, EPA examined the potential impacts of BAT produced
water regulations only for facilities in the Gulf of Mexico and the Pacific.  Approximately 37
percent of the projects in the Gulf of Mexico are assumed to continue their current practice of
the onshore treatment and disposal of produced water. The Gulf of Mexico projects show ten
sets of impacts, i.e., three technologies, two locations, whether new equipment or an upgrade is
required, and whether radium is monitored.  Impacts for BAT projects are shown in Tables 7-6
through 7-14.

       PV of Total Production: Increased annual operation and maintenance costs (O&M) can
lead to early abandonment of a project. Offshore injection leads to an early closure in 18 of 26
projects. Onshore injection .leads to early closure in 13 of the 22 Gulf projects. Filtration leads
to early closures in either 10 or 5 projects, depending upon whether it takes places offshore or
onshore, respectively. When a new improved gas flotation (IGF) system is required, early
closure are seen in 6 of 26  projects and 4 of 22 projects for offshore  and onshore disposal,
respectively.  When an upgrade is needed for IGF, early closures occur in 5 projects. Most
curtailments take place in 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 BOB:  Under a zero discharge requirement, the Gulf Ib project is
assumed to require one reinjection well to service one producing well. Under this assumption,
the corporate cost per BOE may increase by as much as a factor of three (to  $40/BOE; see oil-
.only project) if the injection well must be drilled offshore.  If the well can be  drilled onshore, the
increase  is 41 percent (to $18/BOE).

       The impacts on all  other projects are less severe. For offshore injection, the corporate
cost per BOE increases from 9 to 76 percent; for onshore injection, the increases range from 3 to
13 percent.  For filtration, the increase is less than 15 percent for all other projects; for IGF, the
increase is less than 7 percent even when new equipment is  required.

       Production Cost per BOE:  If the injection well must be located offshore, production
costs quadruple for Gulf Ib and double for Gulf 4 oil-producing projects.  If the injection well
                                           7-10
-------




















CH.
UJ
g|
CJ 1—
gs
"•i
1?
—1 CO
z? 8
o u —
•-• Ul X
"? 3S *
III /V. J
_J UJ "-
m I— o — '
S 21 3
c'
o
O *J
CD o
01 I.
>- a.
CD
Net Present
($1000)
4^
S
g
p
O L.
a. o.


0
to ui
o cu
u a.
•gg
u m
"* 0
g^
8|
a. a.
*-«- -r-     o ooco oo t>
                                                           xxxxxxxxxx
                                                           CMsfo«-«-«-o»o«»in
                                 am**«--**«-^
                                 *OMv-m«-"
*~*$ S cl*"*cl'I~*§{ °»*^*"»  °»J
                                      OOOC\J
                                      •- to •- K
                               gc
                                                           p*- *~
CM in K> CM t\i f\J PJ CM C\J CM CM   w «- *O ** *- -^ »-
                                                         »- OrOCM*- CM «-CM «-«-»-
                                             ^- in in in     «" t
moommininointni

tt\tnu\u\tn in" in in in in in   >o >*
                                 O^ co Is- o* ^ «~ cN- v- c\j   oocoin
                                 mN>c\Jh^(MCOinc\JCM   <^ c> co N-
                                                                                                            S!
                                                                                                            i
                                                                                                            4->

                                                                                                            8

                                                                                                            •o
                                                            g»«
              »        g


            511     I
            O g 'S _g  "g


            'li<52  1
   g     -S^-S2±:u.uu
   L.      o 3 S o — a ca

  JC C 3 P) X O)
   u o v a. o a. i  i  i  i
0 (0 '^ Z 3 Z 13
c-r *i .L -L .L '  » 2 g £
                 ^_ ^_ .!• dw
J                    CO CO CO


                    O C3 o

                                                                                 g
                                         O g'S §  'c
                                         •MX co^   5
                               5c»feafeNlu —
                                U O  U U.CU D- I  I  I  I

                             E w '5Z I  I  I  O  3) O 0
                             — oioinininini-c-t-t-
ca i.—• u- u- u. i
CD 0— (	
m CM c
                                                            °2S8|J?!SlOOOOO
                                                            rviu.— •_••-• — oooo
                                                                                                            i
                                                                                                            a.
                                                         1
                                  7-11
-------
§1
Su.
i
cn<
g-J

i?
gs   i
§1   *
2"   *
            8.
            .
            O Ul


            SS
                  X

                           XXXXXXXMMM     XXMMXXXXXX     XXXXXXXXXX
                           CD CD CD CD ^3 CD CD €D CD ^3     <~" """ O CD CD CD *~ CD CD CD     CD CD ^3 O O O O ^3 O CD


                           dddddddd O O     «4«^OOOOv^OOC3     OOOOOOOOOO
                                                         —
                         ocoo.ooooo.ooo   o. co co o. o. o. o> co o. o. o.   00.000000-000
                           xxxxxxxxxx     xxxxxxxxxx     xxxxxxxxxx
                                                            »-.o»--oeocDo        --
                                                      CM1111111'
                            > eo f> M c> M CM eo 01 r«
                                                      to
                                                      CM
                                                            « >* «  <  ro « «-
                             cx in o in ca o ft •- *-
                                                                                in -* r\j o ru CD KI «- o o
                         «-«OCM«-»-«-«-CM«-»-«   «MCM'i- *- O K> «- »
                                                                                    O      f.
                               *J U     O
                             •^ •*• CO     +*
                             I- Cf C   "-
                             o o u 5   c
                             ** x COM-   o
                                                                                           L. 01     a-
•>-»-
c-c.cc   •—
o o u o   e
"8!

                                         I  I  I  I
                            §
 •g§225£
^s????
                                                                               »- 4J i  i  i  i  0) 0) 111
                                          L-c-t.   -p-oeiininininc..^.^^   •»-oaitQinintni..f.crt.
                                             CO
                                             C
                                                                                . -^ u. 'u. u_ u_ en co i
                                                   7-12
-------
                   CLCO


                   «»
               ?  11
                                   "8
                               g   I      2ggggg£ggg     gggggggggg

                                   a      cxcjoo ooo- ooo




                             §i   **
                               i.   a

                                   a
                                   o







                             o

                             3     3      CMM»-O »^C>«»»-pp     «^CM«-C3«-p -J-ppCD

                             -"     5



                                   o    vv^mO^^N-O^poincMO   •4>oo(^O^NB^ininp^CM

                             u *~>   a    !?h.oepcM epcMNO>cMCM   o o ^ fi co 10 eo CM to oo eo

                             O-<
                               <
                             4J ^
                             OM
                             Z •




                             4-*

                             o     3      oinru»-ra«-incvjoo     inincMOCMO COCMO<
                             u     f      CM                      CM


                             §     X

                                   a





                             a.








                                   o

                                   X

                             co HI   a    •* CM m o K. o N. «o in eo eo   o eo M «-«-«-«- N. h». CM CM
                             t O   4^    ^ "^ ^ t*) ^ fOv^CM^^   OO^vOO^OC^CMO^O^O-


                             §-"   2
                             00        ioini******* *»*»«»*»«»   "*»«»«»




                                          %C %C 2C kC jf >c >c AC frC AC     AC AC AC AC %C AC kC %C tC AC


                                   a      CMC3OOOC3CMC3OO     OOOOOOOOOO

                                   5

                             ss   Z

                                        CMeOCMCMCMCMCMOOl





                             «"n        u\*ttninuMnin*ttnihii\

                             £2
                                          SO*«— «- t> «- O> «- I
                                          ^•*«-M«-MO(
                       OO*-*-CMCMCMCOCOO<

                       **fi2*S*85»'
                                             o. in in in in in « to 10  o o
                                                          to 10  o o •* e
                                                          «- «—  4* 0*0 *
                                                                            co co ro •» »»
S
                                               «»  •»   >•»«»«»
                                                  T--Z ™ —  ^
                                                  sis!   §

                                                  'is
                                   ii
                                 r^.s-c   I
                                  §    £   5
  s    HiHISss     ff    ill


  •g g 3 £ 5 S i  i  i  t    u "g .§ J Hz S •  •  i  i
C •*• 't* i i i i O Q 01 4)   C *^ '£ *  i  i  •  0>OV4>
•-oainininini-t-t-L.   .~a«jinininini-i-L.L.
                                                                                        •o
                                                                                        o
                                                                                                                                 m


                                                                                                                                 in
                                                                                                                                  S
                                                                                                                                  o.
                                                                on L.-^ u. u. u. u-"
                                                                  SOI «- O <9 C9 <9
                                                                  N u. — >->-<-< i
                                         3
                                         <9
                                                                   7-13
-------
     «S
55  §
«>  53



ut  a..


%  t!
P  ca:
           CD o
           «J U
           >- a.
          3



          I


           uR
                 g
               P

               h
               u a
           O 1*1



             SQJ


             **






           I§
               V O
               U C_

               a. a.
                      IB
                              Foooo ooo

                              «* o o o o o o
                                         ooo

                                         ooo
                                                                                 KM
                                                                                 «— o
                                                                                     ooooo
                                                         | *~v— «— «- «— CM •- «— *-     «— O O O O O O O O O
                                                     o»ococoooeocoh-eocooo
                                                                                 ^CNieoroeoMtMinracM
                                                                                 *»•- i  i  i  i  <-  i  i  i
                                                                                  i  i           i
                                                                               33833838233
                                                                               83888888888

                                                                                                  »€>
                                                              inininv-inintn
                              ^oooooooooo
                            eoincocoeoeocococoooco
                                                                                 roooooooooo
                                                                               sssssssssss
                                                                               mtoMroroioroMioroi'i
                                                                               OCMOCMCMCMCMp>OO
                                                                                 
         D)     T> ^;T) C--> U.U.


MM     CD     C-   L.NU-*-*>^
        jc* c x u>x in
 -  -      o O fl> DL W U. I  I  I  I

       CU CO •*• 3C 13 Z 3
       e«-*jiiii««i«>ai
                                                                                  01

                                                                                  D)
                                                i  I


                                                  e>
                                                                c. u    •—
                                                              D) O D)     C.

                                                              •Siife    S

                                                              o o"o o  'E
                                                                                      o     >—   ••

                                                                                    

                                                                                   •D -~.TI I	• u. u.



                                                                                    L.   C. N ill >-••-•
                                                                                               i  i  i  i
                                                      CD  x P>
  o o cu a. v a.
o co »- ae 13 ^ o
c•— « i  T i i cucvaicu
•r-ocoininininc-c.c.c.
_   t-oro-oro oooo
cu o 4->         j:f f^:
                                                                                              co to co co
                                                                         OO   m N u-— •-•-! •-•
                                                                                                                            8!
                                                                                                                             U

                                                                                                                             O
                                                                                                                        or
                                                                                                                        111
                                                                                                                        a.
                                                                                                                            i
                                                       7-14
-------
   w o

     "
   —i en

   85
   ae ct

   85   o

   sa   g
   l- -a   UJ
   no   i

   a*   s
   Q. -J
•f  S
                  I
                        gggggggggg    gggggggggg    gggggggggg
                 CO      OOOOOOOOOO    OOOOOOOOOO   OOOOOOOOOO




            <5 e.  a    poooooooooo  OOCKO-OOCKOO-O-CX  ooooooooooo

                 a







            at    o>      eoin«-«-«-«->o eoKK    --to to o to o ~* o in co   ra M in in in  «O CM ^ CM O> l»5 «- «-    CM in CM «-CXJ »-in CM O O   O 1*5 »-O «-O »» «-O O
            jo    ^      roiiiiiiii*     «— iiiiiiiii    v-itiiiiiii



            9    ca    h- to in «o »• CM  o CM in o CM--f>-to «-!•» in  M in o to 10 *- «- eg «- to o o «- «-  in oo co •- ro «- to N- CM •« sr  -o toin to  CM CM N-CM r--h-»-^«>M*4'^fO1O   ocMinKkintocMO*^^1

            a    9      ^>-o to o too in «-^CD o    co to CM OCMO to >-oo   o to «-o •-OM •-o o
            o    g

                 X

                 o


            l!





                        KKKKKSSiSKiC    gggggggggg   gggggggggg

                 a      CM ni CM CM CM CM cvi ni N c\i    oooooooooo   oooooooooo
            O UJ  .C       I I  I  I  I I  I  I I I

              §m
              "  X


                 °    *§KKKSKSSSK  ssSssssssss  ********'

                                           inininintninininmtnin  _ , , _ _ , _ _ _ _ _

                                                                tScSeSeSeSeSeScScScSS

            Q.IX
                      OOin CMCMCMCMOo-OO  O O-^m-d-«»eoeao(x

                                           *".<88  8  35*"*




                                                    .1      B
                                                    L. 01    •-
                                                                         *-• X «8 '•-
  Ol    AI3EOO44        9)    €>SCfl>O4<'       fll     01'
  a>    "o •NS*D t_ —* u. u.    o    *p>s'D'--T'uuu.    en    *U'

  CO    t-   C_Mu.i-^»-i    CO    S-  C.NU.a-*M«    CD     C.'



c •— -M i i i  i G> v a> u  c — 4J i i  i i 
-------
     i!
     i?
     S5   §
UJ   OL-J
-4     Ul  U.

m   t~o  •=>
                    g

                 1!
                  __
                  u JJ
                 a. a.
                 sl
                 . . -
                 OUI
                   O

                 ss
                        X

                        8-
                        «
    ooo^oooooo

    oooooooooo
                                                                  inminininmoo
                               oinrucxjcMtMN-rxJoo

                                i  i  i   i  i  i  i  i
                               NO >o -o o >o -o vo -o  N- to «o co co eo N. a to eo
                      •» co

                      NrJ
                    i   i  i
                                                             •* «-; CD •* »r Oj «o m >o •r-     in m e\i •» 10 in

                                                             cpcoCKC\3oxrJtos!o»-:     •ovroroor
                                                             oh-r«i«-ro»-Ke\i«-«-     ocvi«- i  »- i
                                                             ruiiiitiiii      iii    i
 oo»*-oo«>jco»-r-ro   o> I--
- to h- en »r co  in   coo>%rtninrviN>oo>\DiM
                                              -                        -
                                                                                      coo>%rtninrviN>oo>\DiM
                                                                                      ro CM in »o •- «O «- <6 «- M ro
                                                                                      -o «— F«. CM in c\j in *o ro in in


                                                                                        "
                                           i- o- «* 10 in co
                                 v-v-OCMOOCOCXJCM     sffinCOOCOOi^^O
                                 eo <•* ^ ** *— eo roo^h^h^     inin%oo«oo
                                                             0«W   CM   ^^          K^-    ,    ,
                               toeoinro^ttoroio   ooch^oro^omfloforo   j-*M(>j<>J
                               «— •" *• »•«» «•- »— •— «-• «— w—   *—|Ul»— H— *"•«•*«—«— ^*— «—   «— <\|«— «— V— ^^«— *— «"W—
                                 gggggggggg
                                                                                                        sss
                               toeatomtatotoeoeototo
                                                                                       >Og>O>

                                                      E
                                               v     •?
                                                 c   ~
                                                 o   c
                                           >!7«"»t>   *»j/j   gMgwg   p.0.



                                                         8

                                                                     D)
                                                                        I. 01      •—

                                                                        gO D)      I-


                                                                     -£ CO      2
                                                                   O) O Dl
                                                                   C-M t.
                                                                   >,_ 
   UOVU.Ou.llll
 v«~-a:=)z=i            u
 C*^A>iiii4}8ICI4l   C*
w-ooinininint.t.c.1.   ••- <
-^[-•oro>orooooo   —
 a> o *•         \r= j: j: j:   «>
 CO U-'U.U.I^LU CO CO CO CO
 a o — oooejcccc
CDNU-^«*-*^«>-^OC3OO
                                                              SO E «> O <-•
                                                              *D ^x"D L. -^ u. u.
                                                       t-      — O<9
                                                       O^t-i-t^U.*- —


                                                       O O (U Ci Q> CX i  i  i  i



                                                     «::i5oininiriirit..t.tt

                                                     01 o 4J  •
a:


I


§

1
                                                           7-16
-------




































85
|>v
ZB
S£
CJ K
O U.
G£ tf
O 	 1
U, _l
to O
s«
PS
&.
ss
ii
- g
— UJ X
CM 1— ~i Ul
«- 3 O Z
i -i oe
"~ 9°" S
111 S.-i
«J UJ bu
£D 1— O — J
< «S 0 =
J~ mi S
•4--°
O -w

« 3

ID O
U 1-
3
\
in
c. o
0.0
%S
Z v
4-(


g
+J UJ
•§ ™
o c-
(L Q-

4-*
8
U
+j
O UJ
t*- g
t_
g.
*0 w
s s
CO C

•^
p
o. o.

(0
4J
1
2
4-»
i
g
4^
_3
O
Q.













V
I

CJ

X

CO
o
U
X
g

a
x:
o

CJ
p
a
o

o
5
(D
4^
O
(0
5

 in


in»-
                       *« »« »« x x »« »« >« J* S
                       &> •* o •* o ^ to S.  CM CM IM  CVI^ JOJO t\l JOJNI MJO JM fM

5 S S «A  oooorocado    <«ooooc9 oc3 oo   taooooooooo
S3  $,>«»*>




 .1      g
 'H a    •—
  go o>    c.
  «J C.    O

o g "5 _g  'g
                              SOOOtOfMtM
                              •* «5 «- 5s «- «-
                               "      ~ •"
                       8!
                                S      B
                                t- 0)    •—
                                go O)    «-
                                •MI.    O


                              •i§!§
                                                     &Q)

                                                     D)

                                                 C W «-
                                                  •t- •*• CO
                                                  l_	
                                                  o
                                                      i  -E
                                 I V— 0(9
                                 . NU- ——
                                                       o +•
                                                       L. — •
  uocuCLwCLi i  i  i     oova.cua.1 i  >
c.£«7?7?«8>«is>   e~-'ijii  i  i one


iUJSIX-M**  s01110"""
CO CD •— O O O O C
mrsiu.» — — «c
                                            SC9 •— SE 3 Z O
                                            .— .Ml  i i  i  g)
                                          •>-o«- o o 13 a
                      m N u- ~ _. ~ ~ i
                        7-17
-------
5

o t
£5
  a.
fe,
    §1



    gs   §

M   P^   K
fi   So   sc
 i   «J oe

    ^^   °
ui   5.-J
_J     til   U.
CD   I-O   -I
<<   •< Q   IP
              ^
               O **
s

I
4-*
£
S~
            s.
             .
          O V
            Sm
            w
              §1
              01 O
              u u
              0.0.
                        gggggggggg    5ggggg2gg§

                        OOOOOOOOO-O    ChOOOOOOtOOO
                      OOOOOOOOOOO  «-O.-»-«-«-«-O.-^-«-
                        in <* >o in  ro in in
 in w
 *- o
                                             f--  »-
                                             >o  oo o
                                            » K-  in in
                                                h- to in >t
                                                o 65 in eg i
                                                O 03 M GO
                                              IM(M<-O«-OK)OOO
                                            T- «» o> in <* in «*• •* »- in in
                                            »- in m fu »- CM «- 3- 1« «- «-
                       gggggggggg    jsgggggsggg
                       OOOOOOOOOO    (\IOC? OOO NO OO
                     eo eo co a eo eo co eo oa co a
                                            co co co 03 co co co oo co oo co
                     rrrvCM CMCMCMCMCXICMCM  inminininminroininin
                        >*o-»o>mo^-oo»o  o«e>o*- CMIMM K>N.o o

                        >c3^S^SS?SJS  **s?35!2tS!?^""Ww
                        *iX irt ^^ ^^ ^* *A ^k ^* ^*     »SS ^% ^^ 4A
                         o. in in in in m jp KI ro   o ^} PJ c
                             O>ir>   in  .-oj.-.-
                             V»V»   M   •*•>*»*»
                                   go
                     C       D>


                   afeS    I



                   ojjijj  'g



                   'iis£  I

            S    -S^-SSli^^
            1.    D 3 OJ OJ — O C3
._           O    L.   t.Nu.^ti-1

I I I  I    .OOOI&U&llll
                     •I O 4J
                       JC-«« I

                       (U— I

                       N U. >
O O O O  —'  C.^OIO^OK) O


         coc.—'U.LUU.U.CO"
            _           s.
                                                                                                           8!
                                                                                                           u>

                                                                                                           u
                                                                                                               g
                                                                                                               a.

                                                                                                               ae

                                                                                                               £

                                                                                                               ce
                                                                                                          1

                                                                                                          i
                                            7-18
-------

CO <
z
O -1
—I CO
o t-

II

Us
li
—10.   O
2_,   E
  UJ   *-•
ss   ^
ca z   a.
          0 CO

          si.
°g
SS
is

                       gggggg    ggggggg    Kggggg     Kggggg
                       o o o o o o    ooooooo    *o o o o o o     *o o o o o o
                                     tnininmininmin  -o tn *o >O O >o -o
                         i i i i i
                                       O *O «4* CM O CM O    *^ 'O v* O «" O     	
                                        (VI  lilt     (M I  I  I  1 I     (M i I  I  i  i
                     5 5 in" f^ S-|C   -2v
                       OOXNO^
                                          in o in o     o CM in CM o CM o
                                                                        !•-CM «-O «-O     rOKtOCMOCM
                                              9OOO    ItC
                                                                        £ggggg
                                                                        tnooooo
                      w
g
                                                        eo
                                                        ^*-
                                                          eoeoeococo  coc
                                                                                      P!S 15 55 fete to
                     in in in in tr\ IA in
                     C\J CM CM CM CM CXI CM
                     o* o o* o* o o* o»
                                                                            CO o^ O* O^ O vh O*

                                                                            co" coco" eo"co" coco"
                     o in eo 10 m ro in
                       SKi

                                         CM«-«-   «-
                                                        3
                                gs
                                                 gs
                                                11
                                                 g3


                                                                       PS
                                                                       II

                                                                       ll
                                                                                                              CO
                                                                                                              s
                      «
                      C ••- **
                                         CD     fc.   ^
                                         .C C X O) X £>
                                         o o « 2x« SI
                                        g w •*- z s z 3
                                             g.2;

                                             "S o •
                                                                        Si,
                                 a

                               V to-

                              "- Q

                              "« P.
                                        BI




                                      ill
                                      F*fBflJ*p-C!lC!]C9C9   OC)'r-C9C9dC9   030>*»*C9C9OC9
                                      1CON11-— ~~~   BOIMU- —~~—  ~-	-

                      OO
                      2-
                                     _OoB

                                     >^ —

                                     '5io
J5S
)-;oa

. 09—•

>w o
                                                                      g  I
                                                             OQO
                                                             tO x^ *.«*
                                                                            «0 X

                                                                             ol

                                                 1-19
-------
can be located onshore, the production cost per BOE increases by 81 to 26 percent, respectively.
In contrast, for all other projects, offshore injection leads to no more than a S4.38/BOE
(88 percent) increase, while onshore injection leads to no more than a $1.12/BOE (23 percent)
increase. For all other projects, filtration leads to production cost increases of no more than
$1.16/BOE (23  percent) when it occurs at the platform, and no more than $0.43/BOE
(9 percent) when it occurs onshore. IGF shows the smallest increases — a maximum of
$Q.50/BOE (10  percent) for offshore, $0.10/BOE (3 percent) for onshore, and $0.17/BOE (3.5
percent) if an upgrade is needed at the platform.1

        Net Present Value: For all Gulf Ib projects (oil, gas-only, and oil-and-gas), the NPV
changes from positive to negative for an offshore zero discharge requirement.  This means that,
although the projects recover their annual operating costs for several years, they would not earn
a sufficient return that would exceed the company's discount rate. In other words, the company
would be more likely to close the project and invest the money elsewhere. Section Nine
examines the potential loss of production from these presumed shut-down projects as well as the
early closure  of projects.

        All other projects show no change in the sign of the baseline NPV (i.e., all that begin
positive remain positive and all that begin negative remain negative).  Decreases in NPV of 10 to
97 percent are seen for the offshore injection requirement; decreases do not exceed 27 percent if
injection can  occur onshore.  Higher decreases, on a percentage basis, are seen with projects with
small baseline NPVs.  Impacts for filtration and IGF are smaller than those seen for zero
discharge.
           projecits barely bring in sufficient revenues to cover operation in their last year of
production under the baseline scenario — the Gulf 6 gas-only, the Pacific 16 gas-only, and the
Gulf 4 oil-only.  Any additional annual costs would shut these projects down 1 year earlier.
Operating costs  are considered to remain constant while production declines throughout the
project's lifetime.  The production cost per BOE in the last year of operation,  then, is at its
highest.  The onshore improved gas flotation option adds just enough costs to  shut the model
down 1 year early but without substantially increasing each year's production cost per BOE.
Under these circumstances, it appears slightly more economical in terms of production costs to
shut the project  down 1 year early.
                                            7-20
-------
       7.2.2  Produced Water — NSPS
       Future efforts that are likely to incur incremental pollution control costs are projected
for the Gulf of Mexico and Alaska. New projects are assumed to treat and dispose of the
produced water at the platform; no onshore costs are shown for NSPS projects.  The impacts of
the various regulatory requirements are summarized in Tables 7-15 through 7-17.

       PV of Total Production:  Increased annual operation and maintenance costs (O&M) can
lead to early abandonment of a project. A zero discharge requirement leads to an early closure
in 11 of 18 projects.  For filtration, the number of early closures drops to five. When an entire
system is required for IGF, the number of closures is three.  Upgrading an intended IGF system,
however, results in no early closures.  Section Nine investigates the impacts of early closure on
production.

       Corporate Cost per BOB:  The highest increase in the corporate cost per BOB is  18
percent, seen for the Gulf Ib oil-and-gas project where one injection well is required to service
one producing well.  This increase translates  to an additional $3.80/BOE in the corporate  cost.
The additional cost is sufficient to change the NPV of the project from positive to negative (see
below). The impacts on the Gulf Ib project are more than twice the impacts seen for any of the
other projects.  Impacts  from filtration costs range from less than one to a six percent increase.
The cost of adding an IGF increases the corporate cost per BOB from less than one to three
percent.  The cost of upgrading a planned IGF system increases the corporate cost per BOB by
no more than 0.3 percent.

       Production Cost per BOB: Production costs increase by 17 to 22 percent for the  Gulf Ib
projects under a zero discharge requirement. For all other structures, production cost increases
do not exceed 14 percent or $1.25/BOE. For filtration, corporate costs increase by four to eight
percent for the  Gulf Ib projects. For all other projects, the increase does not exceed four
percent.  For a  new IGF system, corporate costs increase by two to four percent for the Gulf Ib
projects. For all other projects, the increase does not exceed $0.12/BOE (1.4 percent).  Cost   »
increases for upgrading planned IGF systems increase production costs by no more than 0.3
percent.

                                            7-21
-------
ee


Z
St
tea.

°-«

S3
i§o



|g

II


Is
t-ui
s.  OH:

UJ  °--J
_J  WUJ

§  fe8
•sg
           cSfe
           u S.


             o*
             m
             ^^

           •sg

           §|

           II
   SB
   4J

 f. O
       I
             gggg
                                                             XXXX
                                                             to o o o
             ooino
             CM«- 1
             i  i
                                      -*ooo
                                                   moo o
                                                                          CD O O O

                                                                          oooo
                                                                                          oooo

                                                                                          oooo
           O *O CO O O  ^-OOOv-  *— o ^-«- «—   OCOOOO
           CM»-»-«-CM  CM«-CMCMCM  CMCMCMCMCM   «-«-»-^-«-
             XXXX     XXXX    XXXX     XXXX     XXXX
             O r*- fO O*     CO FO C^ CM    ^3 O* FO *"     fO (X O «"•     O ^3 l/"l *"
                                      CMCMo-O
                                                                 COM
                          xx
                              ^O CM    **~ O ^O ^~
                                                             XXXX
                                                             inosr »-
                                                                                           XXXX
                                                                                           F-co-j-o
                                      w-ill     «—
                                    O & CO-* CO
                                    in»- «* in IA
                                    •Mrv.Jv.ScM
                                                                        CM«-OCOh»  NOtnf\J«-vO   CMOCMOO
                                                                        to 90 r*« o^ co  ir\ f** CM *o c?   ^* IA o* CM o
                                                                        in £. K> o <•  co co -OS-N-»-NO   -J-^CM
                                                        MCM   CMCOK1M--   	
                                                                   tm CM   ou-n-
                                                                                       inouMnin
           w— ^ CM *~ w~   CO O CO CO CO
           CM CM CM CM CM
                        •»*»*•»«»*»
                                                               co co co co co

                                                               MMMMM

             3SSg     ^f«?5g     Sggg    Sggg     gggg     Sggg     J^ggg
                          oooo     oooo    oooo     oooo     oooo     oooo
                           I  I  I        I            I                                      '
                                       m CO C
                                       *o ^a**
                                                                            CMCMCMCMCM   in in uj uj in  inCMininin
                                                                	._ 	 	 	   CMCMCMCMCM   COCOCOCOCO  CM
                                                                O tO & CD C3   f*» r— (^ ^~ r^"   tO lO fO JO IO  C^
           Ororo^oo   «~?ofOM^-   CMOCMCMCM  »-c>«-«—*-   ooooo   952525Si2l  ?f:5^?^^
           Ln-i-ininin   ocoooo   insrinmin  «-'i-'rTT   f±'iri'^:f±   292SS  oinooo
           «— ^-w"«—w—   IO CM CM CM Kl   *3* ** •«* ** **  *O in *O *O *O   *a* ** *X *X *T   CO CO CO CO CO  ^ v-«-• v~ v*»
                        v»-3-«» «» ~»   vO-O-O-O-O  OOOOO
                                                                                     OOOOO*  inmm in~in
                                                                                     CM CM CM CM CM  tO	
                          §--«
                          in -3- in

                          85"
                
                                         O'g(U'SoT3tJT3(UT3(U'D
                                         rncocn«3cncocncao)cacncn
                                         2?   ^™     2?  ^xE     ™  <^ u     cT   «x £.      i-^si-     t-^xi.





                                        •QCOOO   'p-OCOOO   ^-QCOOO  »»-OCOOO   '^-OfflOO   "-acOOO

                              5'"1"  tot^"   •Sot'"'00   Tloi:^00  •Sot™00   «oi:'vl<10   ooi:Clieo
                              — IfeU,   COC--.U.U.   COL.-U.IU   COI.-.gg   g£.-.gtu   g C.-. JU g   g L. .-g 1C

                                                                    U.M**  CO fsl 1^ »^ IM   CONU>^^^«   CQ IM tl. «^ *^
                         WJ >- —' H. H.   WJ^— •»-»   tfl t» —* U. %
            « ^ — — «   COi)M-C30   ej«.^-C3C3   OT«|^-	
            caMu. •-«*-.   CONU-^«   mrsju-^-.—
                                     vO
                                     **-

                                     1
                                                                                        S
                                                                        1
                                                                                                             8!
                                            7-22
-------
    §
    a.

    Is

5   33
            •s§
            J5S
             2S
              s
n:
ss.
             si
             It
             U 0
             a. i-


            OOOO     OOOO    K* O O O    FO O O O    Kl O O O    JO K» O O
                       OO
                       CM CM
                      SSSSS  SRiSSS  SfcSSS  SS0-0.??  fcJSSfcfc
                                                                      XXXX    XXXX
                                                                      m CM •»* «-    in in »o «—
                                                           eo«-oo    co>-oo    o«-oo
                                                           fill     I I  I  I      III!
                                                 XXX
                                                 r>»Ki«»
                           Sxxx
                           in too
                                              fi^f^^i^  CM«-CMCMCM
                                              XXXX
                                         «-    m«»in«-
                                                                                 xxxx
                                                                                       -
                                                         •* COM ao»
                                                         §CMT-KI>O
                                                         •O^ coin

                                                        CMCOOO
                                   in •* in in in
                        4» *»*»«*«»
                                               ^ o «—CM   in co «— KI in
                                               •t^iTMCJ   n- >± h" P^ N-


                                                        «•«*«» 4ft t»
                                                                               Si Si Si SiS
                         roooo     eo»-oo    co«-oo
                                                                                 XXXX
                                                                                 Kl O ** •"


                                                                          OO    t^v-OO
                        ss s; s; s
                          S5S8
O   (O»-oinK>  rooomto
^   mo»«-   iMODiSJW
                                                     «-  m«-mmm  ^«-m«»'-*   CMCOKICMCM
                        88888
                                   KIMMItKI  «»«»«*«»  4» *»*»*»«»
                                                                    •»«»«*«»«*
                                                           XXXX    XXXX
                                                           CMOOO    o-OOO


                          oooo    oooo    oooo    oooo    oooo
                       1S8SS   §5§§§   SK2SS  §|§S§  Sg|5^
                       >Sooo   <«* eo-* ** "•a-   *-ixi *-«—«-  -* co s* «**-^  in ^ ^ in tn

                       -hteh.h>»K»   W K> W OJ Ol   (NJ f*-CM  S^oo-o   FCfCRRR   ^3 -0*0 oo  RsZP-s-s-  ooooo
                            «-»-co
                            in caw
                                         **
                              •^   o in "^ *~ o*  o o oo fM p^
                              rr   KCO.-.S.V  «»«gaS
                                     «
                                    8
                                                    <
                                                    •»

                            8
                          8O^<
                          a«-

                                                      <»x

                                                    J
                                                          &    i
              CO  X O)    03EO)    OSO)    tD   X Q}    Q  3 P)     (D


            Jill  ,1lii  fi1lll  .Ilil   ,11*1   .lass
            '•X-4J      C*i—4^      C*^4^      C1*"*0       C'^4^       C*"4^
            B   — — —   *^ocooo  •'•ociS ^ o  •••ocooo  •*~oa^^   *t~ o co o o

                       8~'o|;c>lco  "ti o u      "S o *•'      "So*-*       T»6*»
                         (_—*U.IJk  COL.-^UkU.  COU-^ILU.   WC-—'U.U.   COC_^U.Ik
              J~-(9(9  COO)-»(9(9  COOI»-(9C9  COO>>r-(9(9   ID 0) ••- CJ O   C00>w(9(9
            coNtk«~  m M u. •— M  m N u. •-<—<  m IM u-— ~  eo M u. — •—   co N u. «•-•
                                     (9


                                     08
                         I  CA

                         !S
                                             tE

                                             I!
                                                         I
                                      g
                                      4*
                                      «_
                                      o
                                                   feL


                                                   8

                                                   "28
•M*C
00.
Siu



«?i
                                                                                                             ?
                                                                                                             u
                                                                                                             01
                                                                                                             o
                                                   7-23
-------
•




































1
s
_
gw
8*
£S
s:
i?
•-
|3
l
O (O
II

o=c
Is §
t= is 2
*T —ice
t^ o o. u-
UI «J
§ WJ UI ^^
i

•sg

2 o
E-B
u
QL
4J
a
g»
IS
t_ «J
4J
s
I
£

C ^^
O.O
4JT-
3C ^
4-*
U
g
1$
o t.
S
u
£
E o

5l
%^
•sg
•^-
ss
«•§
»
c °*

C
Q
g
x
a
a
o
I
o
X
I
o
i
g
X
a
4J
0
4)
1
g
X
a
o
1
g
X
a
4-*
a
a
jr
u
X

«
a
0


12
N
•*—
no*
1
^

§

a
*-•
"o.




o
c.
g
,«
u
U)

8
•^in«o
               CM •- CM CM CM
                                         M
                                         OO
                                      *>ojcorvj    ^Kco^
                                                1  1  1 1
       S.CM«r-r-  cbcorovr
                      CO
                                »-  t^r»in[»in  ft«-
                                              O^CMON-
                                              oo eo ^i «~ in
                                              rotoinoro
                          CMOCMCMCM  fO»-tOIOfO  C>inOOC>(£

                          55555
        exxx    xxxx
                                      )»-00    (OOOO
     r—o«o go  oca
     55555  "3^**   »***.*!
       XXXX
                           xxxx
                            -
                          xx
                          «O«-
                                      xxx
xxxx
in in too

CMOOO
     tO«-eOCMCO  OvOCOMCVl   CM N. in 01


     inco-o-oin  K> «£• K> ro to

     55555  55555
                               CMtQ«-r^CM  O>OS.CMO   omrocMO  o«-r
     worxjro    *^i~fOio    WCM-^IO    '" ~"

     otoh-N-co  oro^N-co   o«-h-K-co  o ^»-N. co  o*-r—r—co
     MK*
                                IS5t3  SKt^^'
                                 omro      -**^

                                 C^"         KT
                  a>          a*         a>         41
             |)    13     ft»    *D    i    «?i    «>i
  jlgl    |!§f   .aj|*|  g||i|  Bj|*|

— a coo  —Q rapo   —appo  —oppo  —aapo
•»*  £• CM CO  ^^  I— CM CO   ^^  C— CM CO  ^**   ^ CM CO  ••^
       *i    •§
       o>    a
                                                  .CMCO
                CO
     m ««— o C3   coa)»-c9o   & 
-------
        Net present value:  For the oil-and-gas Gulf Ib project, the NPV turns from positive in
the baseline case to negative in the regulated case for both the zero discharge and filtration
requirements.  This means that, although the projects recover their annual operating costs for
several years, the projects would not earn a sufficient  return to exceed the company's discount
rate.  (Note that the internal rate of return for these cases is less than eight percent — the
discount rate used  in this analysis. When the NPV is zero, the internal rate of return is equal to
the discount rate used in both sets of calculations.)  A 66 percent decline is seen in the NPV for
the Gulf Ib if improved gas flotation equipment is needed. This is a larger impact than is seen
for the BAT version of the Gulf Ib project for the same requirement (34 percent, see
Table 7-6). The absolute decline in the NPV for the NSPS project is smaller than the decline
seen for the BAT project ($35 versus $374 thousand, respectively), yet the very small NPV of the
marginal NSPS project shows it as a large relative impact.

        All other projects show no change in sign from that of the baseline NPV (i.e., those that
start positive remain positive and those that begin negative remain negative.)  Decreases of 2 to
25 percent are seen for a zero discharge requirement, with the greater change occurring in
projects with small  baseline NPVs.  Impacts from filtration are only about one-fourth those seen
from zero discharge.  Impacts  from a new IGF system do not exceed 6 percent, while upgrading
a planned IGF system decreases the NPV by no more than 0.5 percent.
7.3
TREATMENT/WORKOVER/COMPLETION FLUIDS
       As described in Section Six, only small projects bear incremental costs for treatment/
workover/completion (TWC) fluids.  BAT models will bear only the costs for treatment and
workover fluids because all wells  are assumed to have been completed at the time the regulation
goes into effect. BAT models begin at the projects' economic midlife, a time at which most
drilling programs have been completed.  In reality, there will be projects that fall between the
BAT and NSPS models, e.g., platforms that are installed but complete part of their  drilling
program under the new requirements.  They are much closer to the beginning of their economic
life than to their midpoint but not all wells are drilled under the new requirements.  For these
platforms, the per-project impacts are estimated to be equal to or less than the NSPS per-project

                                          7-25
-------
impacts, depending upon the number of wells drilled under the new requirements.  The number
of wells completed on existing platforms under the new rule is estimated to be small (see Section
Four). The total cost of incremental pollution control for'completion fluids for all wells (BAT
and NSPS) completed under the new rule is assigned to NSPS in this report, see Section Six.

       Table 7-18 shows the impacts from increased pollution control for these effluents.  The
changes for all financial summary statistics are small for the BAT models. The increased annual
costs, however, force the Gulf 6 gas-only project to close one year early.  This effect is examined
more closely in Section 7.5 on the combined  effects of selected pollution control options.

       Table 7-19 lists the impacts for increased control of treatment/workover/completion fluids
for new (NSPS) projects. All changes for all parameters are less than  0.8 percent. No change in
production is seen.
7.4    PRODUCED SAND

       Tables 7-20 (through 7-22 present the impacts from increased costs for the zero discharge
of produced sand for BAT projects. There is no loss in production associated with the zero
discharge of produced sand, either as NORM or non-NORM wastes. All other financial
summary statistics change by no more than 0.7 percent.

       Tables 7-23 and 7-24 list the impacts for new (NSPS) projects.  No change in production
is seen. For a Gulf lb project with NORM sand, the NPV may change by three percent.  For all
other projects and all other parameters, the change is no more than 0.5 percent.
7.5    COMBINED EFFECTS OF SELECTED REGULATORY OPTIONS

       Table 7-25 lists the combined effects of BAT regulatory options on selected projects.
The projects are the Gulf lb oil-only, the Gulf 6 gas-only, and the Gulf 12 oil and gas.  The first
project is the smallest project investigated, bears increased costs for produced water, treatment

                                          7-26
-------
    CO
    o
    o
    K
      =Jb:  =!
co
Yea
Pro
               ii
               -i
Ch
                            x
                            o
g
o
g
o
g    g    g
CD    O    O
                                                                       O

                                                                       o
                                                                                    o
                                                                                    o
                                                                                          g
                                                   g
                                                   coco  oo  oo  oo   oo   oo   oo   oo
                                                           8
                                                                 S
                          8     S     33
                          Or»-
                          inin
                            X


                            o
                                       ££   g§
                                       «*«*   *»<»
                                                         N. tf*
                                                         OO
                                                         OO
             .
            OO  CM»-
                  IMIM
                                     o
                                     CM
                                     f>
                                   o «-
                                   KtCM
                                   rOKt

                                   Sffi

                                   33
                                                                                              33
                                   X

                                   o
                                         o     o     o    o
                                                   Re  fcs
                                 KJ     «»     •*    O
                                  o      •      •     •
                                 o     o     o    •*
                                                                     88   £2   RS   So?
                          33   33


                            g     g
                            o     o
                                               a
                                         g     S  .  S    S
                                         o     d    o    o
                                           23  S3
                     X     X
                     V"     f
                      •      •
                     o     o
                                           X     X     X     X

                                            *      •      •      •
                                           o     o     o     *-
                          KB
                            JCM
                            • w—
                            >*»


                            g     g
                          CMCM   MM

                          5»5   """"
»- CM  in -o  coco   coo   coo   «- »-   ro -*  -»in  o «-
*o «o  coco  i^ r^   to 10   f^ co   *o*>o   v-«*  rnro  IAIA
*-?  4 CO
                           O» O«   *-«—   *— «r-  Ou GO  Q^CX  QOCO   CM (M   >O^O   s^^fCMCM  O» O  OCM
                           in in   44   O*c>  coco  CMCM  «**•**   ^o^o   oo>   «-»-  CMCM  tnin  CM in
                                                         fv. PH.   «~«~.4^J   COCO  ^«—  -^ ^J"   00 CM
                                                         KI ro   oo   r»-s.   K»K»  <*•*  -•-«-   oo
                          inm   coco
                          «— ^   **«!*'
                          	   c5c5
                             D9     O)    D9    O)     R     R     B    D)
                             1.L.L.I.U1.I.L.
                             a     co     co    co     a     a     a     a

                             •g-g-g-S-g-g-g-g-g-g-g-g
                           v «>   vv>   V ai  v a>   ^ co   ci w   «) _to   e> a>  oitn   t> o>   w m   «_»


                           00   cao   o o  o o   co   cj o
                                                                                         82   SS
                                              « 01
                                              ss
                           11   11  11
                           oo   oo
S                                                          ... c.   we.   co u    m t,   u
                                                      ti   con   coo   o u    to  oi   
-------











































w
»-«
U-
g

"{
— J
|
^
oc
2

§
^
Ig

fr™ O-
o"
_•&
O UJ
S^o
o a.
v- % UJ
' 8
2 it,
m — j a.
g g£





























































O
U
»•
a
g
ti.
§,

1 -C
1 U
Six
**•**•!
3 4-» 1
0 1 «J
ajS • *•
UTS i a
a S i a
ti t- i
>-0- I
i «i
f"



C « i **
o> a: i 0
c». ! °
Cl
SI 51
_. ! «!
> i Ci
« :»«
C I
V 1
c_ o • *•
D.5 1 II
^010
sett !
i 41
••-> i n
M 1 C;
5 i «
u i ^:
• o
g :>e
*g *
O O t 19
•fi 1 13
L. V 1
a. a. i
•  L. 1
a. a. •




L.
&




1

1
*
c
X
o
o



OO
CM CM





X




O O
OO

t**
o
1


ii


JJ
o
0



*" CM

MM
«*«»

g
o



J2t
55

g
0


OO
r»iio
OO
mm
^.^.

0)
0
•g
Z£
V 0
e> t-
a 01
ea N


tn 
ii
OO

«*-«»-
11
g
0



OO
CM CM





M
CM
O
h-h-

o o
00
„
to
o


If?
MM

J4
0
0



N-CO
CM CM
^j:
4^ 4ft

g
o



CR
in in
MM

g
o


CM CM
33
mm
,_.-

0)
u

•c

0) 0
a t-
a v
ca N



11
Ii

«*-<«-
11
g
0



rocM





X
*••
o

«— ^
CM CM
OO
X
^™
o
t


Is
mm
MM

X

o



CO O

ss


g
o



go
0
coco
MM

g
O


CM CM
ss
00
MtO
•»•*

V
DI
10
•g
-,M
01 O
n i-
10 0)
miM


O (9
11
OO

«*«»
•»-«*•
15 "3
g
o



CM CM





X
^™
o
to to
CM CM

OO
x
JO
o
1


ill
8»

X
»~
o



o» o

«»fc .


g
o



S5
mro
MM

g
o


S.8
«*•»
II
mm

i
a
•§
g.2
|fe



11
(9 O

•»•>»
11
g
O



CM CM





X
^™ •
c>
«— »—

CM CM

X
^~
o
1


§fO
io
88

X
^~
o



00

88


g




iCR!
MM

g



03 CO
mm


L.
a
•g
W «
St.
0)
CO N


u> a)
S3
ca a
00

«*- «^.
11
g




CM CM





X
*™
0
00

*~ ^

x
*^
1


SR
CM" CM
MM

X
^
0 •



in *o

«»«»


g
0



CM CM
zz

g
0


mm
ss
mm


g
•5
•g
ss
a 01
m N



11
CO 0)
o o

H-H-
C9 U


























































0)
01
i
(A
01
Ul
>B
Source
7-28
-------
S
i:
O U    i
Of ui
f— ™3   O
3EO   U
O a:   --
u a.   x
      uj
£2   3
          °t;
          ai 3
          «"8
          01
          CA
          0) ^N
          u
          01
          V
          gg
            v^

          *0 C
          H-3
          °-g
                        gg
                  gg    gg    gg     gg     gg     gg
                        00    00    00     00     00     00     00     00
                                                         »«*(
                                                         >*»-
                                                           XX
                                                           MO
in in in  co F-to  (MOtvi  4~f-O
•-»•«-  OOO  (MIMCM  CO CO CO
                                                       ui-
                   ico   mo-*  «—
                R3JR-   <><>   535   OOO

                                                               222   222
            «-  coo eo  romio  COCKCO   O«M«-   ~J-NO~»
            •O  «o^to  «-«-T-  in in in   in in in   »-«-«-
            <£  «4«-^  v?«-!v?  «4«4v?   °H2   SSS
                        gg    gg    gg     gg     gg     gg     gg     gg
                        oo    oo    oo     oo     oo     oo     oo     oo
g$$  §;
in in in  co <
                o<
        pjoj<\i   
                      in in in  -a-a*
                      m S m  * "* *
                                      -*vt^l-   000   NCMC
                                         sss
                                               ^^-^   CMCMCVI   «»«*^

                                         %
                                                                         CD ID     O) CO
ne
is
is
Base
Zero
Zero
"5
0>
1 D>
C.
to
f
u
(0
o
•5 "5
as
a ID
•g-g
OJ IB 01
•^ O O
o o
s§
ra a
•g-g
ftl 01 «0
— O O
o o
1?
a a
•g-g
V V> V>
"- OO
o o
as
IS <0
•g-g
O 
•— O O
O 0
!»§
m a
•g-g
»_«_»
— 'o o
o o
0) 0)
0,0,
a a
•g-g
t> 10 IB
— QQ
O O
01 «l
o> a>
L. C_
a a
C.M.'*
•^ o o
                                                                                                                  8!
                                                                                                                   u
                                                                                                                   0)
Ze
Ze
Base
Zero
Zero
Base
Zero
Zero
Base
Zero
Zero
Base
Zero
Zero
Base
Zero
Zero
                                                       OJCMCM   SfXTsf  OOO  CO CO CO
                                       •»•*•»   sOvO-O   <-*-•-   CMCMIM  -J-N*%±  in in in
                                                                                          a>
                                                                                          u
                       3 33
                       tataa
         333
         <9 <9 <9
333
13 O Q
333  333
333
m ta CO
333
                                                 7-29
-------
S   3
°«
s|
82
i-0.
4J UI
u o
3 co
•gt.
  s
  ca

sg
             XX
             00
gg
oo
         gg    gg    gg
                                                 XX
                                                 00
                                                                 g
             XX
             
                                                 O3
                                                              cor- in
                                                              in to in
                                        OOO   W-«P-^-  OO OO 00  «-r*<^
                                        555   sss  sss  333
             XX
                                        KRR  SCS8   S5fe

                                                  WWW  SJ5J4J
             oo    oo    oo    oo    oo    oo
                                                       N-ooo
                                                       (MKIIM
                          CO *•• o  "^ ^ in  in N> in
                          N-eoS-  MKjio  «>a>c°

           MMIO  Mcxira   CXIMOJ  Nruru  Ji^^   ^11^  1^1^^
           5Sl»  *»55   SJ»5  5S*>  «5«   «*4*M  *»«»*»
                            gg    gg    gg    gg    gg    gg
             oo     oo    oo    oo    oo    oo
                                                       CO CO CO

                                                       ooo
                          SS8  SSS  8:8:8:   22S
                          CM CM CM  ^K c^ o^  m in in   (^ fo PO
                          OOO  
                     ca ca

                     'S'S
             II
              to co
           7 o o
            B U L.
              51) «
              NN
o» 

                                         £SS  •-
                                           11
                                                         'S'S     0*8
                                                         o o

                                                         01 01
                                           a a

                                          •g-g
                                                                                              SI
                                  01 O O
                                 . 00 C. t.
                                  ea «i u>
                                 0>NN
                                                » o o
                                                10 t- L.
                                                ca « u
                                                mNN
— oo

122
                                    01 O O

                                    Sfefc
                                    CO NN
>— O O

S22
co o> 0)
CD NN
                                                        OOO  CO CO OO
                                                        sr?<»  in in in
            3SS
                                  333
                                 (9 C9 (9
                                         C3 C3 C3  O O C9   C3 C9 C9
                                                               C9 U O
                                                                               g
                                                                               ca
                                    7-30
-------
   8£   i

   £M   £

   o!   i

   gg   |


   ||   g

(M  Z-J   >
I  O 111

ui  sx   u!


I  ii   i
i—  a. CQ   a.
o +>

«_3
4-*


I!
S£
              g
              CD
              v


            Is
            »— **

            tl
            g    g
             •     •
            o    o




          •»*»  mm
                                  g
                                  o
            X.


            o
                             X


                             o
                      X
          m(M  -------
    ^s   °
    O ui   i
»
I   2l
              !g
                          00


                          OO
         gg
         OO
                                         XX
                                         00
                                                        gg
                                                                00    00


                                                                OO    OO
                                                                      {GIG."
                            «-    100
                                                 XX
                                                 100
                         u,-ju.  «»ro>*   «-«-«-  »-o«-   rororo  cMtMcvi   N.N.K
                         ss§  (M(M(\j   JOSH  was   KiMiM  JQSQKS   sss
                         ooo  ooo   ooo  ooo   ooo  ooo   ooo
                            SX    XX    XX    XX    XX    XX     XX
                            *$•    m*—    ** *~    m^    roo    roo     roo
                                               I
                                                       rjcoo    CO CO 03   ^O *O *O  ^O^O^O   ^O ^O *O

                         cupjcvi  5jfj;   JfSvJ  «*«»«»   5»S5  «A«AM   <*MM
                           OC3

                           oca
                                  gg
                                          XX
                                          00
                        gg
gg
                        gg
         gg
         00
                         «-»->~  CMCMCM
                         OOO
                         flMM
                                        III
                         in in in
        »-»-•-  CM CM CM   ^-«-«-
        000  ininig   ^^^
                                                       5S5
                         «-«-T-  ^»4"^



                           ^%      ^^
                           x      a:
                                        
                                   C- U



                                  II
                                 Ol CO CO
                                 CO Q) U

                                 CD N M
  o o

  01 Ol

  s?s
  O ID

  •g-g
Ol CO CO

.555

ooo
09 C. t.
CO Ol 01
CD, N N
                                                 tn tn

                                                 •s-s
01 Ol

L. L.
CO CO
01 CO CO
••" O O
Ol 01
O) Ol
t_ L.
a -------
s
O u
o: <
0.0.
o


o uj
  _
  Sill

-8
_i en

O CO







































































ALASKA



o
O 4J

L. ^
6) l»
>- O.


0)
4J
a
"c
•sis
C 4-*
fl" ^
«-*
C *•
£ o


s

CD

i

~
L.O
*• «•?.

u
3
U
g
4_t ni
u o
o t.
Qu O.



to
"
4-*
|g
t. <~

u a.


ui
m
.
S g

C-S
° e














en
1
u
X

CO
a
0


c
ID
fi
CJ
X

a

a



w
.c
u

X

CO
CO
o
at

5
X
.
CD
CO
a
0)
CO
g
X

CO
a
o



fl)
CO
g
X


CO
CO
o








o
o
c

in

u
SI
o
L
a.
g
0


o o
M fO



X
,
o
1


•*»*

«~ «~
oo


X
CM
d
1



' Sco

5|*

X
d


mm

8$

g
O


<><>
OJCM



•
g
d


00 CO
53

^1 ftj
«™ «~

CIS
CD
CA
•5
0)
D>
C9
JE
Q
g.2
••- o
a> o
CO t-

(9 C9
1. C.
O O
H-M-
cu at
m m
g
d


co co
CM CM



X
,
o
1


in in

CM CM
OO


X
*^-
d



STCM
feJS

as
ss
X
d


M-*

sa

g
O


ss
. »-.-
MM



g
d


IO K>
ss

ss
"I"!

«o«o
"S
(S
in
"o
a
a
ts
JC
«u tn
n- O
t) O
CO t.
CD «l
aiM
a. a.
Beaufort
Beaufort
g
d


o o
M Kl



X
B
0
I


OO

into
oo


X

d
i



II

fefe
as
jj
d


«oo>

22

X
o


CM CM
CM CM
toio
MM



g
O


§K1
g

gg

«0«
?
CD

M-
O
0)
D)
ID
.C

!3°
41 O
CO <-

W«J
c c
11
u u
g
d


o o
M PO



X
,
0
1


CM»-
min

oo


i*
CM
0
i



CM 00

££
MM
X
0


^JJ

«»«»

g
d


33
CM CM
MM



g
O


oo co
55

KK

R"R"
1
in
•s
ej
O)
S
g.»
M-O

CO U
CD O
CON

CJC
g
d


h-N.
CMCM



X
,
0



^ ^.

CM CM
OO


X

d
i



m S>
coin

88

X
d


oo

S«J

g
d


Si CM
i-.-
MM



g
O


^ ^
mm

oo

««0
1
-------
       H-C ;
       o S i


       23:
       a 5 i
       1>*O I
       >- O i
             a

             tt
                              gggggggggg    2 	

                              o o o o o o o o o o    *—«— o o o o ^ o o o

                              I  I I I  I 1  I I  I  I    t  '        *



                            ooooO'OOsoooo  o*cocoo»o*^o»coo*o*o u) i Mco-*MK5  55&!2l5lSlS5s5a5S5s5S  «-MCM^^^^CM«^^;^;
                    ^ V* ^- T- «— w— «— T- «~ «—  J OJ CNJ CM CM OJ   (O K? O O O O rO O O O

                                       	I  i  I i     II        I
tn
a
G- ;
O—• i
  80 I
  4^ I

£:3:


  s:^
                             «»
                                     «||SS88888
                                                        CM'CM'CM'CM'CM CM CM CM CM CM CM

  s:
  4-* I

  li

  g!
          Ill-
          O. I U
                  OOOCMCMCMCMN-^-OO

                  *»
                            g



                         e  1
                         T  S
                         o  z
                          B
                    *    gg
                    •^ge  i-«z

                                                                   O COCMCM
                                                                   PJ 85«- «~
                                                                   in    ~
   .1
   u

{?  s     ]


I  1     i
g""  a     .,
   cc   z i
K       O <
   >>z  S;
a  3 o z g

°!'N'7oPo'

    B


B   S

'i  I
                                                               o
                                                                » 111 LU U I—
                              }Eg2    _.	._.

             £    f-£2ci!*'v'*'%'uiii4ujui   ci22s'>^*^^'ujujuii—  .— xpminininSSL.




                  Illsssgiiii   illssssiiii  ilis-assf*   "

                                                          U)
      o
      L.
      a.
                                     M- CO
                                     —• CD


                                     3°
                                         7-34
-------
and workover fluids, and produced sand. It is therefore more likely to show impacts. The Gulf
6 gas-only was the only project to show an early closure due to increased costs of treatment and
workover fluids. As a small gas-only project, it bears costs for produced water and treatment and
workover fluids. The Gulf 12 oil and gas model is considered representative of a "typical" Gulf
project. The projects bear costs for  produced water and produced sand. These costs for zero
discharge of NORM sand and treatment and workover fluids are included in every model run as
appropriate, and the costs are varied for the method of produced water disposal.

       Change in some financial statistics is on a continuous scale,  e.g., NPV, corporate cost per
BOE, and production cost per BOE. Change in two other statistics, years of production and,
therefore present value of total production,  is on  a discrete scale. A project either operates in a
given year, or it shuts down.  In examining Table  7-25, there is no greater loss of production seen
for projects bearing the costs of zero discharge for treatment and workover fluids and produced
sand, than is associated with the costs for a  given produced water option.  For example, all
produced water options cause the Gulf 6 gas-only model to have a 9-year lifetime  (i.e., it shuts
down one year early, see Table 7-10).  The costs for zero discharge of treatment and workover
fluids also cause the Gulf 6 gas-only project to  shut one year early (see Table 7-18).  The
combination of these costs, however, does not lead to the project shutting down two years early.
That is, loss of production estimates are not additive due to the discrete nature of measuring the
impact.

       For the parameters where the changes can measured in a continuous manner, the
impacts appear to be additive.  For example, the  baseline NPV for the Gulf Ib project is $939
(thousand).  The costs for offshore IGF lead to a $367 (thousand, 1986 dollars) decline in the
NPV (see Table 7-11). The zero discharge of treatment and workover fluids leads to a $3
(thousand, 1986 dollars) decline in the NPV (see Table 7-18). The zero discharge of NORM
produced sand leads to a $5 (thousand, 1986 dollars) decline in the NPV (see Table 7-21), for a
total of $375 (thousand, 1986 dollars). The NPV for these options combined is $566 (thousand,
1986 dollars).  This is a decline of $373 (thousand, 1986 dollars),  i.e., additive within rounding.

       For an existing single-well structure in the Gulf of Mexico with its own production
equipment (Gulf-lb), but needing new floatation  equipment, the combined effects of the selected
                                           7-35
-------
 options for produced water, treatment and workover fluids, and produced sand is expected to
 reduce the net present value by 40 percent and increase the corporate cost per barrel-of-oil
 equivalent (BOE) by 28 percent.  (This model project is considered indicative of offshore
 projects most sensitive economically because its source of revenue is a single producing well.
 Most offshore platforms produce  hydrocarbons from multiple wells.) For a Gulf of Mexico
 project comprising 12 well slots and 10 producing wells, the same requirements lead to a four
 percent decline in net present value and increase of three percent for the corporate cost  per
 BOE. (This  model, termed  Gulf 12, is considered representative of a typical offshore platform.)
 There were no production losses beyond those already seen with the produced water option.

        Similar patterns are seen  in Table 7-26 for NSPS projects. For the IRR, NPV, corporate
 cost per BOE, and production cost per BOE, impacts from the combined costs may be estimated
 by adding the impacts see when each effluent  is  analyzed separately. The added costs are
 sufficient to change the sign of the NPV from positive to negative for the Gulf Ib oil and gas
 project when it must add IGF equipment. The NPV remained positive when the project  had to
 bear only the costs of produced water control. This change has been incorporated in the
 estimation  of the potential loss in production under the regulatory packages (see Table 9-3). For
 years of production and present value of total production, the additional costs of zero discharge
 for treatment/workover/completion fluids, produced sand, and drilling wastes, do not lead to
 additional losses in production beyond that seen for any given .produced water option.

       For a Gulf-lb project, the combined costs lead to a 2 to 5 percent increase in the
 corporate cost of production, depending on whether new equipment is needed. If new
 equipment  is needed, the new present value becomes negative. These projects are assumed to be
 canceled and production is lost.  If new equipment is not needed, the net present value for the
 project remains positive, but with a 65 percent decline in value from the baseline. For a more
 typical Gulf-12 project, the same requirements lead to decrease in net present value of 5  to 6
 percent, and an increased corporate cost of 1 to  1.5 percent per BOE.
       In the real world, there will be projects that fall between the BAT and NSPS models,
e.g., platforms that are installed prior to promulgation but complete part of their drilling
program after this rule is issued. These platforms are much closer to the beginning of their

                                          7-36
-------
CO
o
§

I
Q.
CO

0
§
a.

a:

S

co
z
o co
 i°
 Q I—
 U U
  iui   S
 O CO   U.
        .
 a. a.   _i

 zS   a

          c
          o


          tis

          o i_

          £8.
          ac
>2

c °"
  g--
  Q)
0) V
<- o
a. t-


  m



  I
  _  S


  *o  o ** ^*
S                       t>
                           > oo   *-
                      ooooo   o   ooo   ooooo
                        SSSS     88S8
                                                VIII
            st-cocof««
                                     ~~        O K><
                      in ** in in in
                                  intriinmin

                                  aotototota  oToToTo^»
            ooror-co   o^-h-h-eo   o»-h-
S!
              41    •§    41    -S    81    -D
                    ?a    ra    o    o>    a
                  ^% Cv    b  ^S K»    LB  ^^ I—


              "  "    "glf  ;isl*
                                                                                                                 S!
            •i— O 10 O O  • v o (Q O O  ••— O Q O O

            —   uKSeO  --"U«MCO  -*«-CMOO
            ttl O -M      (U O ^      fll O *^
            (A t_—* U. U.  tA C_ *^ U. U. . CA G-•>« U. U.

            (D O *^ U C3  O 4) •«•• C9 CD  CO (U *<~ C9 U
            CO N U. *-• —  CO |sj U. « »  COMU.*—<->
            M- —'        *l- 0)


            "DO        "53
            C9          C3
                                                     7-37
-------
economic life than to their midpoint but not all wells on the platform will have been drilled
under the new BAT requirements. For these platforms, the per-project impacts are estimated to
be equal to or less than the BAT per-project impacts, depending upon the number of wells
drilled under the new requirements.
                                         7-38
-------
                                 SECTION EIGHT
                IMPACTS ON REPRESENTATIVE COMPANIES
       This section evaluates the financial impact of BAT effluent guidelines and NSPS
standards on representative companies in the offshore oil and gas industry. Impacts are
examined in terms of several financial ratios for two entities: 1) for a "typical" major oil company,
and 2) for 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 the regulations are presented in Section Six of this report. The balance sheets
and costs were developed in terms of 1986 dollars. The focus of the economic impact analysis is
the change from the baseline value for the financial ratios caused by the incremental pollution
control costs, rather than the baseline values themselves. For this reason, neither the costs nor
the components were inflated to 1991 dollars for the company-level impact analysis.
8.1     METHODOLOGY

       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 markets and not domestic costs, the Agency assumes no increase in oil price to offset
the costs of compliance.

       In order to estimate the potential impacts on the representative companies, it is necessary
to determine the portion of the regulation's costs that will be borne by the individual companies.
Companies in the offshore oil and gas industry have been characterized using two model
companies. The typical major oil company represents the large integrated oil companies such as
Exxon and Mobil, which operate in many facets of the oil  and gas industry.  The typical
independent oil company represents the smaller nonintegrated oil producer who is typically
involved in only the upstream or production segment of the industry. The March 1991 EIA
                                          8-1
-------
allocated the costs oi: regulation to a typical independent and typical major oil company based
upon expenditures on exploration and development.  For instance, according to the 1986 API
Survey on Oil & Gas Expenditures, a typical major oil company accounted for approximately
2.77 percent of total offshore expenditures on exploration and development in 1986.  It was
assumed, therefore, that a typical major oil company would likely bear 2.77 percent of the total
incremental pollution control cost of the regulation.  The March 1991 EIA included the costs of
regulation on drilling fluids and drill cuttings,  effluents generated only in the exploration and
development stages. Since produced water is the largest component of the total regulatory costs,
EPA reassessed the apportionment of costs among typical major and independent oil companies.
(Expenditures on exploration and development may not directly relate to the volumes of
produced water generated.)

       Table 8-1  displays a listing from the Minerals Management Service (MMS,  1990) of the
top 98 oil producers in the Federal Outer Continental Shelf (OCS) region in 1989, ranked
according to volumes of oil produced.  Although the offshore category of the oil and gas industry
includes operators in both state and federal waters, 90 percent of the BAT or existing structures
expected to incur additional costs are in federal waters (see Section Four). The OCS distribution
was, therefore, used to estimate what portion of incremental costs would be borne  by both a
typical major oil company and a typical independent oil company.  Of these 98 operators, 92
represent unique  corporations (6 of the entries represent subsidiaries of previously listed
companies).  The allocation between major and independent operators was determined according
to company listings in the PennWell Oil and Gas  Directory (PennWell, 1991).  Companies that
were involved in multiple facets of the oil and gas industry are listed as majors (i.e., exploration,
production, refining, marketing, etc.).  Conversely companies involved in only upstream activities
are listed as independent operators (i.e., only exploration, development, or production). Several
of the operators listed in Table 8-1 were not listed in the PennWell directory, but were
considered to be independents.

      There is generally an overall strong correlation between the volume of oil produced and
the volume of produced water generated. Furthermore, the volume of produced water that an
operator generates will have a direct effect upon the cost of complying with these regulations.
Accordingly, the distribution of operators in the OCS region was used to estimate the proportion

                                           8-2
-------
                                         TABLE 8-1
         Oil Production, Reported in Barrels for 98 Ranking OCS Operators in 1989
Gulf of Mexico
OCS Operators
1. Chevron USA Inc.
2. Shell Offshore Inc.
3. Exxon Corp.
4. Conoco Inc.
5. Mobil Oil E & P
6. Union Oil Company of California
7. Marathon Oil Company
8. Texaco Inc.
9. Union Exploration Partners Ltd.
10. Mobil Producing Texas & New Mexico Inc.
11. Atlantic Richfield Company
12. Pennzoil E & P
13. BP Exploration Inc.
14. Odeco Oil and Gas Company
15. Amoco Production Company
16. CNG Producing Company
17. Placid Oil Company
18. Kerr-McGee Corporation
19. Oryx Energy Company
20. FMP Operating Company
21. Phillips Petroleum Company
22. Hf Aquitaine Operating Inc.
23. McMoran Oil & Gas Company
24. Sandefer Offshore Operating
25. TXP Operating Company
26. Apache Corp.
27. Sonat Exploration Company
28. Union Texas Petroleum Corp.
29. Howell Petroleum Corp.
30. Anadarko Petroleum Corp.
31. Taylor Energy Company
32. Mesa Operating Limited Partners
33. OXY USA Inc.
.34. Hall-Houston Oil Company
35. Forest Oil Corp.
36. Walter Oil & Gas Corp.
37. Tenneco Oil Company
38. Great Western Offshore Inc.
39. Hunt Oil Company
40. Nerco Oil & Gas Inc.
41. Amerada Hess Corp.
42. W&T Off shore Inc.
43. Alliance Operating Corp.
44. Mesa Petroleum Company
45. Huges Eastern Petroleum Inc.
46. Total Minatome Corp.
47. Samedan Oil Corp.
48. Canadianoxy Offshore Production
49. Texaco Producing Inc.
50. Corpus Christ! Oil and Gas Company
51. Columbia Gas Development Corp.
52. Elf Aquitaine Inc.
53. Union Pacific Resources Company
54. Pelto Oil Company
55. Santa Fe International Corp.
Subtotal (Continued next page)
Crude Oil
46,940,619
33,098,609
28,955,890
19,950,976
13,986,816
—
15,330,957
11,531,572
8,395,658
6,768,049
6,080,446
7,118,244
6,578,987
5,950,762
2,549,065
1,591,267
3,670,020
3,213,933
1,475,006
1,986,247
1,133,814
1,714,524
1,470,503
790,204
654,444
982,024
655,518
169,305
741,874
588,269
228,716
306,358
172,921
—
391,359
318,118
399,099
—
140,425
_
47,407
248,158
197,337
199,682
152,459
83,913
33,210
122,627
—
—
—
219
61,018
5,112
—
237,181,740
Condensct*
5.044,315
3,885,357
1,484,025
2.918,273
3,848,415
214
629,724
1,099,796
1,957,459
2,045,475
2.061,976
868,847
367,051
769,832
2,812^78
3.177,834
1,059,972
324,107
199.889
187.684
318,703
108,751 -
62,203
598,193
561,193
15,079
320,697
668,947
_
60,761
366,101
225,678
345,146
497,300
76,870
142,841
53,524
290,814
145,966
272,401
214,666
457
45,712
35,894
55,812
118,425
155.001
43,909
153.911
146,521
140.121.
139,645
61,422
106,502
106.005
41,397,712
Pacific*
Crude Oil &
Condartut*
2,964,957
5,065,058
9,519,054
_
w
13,117,209
—
9,784
_
_
—
_
_
_ .
«.
_
_
_
1,781,111
_
625,630

_
_
—
_
_
—
_
_
_
_
_
_
_
«.
_
_
_
_
«
_
_
_
_
_
_
_
_
—
_
_
'_
a.
_
33,082,803
Field
Volumes
Inbbl
54,949,891
42.049,024
39.958,970
22,869.249
17,835.231
13.117,423
15560,681
12,641,152
10.353,117
8.813,524
8,142,422
7,987,091
6,946,038
6,720.594
5,361,343
4,769,101
4,729.992
3,538,040
3,456,006
2,173.931
2,078,147
1,823,275
1.532,711
1,388,402
1,215,640
997,103
976,215
838,252
741,874
649,030
594,817
532,036
518,067
497,300
468,229
' 460,959
452,623
290,814
286,391
272.401
262,073
248,615
243,049
235,576
208,271
202,338
188,211
166,536
153,911
146.521
140.125
139,864
122,440
111.614
106.005
311,662,255
Source:  MMS, 1990.
                                          8-3
-------
                                  TABLE 8-1 (continued)
         Oil Production, Reported in Barrels for 98 Ranking OCS Operators in 1989



Gulf of Mexico
OCS Operators
56. Gas Transporation Corp.
57. Coastal Oil & Gas Corp.
58. Century Offshore Management
59. Diamond Shamrock Offshore Partners
60. Zapata Exploration Company
61. Quintana Petroloum Corp.
62. fvory Production Company
63. Enron Oil & Gas Company
64. Kirby Exploration Company Offshore
65. General Atlantic Energy Corp.
66. Brooklyn Union Exploration Company
67. Mitchell Energy Corp.
68. Mark Producing Inc.
69. Cockrell Oil Cop.
70. Conquest Exploration Company
71. Cliffs Oil and Gsa Company
72. Louisiana Land and Exploration
73. Houston Oil & Minerals Corp.
74. Getty Oil Company
75. Seagull Energy E&P Inc.
76. Koch Exploration Company
77. Gulfstar Operating Company
78. Felmont Oil Cop.
79. Mob!) Oil Corp.
80. Total Petroleum Inc.
81. Matagorda Island Development
82. Cashco Energy Corp.
83. Stone Petroleum Corp.
84. Ashland Exploration Inc.
85. ANR Production Company '
86. Southland Royalty Company
87. Flash Gas & Oil Southwest
88. Felmont Oil & Gas Company
80. PSI Inc.
go. Gulf Oil Corp.
91. DKM Offshore Energy Inc.
82. Offshore Energy Development
S3. Wayman W. Buchanan Inc.
94. Wacker Oil Inc.
65. B T Operating Company
96. Falcon Offshore Operating Company
97. Petrofina Delaware Inc.
98. Norcen Explorer Inc.
Field Total*
Crude Oil
94.596
93,173
2,911
—
—
17,008
46,793
—
39,792
34,824
—
38,778
18.371
—
14,117
—
—
11.873
—
—
—
— ,
—
4.852
7.595
—
_.
—
—
—
—
—
—
—
—
1,690
—
—
—
—
,_.
—
_
237,608,113
Condensat*
9,694
—
83,586
71,739
59,740
38,356
1,373
47,549
3,546
7,862
39,332
91
20,409
38,141
22,789
34,158
33,766
20.415
32,049
27,793
25,729
13,683
13,661
3,599
—
5,876
5,585
5,282
4,934
4,631
4,340
4,006
3,497
2959
1855
—
1,448
1,337
198
53
26
22
13
42,092,834
Pacific*
Crude Oil &
Condensate
_
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— .
—
—
—
—
—
—
—
—
—
—
•. —
33,082,803
Field
Volumes
Inbbl
104,290
93,173
86,497
71,739
59,740
55,364
48.166
47,549
43,338
42,686
39,332
38,869
38,780
38,141
36,906
34,158
33,766
32,288
32,049
27.793
25,729
13,683
13,661
8.451
7,595
5,876
5.585
5,282
4,934
4,631
4,340
4,006
3.497
2,959
1,855
1,690
1,448
1,337
198
53
26
22
13
312,783,750
LM\ 1 L. T)w vcJuflMA fMfV M tilGMA rrijtjrMjJ In 1t|A fMd aA ttl* WBfltlAAd flOt 1lW AdjtlSMd fifUj production fiQUm UlCt
tt>« eo*o*on raced and on wWeii (MM** p«y nyalti** to tht F*d*nl Gommmcnl.
Source: MMS, 1990.
                                          8-4
-------
of regulatory cost to be borne by typical companies in the offshore industry. Table 8-2
summarizes the OCS operators according to oil production quantities and to whether or not they
are integrated companies.  Note that the 29 majors represented approximately 90 percent of all
oil production from the OCS.1 This distribution was used to estimate that a typical major would
likely bear 3.1 percent of any additional pollution control costs (90 percent divided by 29).2
Similarly, since the 63 independent operators accounted for roughly 10 percent of OCS oil
production, it was assumed that a typical independent producer would bear 0.15 percent of the
costs of regulation.

       The typical companies are assumed to raise the funds necessary for compliance through
two financing alternatives:

       •      All expenditures are financed by long-term  debt.
       •      All expenditures are financed by working capital.

The potential impacts that result from the increase in pollution control expenditures are
estimated by examining the balance sheets of the typical major and independent before and after
the 3.1 and 0.15 percent portion of the costs have been borne.  The balance sheets used to
represent the two typical companies are developed in Section Three of the March 1991 EIA.
The impacts are gauged in terms of four financial statistics:
              Working Capital; The amount of liquid assets that are available to finance day-to-
              day operations.
    1MMS, 1990 gives a similar breakdown of gas producers in the OCS region. This breakdown
includes most of the same operators, but indicates that the independent producers play a larger role
in gas production than in oil production.  Since the generation of produced water is greater with oil
production than gas production, we are using the offshore oil producers' distribution to allocate costs
to "typical" companies.
    2Data from MMS, 1991 show 28 major oil companies operating in the Federal offshore region.
These 28 companies account for 90 percent of the oil production. The updated information results
in a  typical major bearing 3.2 percent  of the cost of the regulation; a change that would not
significantly affect the results presented in this section.

                                            8-5
-------
TABLE 8-2
OIL PRODUCERS IN THE DCS REGION
Type of Number of Percent of Oil Production Percent of Per Company
Operator ' Companies Total (Millions of BBLS) Total Share of Costs
Major (Integrated) 29 32%
Independent (Non-Integrated) 63 68%
Total: 92
283.0 90% 3.12%
30.0 10% 0.15%
313.0
Source:  HHS, 1990.
            28-Oct-92
DCS PRD.WK3
                                               8-6
-------
              Current Ratio;  The ratio of current assets to current liabilities.  This provides an
              indication of a company's ability to honor short-term obligations.
              Long-term Debt to Equity Ratio:  This ratio provides a measure of a company's
              leverage: the proportion of debt being used to finance a company's assets.
              Debt to Capital; An additional measure of a company's debt level or leverage.3
8.2    DRILLING FLUIDS AND DRILL CUTTINGS

       Table 8-3 presents the average annual cost for the four options for the control of drilling
wastes.  The annual cost ranges from $19 million to $148 million in 1986 dollars. A typical major
is expected to bear 3.1 percent of the total cost, resulting in incremental costs to the company
ranging from $0.59 million for the 3-Mile Gulf/California option to $4.61 million for the Zero
Discharge Gulf/California option. A typical independent would bear approximately 0.15 percent
of the total cost of an option. This translates into incremental costs of $0.03 million to $0.23
million for the same options.

       Table 8-4 illustrates the balance sheet for a typical major and how it would change if the
costs for each option were borne entirely out of working capital.  Table 8-5 shows the balance
sheet and how it would change if the costs were financed entirely by long-term debt. These two .
tables form the basis for the  derivation of the change in financial ratios for a typical major
caused by the increased cost  of incremental pollution control for drilling wastes (Table 8-6).
These costs cause  only small discernable  changes in the long-term-debt to equity and the debt-to-
capital ratios (<= 0.1 percent);  ratios affected by financing through long-term debt. These costs
lead to small (<= 0.1 percent) changes in the ratios affects by financing through working capital
except for the Zero Discharge Gulf/California option.  Here working capital declines by 0.6
percent.
    3The debt to capital ratio used in this analysis is calculated as the book value of long-term debt
divided by the sum of stockholder equity and current liabilities.

                                            8-7
-------
TABLE 8-3

ANNUAL COST OF POLLUTION CONTROL OPTIONS
DRILLING FLUIDS AND DRILL CUTTINGS
MILLIONS OF DOLLARS, 1986 DOLLARS
Option
1
2
3
4
Cost Scenario
3 Mile GUlf/ CA
8 Kile Gulf/ 3 Mile CA
Zero Discharge Gulf/ CA
4 Mile Gulf/ CA
Annuali zed
Cost
Of Option
$19
$33
S148
$21
Typical Typical
Major Independent
Portion Portion
$0.59
$1.03
$4.61
$0.66
$0.03
$0.05
$0.23
$0.03
Notes:   Projects in Alaska are exempt from the barging requirement,  however must  comply
         with the requirements for clean barite, toxicity, and static sheen.

Source:  EPA estimates.
KSC SHRE
21-Dec-92
                                                  8-8
-------
TABLE 8-4

EFFLUENT GUIDELINES IMPACTS ON TYPICAL MAJOR OIL COMPANY
COMPLIANCE COSTS FINANCED BY WORKING CAPITAL
DRILLING FLUIDS AND DRILL CUTTINGS

Parameters
Regulatory Cost borne by Major
Assets
Current Assets
Property, Plant and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
Long- terra Debt
Other Liabilities (a)
Total Liabilities
Shareholders' Equity
Total Liabilities
and Net Worth

1986
Dollars

$8,337
$24,799
$2,758
$35,894
$7,536
$5,443
$7,600
$20,579
$15,315
$35,894

8 Mile
3 Mile Gulf/ CA 3 Mile
$0.59
$8,336
$24,799
$2,758
$35,893
$7,536
$5,443
$7,600
$20,579
$15,314
$35,893

Gulf/
CA
$1.03
$8,336
$24.799
$2,758
$35,893
$7,536
$5,443
$7,600
$20,579
$15,314
$35,893
Regulatory Option
Zero Discharge
Gulf/ CA 4
$4.61
$8,332
$24,799
$2,758
$35,889
$7,536
$5,443
$7,600
$20,579
$15,310
$35,889

Mile Gulf/ CA
$0.66
$8,336
$24,799
$2,758
$35,893
$7,536
$5,443
$7,600
$20,579
$15,314
$35,893
Note:(a) Other liabilities include: deferred Federal and foreign income taxes, deferred
         revenue, production payments, and other medium-term commitments.
     (b) All values in Millions of dollars.
Source:  EPA estimates.
 M&C MAJ.WK3
                     21-Dec-92
8-9
-------
 TABLE 8-5

 EFFLUENT GUIDELINES IMPACTS ON TYPICAL MAJOR OIL COMPANY
 COMPLIANCE COSTS FINANCED  BY LONG-TERM DEBT
 DRILLING FLUIDS AND DRILL  CUTTINGS

Parameters
Regulatory Cost borne by Major
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 Worth

1986
Dollars

$8,337
$24,799
$2,758
$35,894
$7,536
$5,443
$7,600
$20,579
$15,315
$35,894

8 Mile
3 Nile Gulf/ CA 3 Mile
$0.59
$8,337
$24,799
$2,758
$35,894
$7,536
$5,444
$7,600
$20,580
$15,314
$35,894

Gulf/
CA
$1.03
$8,337
$24,799
$2,758
$35,894
$7,536
$5,444
$7,600
$20,580
$15,314
$35,894
Regulatory Option
Zero Discharge
Gulf/ CA 4
$4.61
$8,337
$24,799
$2,758
$35,894
$7,536
$5,448
$7,600
$20,584
$15,310
$35,894

Mile Gulf/ CA
$0.66
$8,337
$24,799
$2,758
$35,894
$7,536
$5,444
$7,600
$20,580
$15,314
$35,894
Hote:(a) Other  liabilities include: deferred Federal and foreign income taxes, deferred
         revenue, production payments, and other medium-term commitments.
     (b) All values in Millions of dollars.
Source:  EPA estimates.
WC HAJ.WK3
21-DCC-92
                                                              8-10
-------
TABLE 8-6

CHANGES  IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
DRILLING FLUIDS AND DRILL CUTTINGS
Working Capital (a)
Millions
Options
Baseline
3 Mile Gulf/ CA
8 Mile Gulf/ 3 Mile CA
Zero Discharge Gulf/ CA
4 Mile Gulf/ CA
Parameter
$801
$800
$800
$796
$800
Change

-0.1%
-0.1%
-0.6X
-0.1%
Current Ratio (a)
Parameter
1.11
1.11
1.11
1.11
1.11
Change

-0.01%
-0.01%
-0.06%
-0.01%
Long Term Debt/
Equity 
Parameter Change
35.5%
35.5%
35.5%
35.6%
35.5%

0.0%
0.0%
0.1%
0.0%
Debt/Capital
Ratio (b)
Parameter Change
23.8%
23.8%
23.8%
23.8%
23.8%

0.0%
0.0%
0.1%
0.0%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.

Source:  EPA estimates.
M&C MAJ.UK3
21-Dec-92
                                                            8-11
-------
       Tables 8-7 and 8-8 show the balance sheet for a typical independent.4  Table 8-7
illustrates the changes caused by funding the increased pollution control costs for drilling wastes
through working capital; Table 8-8 shows the changes when the costs are funded through long-
term debt. The impacts are summarized in Table 8-9. Working capital decreases by 5.4 percent
for the Zero Discharge Gulf/California option, and 1.2 percent or less for the other options. The
other financial ratios are less sensitive, none show a change greater than 0.5 percent for any of
the options.

8.3    PRODUCED WATER — BAT

       Table 8-10 presents the costs of compliance for the five BAT produced water control
options.  The first option, BPT All, has no incremental costs associated with it. It is not
discussed further in this section.  The annualized costs range from $39 million to $654 million in
1986 dollars for the other options. These costs are broken down into the approximate share of
the incremental costs  that would be borne by a typical major and a typical independent oil
company. A typical major is expected to bear 3.1 percent of the total incremental cost,  resulting
in total incremental costs to the company ranging from $1.2 for the Filter 4 Miles option to $3.0
million per year for Che Flotation All option to $20.3 million per year for the Zero Discharge
Gulf option.  The typical independent would bear approximately 0.15 percent of the total cost of
an option. This translates into incremental costs ranging from $0.06 million to $1.00 million for
the same options.

       Table 8-11 summarizes the potential impacts that the incremental costs would have on  a
typical major as measured by four financial statistics.  If the company were to finance all of the
incremental costs using working capital, it is estimated that the typical major's working capital
would decline by  no more than 2.5 percent. Similarly, the current ratio would decrease by less
than 0.3 percent under any of the options.  If the incremental costs were financed using long-
   4As mentioned in Section Three, it was not possible to update the income statement and balance
sheet for 1986 for independents because  of the  takeover of Inexco by  Louisiana  Land and
Exploration in mid-1986.  Dropping Inexco would have resulted  in  too few companies for
aggregation. The consumer price index was  used to inflate the 1985 balance sheet to 1986 dollars.

                                           8-12
-------
 TABLE 8-7

 EFFLUENT GUIDELINES IMPACTS  ON  TYPICAL  INDEPENDENT OIL COMPANY
 COMPLIANCE COSTS FINANCED  BY WORKING  CAPITAL
 DRILLING FLUIDS AND DRILL  CUTTINGS

Parameters
Regulatory Cost borne by Major
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 Worth

1986
Dollars

$55
$547
$3
$605
$51
$278
$112
$441
$165
$605

3 Mile Gulf/ CA
$0.03
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
REGULATORY (
8 Mile Gulf/
3 Mile CA
$0.05
$55
$547
S3
$605
$51
$278
• $112
$441
$165
$605
>PTION
Zero Discharge
Gulf/ CA 4
$0.23
$55
; $547
$3
$605
$51
$278
$112
$441
$165
$605

Mile Gulf/ CA
$0.03
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
Note:(a) Other liabilities include: deferred Federal and foreign income taxes, deferred
         revenue, production payments, and other medium-term commitments.
     (b) All values in Millions of dollars.
     (c) 1985 dollars inflated to 1986 dollars by 3.65X based oh change in Consumer Price Index.

Source:  EPA estimates.
                                                       8-13
m&c ind.wk3
21-Dec-92
-------
TABIE 8-8

EFFLUENT GUIDELINES IMPACTS ON TYPICAL INDEPENDENT OIL COMPANY
COMPLIANCE COSTS FINANCED BY LONG-TERM DEBT
DRILLING FLUIDS AND DRILL CUTTINGS
REGULATORY OPTION
Parameters
Regulatory Cost born Other liabilities include: deferred Federal and foreign income taxes,  deferred
         revenue, production payments, and other medium-term commitments.
     (b) All values fn Millions of dollars.
     (c) 1985 dollan: inflated to 1986 dollars by 3.65% based on change in Consumer Price Index.

Source:  EPA estimates.
                                                    8-14
                    St1-Dec-92
-------
TABLE 8-9

CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUEN
DRILLING FLUIDS AND DRILL CUTTINGS
Working Capital (a)
SMUlions
Options
Baseline
3 Mile Gulf/ CA
8 Mile Gulf/ 3 Mile CA
Zero Discharge Gulf/ CA
4 Mile Gulf/ CA
Parameter
$4
$4
$4
$4
$4
Change

-0.7%
.-1.2X
-5.4%
-0.8%
Current Ratio (a)
Parameter
1.08
1.08
1.08
1.08
1.08
Change

-0.05%
-0.09%
-0.41%
-0.06%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.

Source:  EPA estimates.
                                                      8-15
m&c ind.uk3
21-Dec-92
-------
TABLE 8-10
ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT PRODUCED WATER
MILLIONS OF DOLLARS, 1986 DOLLARS
Option #
Option
Annualized
      Cost
 Of Option
                                                        Typical        Typical
                                                          Major    Independent
                                                        Portion        Portion
    1    BPT All
    2    Flotation All
    3    Zero 3 Miles Gulf
    4    Zero Discharge Gulf
    5    Filter 4 Miles
                               $0
                              $96
                             $115
                             $654
                              $39
                   $0.00
                   $2.99
                   $3.58
                  $20.30
                   $1.20
$0.00
$0.15
$0.18
$1.00
$0.06
Source:  EPA estimates.
BAT SHFIE
             21-Dec-92
                                                8-16
-------
TABLE 8-11

CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT PRODUCED WATER
Working Capital (a)
Millions
Parameters
Baseline
Flotation All
Zero 3 Hiles Gulf
Zero Discharge Gulf
Filter 4 Hiles
Parameter
$801
$798
$797
$781
$800
Change

-0.4%
-0.4%
-2.5%
-0.1%
Current Ratio (a)
Parameter
1.11
1.11
1.11
1.10
1.11
Change

-0.04%
-0.04%
-0.24%
-0.01%
Long Term Debt/
Equity 
Parameter
35.5%
35.6%
35.6%
35.7%
35.6%
Change

0.1%
0.1%
0.5%
0.0%
Debt/Capital
Ratio (b)
Parameter
23.8%
23.8%
23.8%
23.9%
23.8%
Change

0.1%
0.1%
0.5%
0.0%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.

Source:  EPA estimates.
                                                     8-17
bat_maj.wk3
21-Dec-92
-------
term debt, we would see slight increases in the two leverage ratios (Long-term Debt/Equity and
Debt/Capital ratios) of no more than 0.5 percent under the Zero Discharge Gulf option.

       Table 8-12 displays the potential impacts that increased pollution control costs would
inflict upon the typical independent oil producer. If the company chose to finance the costs
through working capital, the available working capital would decline by 24 percent (from $4
million to $3 million)  under the Zero Discharge Gulf option.  Under this same option, the
current ratio drops from 1.08 to 1.06, a decline of 1.8 percent.  Under  the Flotation All option,
however, the decline in working capital is less than 4 percent, and the  decrease in the current
ratio is under 0.3 percent. If the typical independent raised the funds  required for compliance by
incurring long-term debt, the increase in the two leverage ratios would range from 0,1 percent to
1.0 percent for the Flotation All option and the Zero Discharge Gulf option, respectively.

8.4    PRODUCED WATER — NSPS

       Table 8-13 presents the costs of compliance for the five NSPS produced water control
options.  The first option, BPT All, has no incremental costs associated with it. It is not
discussed further in this section. The peak annualized costs range from $12 million to $347
million in 1986 dollars. This peak will occur in the 15th year of the regulation when the number
of new sources coming into production reach an equilibrium with those reaching the end of their
productive life.  These costs are broken down into the approximate share of the incremental
costs that would be borne by a typical major oil company and a typical independent. The typical
major's portion of the incremental costs ranges from $0.4 million for the Flotation All option to
$10.8 million for the Zero Discharge Gulf and Alaska option.  The typical independent would
bear incremental costs ranging from $0.02 million to $0.53 million for the same options.

       Table 8-14 summarizes the potential impacts that the incremental costs would have on a
typical major as measured by several financial statistics. If the company were to finance all of
the incremental costs using working capital, it is estimated that the working capital would decline
by no  more than 1.3 percent under any option.  The current ratio would decrease by less than 0.2
percent under any option.  If the incremental costs were financed using long-term debt, there
                                           8-18
-------
TABLE 8-12

CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT  GUIDELINES REGULATIONS
BAT PRODUCED WATER
                     , i
                      r
Working Capital (a)
Millions
Parameters
Baseline
Flotation All
Zero 3 Miles Gulf
Zero Discharge Gulf
Filter 4 Miles
Parameter
$4
$4
$4
$3
$4
Change

,-3.5%
-4.2%
-24.0%
-1.4%
Current Ratio (a)
Parameter
1.08
1.08
1.08
1.06
1.08
Change

-0.27%
-0.32%
-1.81%
-0.11%
Long Term Debt/
Equity 
Parameter
168.6%
168.8%
168.8%
170.2%
168.6%
Change

0.1%
0.2%
1.0%
0.1%
Debt/Capital
Ratio (b)
Parameter
128.8%
129.0%
129.0%
129.9X
128.9%
Change

0.1%
0.1%
0.8%
0.0%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.

Source:  EPA estimates.
                                                       8-19
bat  ind.wk3
21-Dec-92
-------
TABLE 8-13

ANNUAL COST OF POLLUTION CONTROL OPTIONS
NSPS PRODUCED WATER
MILLIONS OF DOLLARS, 1986 DOLLARS
Annual i zed
Option
Number
1
2
3
4
5
Coat
Option Of Option
BPT All
Flotation All
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
Filter 4 Miles
$0
$12
$62
$347
$16
Typical
Typical
Major Independent
Portion Portion
$0.00
$0.38
$1.92
$10.77
$0.50
$0.00
$0.02
$0.09
$0.53
$0.02
Source:  EPA estimates.
 NSPSSHRE
5!1-Dec-92
                                                  8-20
-------
TABLE 8-14

CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
NSPS PRODUCED WATER
Working Capital (a)
$H ill ions
Option
Basel ine
Flotation All
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
Filter 4 Miles
Parameter
$801
S801
$799
$790
$800
Change

•0.0%
-0.2%
-1.3X
-0.1X
Current Ratio (a)
Parameter
1.11
1.11
1.11
1.10
1.11
Change

-O.OOX
-0.02X
-0.13X
-0.01X
Long Term Debt/
Equity 
Parameter
35.5%
35. 5X
35.6%
35. 6X
35.5X
Change

O.OX
O.OX
0.3X
O.OX
Debt/Capital
Ratio (b)
Parameter
23. 8X
23.8%
23.8%
23.9%
23.8X
Change

O.OX
O.OX
0.2X
O.OX
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt'financing approach only.

Source:  EPA estimates.
                                                  8-21
nsps_maj.wk3
21-Dec-92
-------
would be a slight increases of 0.3 percent in the two leverage ratios under the Zero Discharge
Gulf and Alaska option.

       Table 8-15 displays the expected impacts that increased pollution control costs would
inflict upon the typical independent oil producer.  If the company chose to finance the costs
through working capital, the available working capital would by roughly 13 percent under the
Zero Discharge Gulf and Alaska option. Under this  same option, the current ratio drops from
1.08 to 1.07, a decline of 1 percent. Under the Flotation All option, however, the decline in
working capital is only 0.4 percent, and the decrease in the current ratio is less than 0.1 percent.
If the typical independent raised the funds required for compliance by incurring long-term debt,
there would be an increase in the two leverage ratios ranging from 0 percent to 0.5 percent for
the Hotation All option and the Zero Discharge Gulf and Alaska option, respectively.
8.5    TREATMENT, WORKOVER, AND COMPLETION FLUIDS

       Table 8-16 lists the annual estimated costs for the zero discharge of treatment, workover,
and completion fluids for BAT and NSPS projects. A typical major would bear approximately
$0.06 million while a typical independent would bear $0.003 million (i.e., $3,000 dollars). These
costs are small relative to those for the other effluents. The financial ratios show no change for
either the typical major (Table 8-17), and changes of 0.1 percent or less for the typical
independent (Table 8-18).
8.6    PRODUCED SAND

       The annual cost for produced sand disposal is presented in the Development Document
for this rulemaking.  The cost to a typical major is estimated to be $0.12 million while that for a
typical independent of estimated to be $0.01 million (Table 8-19). The changes in financial ratios
caused by these costs are very small and are comparable to those seen for the treatment,
workover, and completion fluid costs  (Table 8-20 and 8-21).
                                          8-22
-------
 TABIE 8-15
 CHANGES IN  FINANCIAL  RATIOS  FOR A TYPICAL  INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
 NSPS PRODUCED  UATER
                                Working Capital (a)
                                     Millions
                                                            Long Term Debt/
                                                               Equity (b)
Debt/Capital
 Ratio (b)
                                                        Current Ratio (a)
 Parameters                      Parameter    Change     Parameter  Change     Parameter  Change     Parameter  Change
 Baseline                               $4                   1.08                 168.6%
 Flotation All                          $4      -0.4%        1.08    -0.03%       168.6%     0.0%
 Zero 3 Miles Gulf and Alaska           $4      -2.3%        1.08    -0.17%       168.7%     0.1%
 Zero Discharge Gulf and Alaska         $4     -12.7%        1.07    -0.96%       169.4%     0.5%
 Filter 4 Miles                         $4      -0.6%        1.08    -0.04%       168.6%     0.0%
                                                                                  128.8%
                                                                                  128.9%
                                                                                  128.9%
                                                                                  129.4%
                                                                                  128.9%
          0.0%
          0.1%
          0.4%
          0.0%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.
Source:  EPA estimates.
                                                     8-23
nsps_ind.wk3
21-Dec-92
-------
TABLE 8-16

ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT AND NSPS TREATMENT, WORKOVER, AND COMPLETION  FLUIDS
MILLIONS OF DOLLARS, 1986 DOLLARS


Cost Scenario
Discharae with Additional Controls for:
BAT Treatment & Workover Fluids
NSPS Treatment & Uorkover Fluids
NSPS Completion Fluids
Total Annual Cost
Annuali zed
Cost
Of Option

$1.50
$0.35
$0.19
$2.04
• Typical
Major
Portion

$0.05
$0.01
$0.01
$0.06
Typical
Independent
Portion

$0.002
$0.001
$0.000
$0.003
Source:  EPA estimates.
 TUC SHRE
21-Dee-92
                                                 8-24
-------
TABLE 8-17

CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT AND NSPS TREATMENT, WORKOVER, AND COMPLETION FLUIDS            "                  .  ';
Parameters
Baseline
Oil and Grease Limits
• ' Working Capital (a)
Millions
Parameter Change
$801
$801 -0.0%
Long Term Debt/
Current Ratio (a) Equity (b)
Parameter Change Parameter Change
1.11 ' 35.5%
1.11 -O.OSS " 35.5% 0:6%
Debt/Capital
Ratio (b)
Parameter
23.8%
• '" 23.8%
Change

u 0.0%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.

Source:  EPA estimates.
                                                     8-25
twc_maj.wk3
21-DCC-92
-------
TABLE 8-18

CHANGES IM FINANCIAL RATIOS FOR. A TYPICAL INDEPENDENT AS A RESULT  OF  EFFLUENT GUIDELINES REGULATIONS
BAT AHD NSPS TREATMENT, WORKOVER, AND COMPLETION FLUIDS                    .
•-
Parameters
Baseline
Oil and Grease Limits
' Working Capital (a) ~ Long Term Debt/ Debt/Capital
SMillions Current Ratio (a) Equity (b) Ratio (b)
Parameter Change Parameter . Change .Parameter Change Parameter Change
$4 1.08 168.6% 128.8%
$4 -0.1% 1.08 , -0.0% . 168.6% 0.0% 128.8% 0.0%
Note:  (a) These ratios affected by working capital approach only.
       (b) These ratios affected by debt financing.approach only:

Source:  EPA estimates.
                                                     8-26
 twc ind.wk3
                     21-Dec-92
-------
 TABLE 8-19

 ANNUAL COST OF POLLUTION CONTROL OPTIONS
 BAT AND NSPS PRODUCED SAND
 MILLIONS OF DOLLARS, 1986 DOLLARS
 Cost Scenario
  Annualized
        Cost
   Of Option
Typical       Typical
  Major   Independent
Portion       Portion
 ZERO DISCHARGE
                                                            $4
                                                                      $0.12
                                                                                    $0.01
 Source:  EPA estimates.
sandSHRE
             21-Dec-92
8-27
-------
TABLE 8-20
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT AND NSPS PRODUCED SAND

Parameters
BASELINE
ZERO DISCHARGE
Working Capital (a)
Millions
Parameter, Change
$801
$801 -0.0%
Current Ratio (a)
Parameter Change
1.11
1.11 -0.00%
Long Term Debt/
Equity (b)
Parameter Change
35.5%
35.5% 0.0%
Debt/Capital
Ratio (b)
Parameter
23.8%
23.8%
Change

0.0%
Note:  (a) These ratio® affected by working capital approach only.
       (b) These ratios affected by debt financing approach only.
Source:  EPA estimates..
                                                      8-28
SAHO_maj.wk3
21-Dec-92
-------
TABLE 8-21

CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT  OF  EFFLUENT  GUIDELINES REGULATIONS
BAT AND NSPS PRODUCED SAND

Parameters
Baseline
Zero Discharge
Working Capital (a)
Millions Current Ratio 
Parameter Change
168.6%
168.6% 0.0%
Debt/Capital
Ratio (b)
Parameter Change
128.8%
128.9% 0.0%
Note:  (a) These ratios affected by working capital approach only.
        These ratios affected by debt financing approach only.

Source:  EPA estimates.
                                                      8-29
 sand ind.Mk3
21-Dec-92
-------
8.7    COMBINED REGULATORY PACKAGES

       Table 8-22 presents the costs of compliance for the two regulatory packages.  The total
annualized costs in the first year range from $122 million to $144 million in 1986 dollars. The
costs drop to $36 and $86 million, respectively, in the 15th year of the regulation. The portion of
these costs borne by the typical major oil company ranges from $3.8 million to $4.5 million for
first year costs, and from $1.1 to $2.7 million in year 15 cost.  For the typical independent, the
share ranges from $0.18 million to $0.22 million and from $0.05 to $0.13 million for the same
packages.

       Table 8-23 summarizes the potential impacts that the incremental costs would have on a
typical major as measured by several financial statistics. Under Package B, working capital
declines by 0.3 to 0.6 percent while the current ratio shows change of less than 0.1 percent.
Impacts on working capital are less for the other package.  When long-term debt is considered as
the financing method, we see increases in the leverage ratios of 0.1 percent or less under any
given package.

       Table 8-24 displays the potential impacts that increased pollution control costs would
inflict upon the typical independent oil producer. The greatest impacts are seen when working
capital is used exclusively to finance the additional pollution control. Under this financing
scenario, we see declines in working capital of nearly 4.5 to 5.3 percent. The current ratio
declines by 0.4 percent or less. When long-term debt is the financing mechanism, increases in
the leverage ratios are 0.2 percent or less under any given package.
                                           8-30
-------
TABLE 8-22

ANNUAL COST OF POLLUTION CONTROL OPTIONS
COMBINED REGULATORY PACKAGES
MILLIONS OF DOLLARS, 1986 DOLLARS
Package           Waste Stream
                                                                                       Total
                                                                         Year     Annualized
                                                                          of             Cost
                                            Effluent Control  Option    Regulation  of Package
                                                        Typical      Typical
                                                          Major   Independent
                                                        Portion      Portion
       Drilling Fluids & Drill Cuttings
       BAT Produced Water
       NSPS Produced Water
       BAT Treatment & Workover Fluids
       NSPS Treatment & Workover Fluids
       NSPS Completion Fluids
       Produced Sand

       Drilling Fluids & Drill Cuttings
       BAT Produced Water
       NSPS Produced Water
       BAT Treatment & Workover Fluids
       NSPS Treatment & Workover Fluids
       NSPS Completion Fluids
       Produced Sand
3 Mile Gulf/CA
Flotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
Year One

Year Fifteen
                             Year One
3 Mile Gulf/CA
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska Year Fifteen
Oil and Grease Limits
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
$122

 $36
                   $144

                    $86
$3.77

$1.11
           $4.47

           $2.66
$0.18

$0.05
             $0.22

             $0.13
 Source:   EPA  estimates.
  PKG SHRE    21-Dec-92
                                                         8-31
-------
     II
til   O •"••

—j   se CQ
                                      »-   o   «-   *-
                                 g   IS
                                           KS   53
                                                3*   3*
                                 10   M   M   10
                                      »t
                                           5   S   8
                                      »t
                                           «-      «
                                                             "^   2
                                                             ^%*N   UJ
                                                    8-32
-------
   UJ

   u.

   o
   §
I-   U U
            *,
            <=e
             s
                  s
                 Is

                 =1
                 oca
                                 X  »*  »<

                                  .  *J • "^
                                 o  o  o
  aoJ
  CM
                             O  O   O   O
                        S    S  3
                                 o  o   o
                              §  g  g  g
                                 »
                                 «-  m  to
                        3    3
                               a  no   a   co
                               o  a!   0)   o
I  I
                                                 §c
           Sg

           l-'i
           o «o
                                                 •s
                                                 s-g
                                                 II
                                                 .2.2   8
                                                       g
                                                 ^N<-»  Ul
                                                 01 XI
                                           8-33
-------
8.8    REFERENCES
PennWell. 1991.  PennWell Directories, 1991 U.S.A. Oil Industry Directory. 30th Edition,
       January.

MMS. 1990. U.S. Minerals Management Service, Federal Offshore Statistics: 1989. OCS Report
       MMS 90-0072, Tables 60 and 61,1990.

MMS. 1991. U.S. Minerals Management Service, Federal Offshore Statistics: 1990. OCS Report
       MMS 91-0068, Tables 60 and 61,1991.
                                        8-34
-------
                                    SECTION NINE
                            IMPACTS ON PRODUCTION
       The incremental costs of additional pollution control potentially can lead to lost
production because projects are closed early or are not undertaken. This section presents the
methodology for evaluating the potential production loss under different regulatory options.
9.1    METHODOLOGY

       The basic approach uses the change in the present value of production due to
incremental pollution control costs to estimate the potential production loss.  First, total
"baseline" production1 is estimated — that is, the present value of production from all projects
before any incremental costs. To obtain total 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 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 takes into consideration  early
curtailment of projects, immediate project shutdown (BAT), or projects not undertaken (NSPS).
This approach takes into account lost production over the entire lifetime of the project, not just
during the first year of the regulation.  Since the analysis is performed with the assumption of a
constant  oil price, a project that is considered uneconomical due to increased pollution control
costs is counted as a loss for the entire time period. That is, projects are not considered to
    Production is expressed in terms of barrels-of-oil equivalent (BOE) 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
-------
become economical later in time due to rising oil prices as in the analysis by Grigalunas and
Opaluch, 1988.

       The same set of factors is used to calculate of the cost of a regulatory option and the
production tinder that option. These factors include:

       •      For existing structures in the Gulf of Mexico (BAT), 37 percent use onshore
              treatment and disposal of the produced water.
                        I iX^ LJW/1 V/k/llLUCkV \Ji iiAV/iAinvk* fc.*****. •» V«M.»- •»•••——— ___——	
                       equirement for improved gas flotation are as follows:
                            Oil only facilities - 40 percent
                            Oil and gas facilities - 60 percent
                            Gas only facilities - 80 percent
              The remaining projects are assumed to bear increased annual costs to upgrade the
              performance of existing equipment.
        •     For new structures (NSPS), only 20 percent need an improved gas flotation
              system while the remaining 80 percent are assumed to need to upgrade their
              equipment and procedures.

 The reader is referred to Section XII of the development document for the basis of these costing
 assumption;;.
 9.2    PRODUCED WATER — BAT

        Table 9-1 shows potential production loss under the various regulatory options for
 existing stnictures estimated to bear incremental costs of pollution control.  The Flotation All
 option leads to about a 0.4 percent decrease in production (15 million BOB over the 15-year
 time period).  The Zero 3 Miles Gulf includes an exemption from the zero discharge
 requirement for single-well structures in the Gulf that have their own production equipment
 (Gulf Ib stnictures) and Pacific projects. These structures must meet flotation requirements.
 The production loss under this option is also 0.4 percent (17 million BOB over the 15-year time
 period). Extending the zero discharge requirement to  all structures in the Gulf of Mexico (Gulf
 Ib projects and Pacific projects also meet flotation, not zero discharge in this option), leads to a

                                             9-2
-------
TABLE 9-1

CUMULATIVE POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
OVER 15 YEAR PERIOD OF ANALYSIS
BAT PRODUCED WATER


Option
Number
1
2
3
4
5


Scenario
Baseline (BPT All}
Flotation All
Zero 3 Miles Gulf
Zero Discharge Gulf
Filter 4 Miles

Total PV of
Product i on
(Millions of BOE)
4,201
4,187
4,184
4,101
4,186
Potential Loss
(Millions
Data

15
17
100
16
in Production
of BOE)
Percent

-0.4%
-0.4%
-2.4%
-0.4%
Source:  EPA estimates.
 PROD IMP.WK3
21-Dec-92
9-3
-------
 production loss of 2.4 percent (100 million BOE over the 15-year time period). The Filter 4
 Miles option is associated with a production loss of 0.4 percent (16 million BOE over the 15-
 year time period).
 93    PRODUCED WATER — NSPS

       Table 9-2 shows potential production loss from incremental pollution controls on
 produced water for new projects. None of the options examined, including Zero Discharge Gulf
 and Alaska option, leads to more than a 0.3 percent loss in production (21 million BOE over the
 15-year time period). Options involving improved gas flotation or filtration within 4 miles of
 shore result in less than a one-tenth of one percent loss in production.
9.4    COMBINED EFFECTS OF SELECTED REGULATORY OPTIONS

       Table 9-3 is a list of the regulatory packages considered in this report.  Table 9-4
summarizes the potential production loss under each of these packages. The impacts of
increased pollution controls on drilling fluids, drill cuttings, produced water, produced sand, and
treatment, workover, and completion fluids are included in these estimates. As shown in Section
Seven, there are no incremental production losses beyond those already seen for the produced
water options. Under Waste Package A (Rotation All), there is a production loss'of about 0.1
percent (15 million BOE over the 15-year time period). Under Waste Package B (Zero 3 Miles
Gulf and Alaska), the production loss is approximately 0.2 percent (19 million BOE over the 15-
year time period).
9.5    REFERENCES
Grigalunas, Thomas A. and James J. Opaluch. 1988. Comments on EPA-Funded Economic
       Study Eastern Research Group Economic Impact Analysis of Effluent Limitations
       Guidelines and Standards for the Notice of Data Availability for Drilling Fluids and Drill
       Cuttings for the Offshore Oil and Gas Industry. Economic Analysis Incorporated.
       Peacedale, Rhode Island. December.
                                          9-4
-------
TABLE 9-2

CUMULATIVE POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
OVER 15 YEAR PERIOD OF ANALYSIS
NSPS PRODUCED WATER


Option
Number
1
2
3
4
5


Scenario
Baseline (BPT All)
Flotation All
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
Filter 4 Miles

Total PV of
Product i on
(Millions of
7.598
7,598
7,596
7,577
7,597
Potential Loss
(Millions
BOE} Data

1
2
21
1
in Production
of BOE)
Percent

-0.0%
-0.0%
-0.3%
-0.0%
Source:  EPA estimates.
 PROD IMP.WK3
21-Dec-92
9-5
-------
                                     TABLE 9-3

                              REGULATORY PACKAGES
Packages
V/aste Stream
Regulatory Option
B
Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS TWC Fluids
Produced Sand

Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS TWC Fluids
Produced Sand
3-Mile Gulf/California
Flotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge

3 Mile Gulf/California
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
                                         9-6
-------
TABLE 9-4

CUMULATIVE POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
OVER 15 YEAR PERIOD OF ANALYSIS
IMPACTS OF COMBINED REGULATORY PACKAGES
Package  Scenario


         Baseline
                       Total PV of
                       Production
                       (Millions of BOE)
                                                          Potential Loss in Production
                                                                (Millions of BOE)
                   Data
                              Percent
         Flotation All
                         11.800

                         11.784
                     15
                                                                                 -0.1%
    B    Zero 3 Mile Gulf and Alaska
                         11,781
                     19
-0.2%
Source:  EPA estimates.
PROD IMP.WIG
21-pec-92
9-7
-------
-------
                                  SECTION TEN

         SECONDARY IMPACTS OF BAT AND NSPS REGULATIONS



      Although the exists 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, EPA 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 two packages of regulatory options:
Packages

A
B
Waste Stream

Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand

Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand
Regulatory Option

3-Mile Gulf/California
Rotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits

Zero Discharge

3 Mile Gulf/California
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits

Zero Discharge
These costs change through time as existing structures cease operation and no longer incur BAT

costs, while new structures continue to come into operation and bear NSPS costs. The costs of

the regulatory packages are presented for the first year of the regulation when BAT costs are at

their highest, and in the fifteenth year of the regulation when NSPS costs are highest.
                                          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. As a
 result, the federal government 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, EPA assumes  91 percent of the remaining costs could be
 recouped by the company through lower lease bids on federal areas.

       Table 10-2 lists the potential impacts on federal revenues.  For example under year one
 of regulatory Package A, the total annual cost of the regulation is  $122  million (1986 dollars).
 Revenue lost to the federal government through tax savings equals $122 x .34 or $41 million
 (1986 dollars; $47 million in 1991 dollars).  In year 15, the cost from regulatory Package A drops
 to $36 million with a concomitant loss of $12 million in tax revenues (1986  dollars; $14 million in
 1991 dollars).

       There also may 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 A the
potential loss" due to lower lease bids equals ($122 minus $41) x .91 or $73 million  (1986 dollars;
$82 million in 1991 dollars). 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
                                            10-2
-------
TABLE 10-1

RATIO OF FEDERAL-TO-STATE PRODUCTION
PROJECTED PRODUCTIVE DEVELOPMENT WELLS IN OFFSHORE REGION (15-YEAR  PERIOD)
Region
Gulf
Pacific
Alaska
Total
Percent
Source:
Number of
State Wells
538
0
69
607
of Total 8.8%
EPA Estimates.
Nunfcer of
Federal Wells
5.914
38Z
29
6,325
91.2%

Total Number
of Productive Wells
6,452
382
98
6,932


 T10-1.WK3
21-D6C-92
                                                 10-3
-------






































CO
o
*™

u.

1
m
— 1 CO
£ u
2
CO U
uj «s
3 CX

UJ >-
5g
08 5

01 O O
— • > 4J O
CD O
H-
— * 05 C_ Cfl
CO 0) OIT3
— O 3 —
4-> _> o m
C —i .
01 01 fl>
4J 2 O W
O C ** CD
n oi 01
> 0) _l
• 01 3
Of O
ISI1
W «*-**- CU
o uj<*--a
0» CO M- C3
gl- 0
01
a:
__,
'i U
g
t- 4-»
ca «+- - 3
I

g
4-»
ci-
1
g
u
4-*
I
**—
H-
UJ










1
s



>»

o
4-1 0
6) O)
— • CO
o> u
at ca
o£ a.
** ^*

«- ^>








5 •«







» R






Rl S
5 *
§
JH-
U.

C_ L.
(0 CD
o o


U) CO CA
*->*-> 4J

-J — 1 — 1
SO) Q) Q) O
-j _• CO tO CO CT
•^_»_, CD co ca t.
M- *t  •*- O
K1 u- u. O O O rsl
CA CA
•^- »S- 3

CJ C_
C- O
S §^-S

o c. t. o u
u o o u —
eB Q» 4-* 3 u-
4J (Q {^J
« OJ 3«^J C
D T) t& C Q) 4-» C
tu O 3 E 4-*— • CO
3 TD *-» CO Q.
O5~O O CD (U E TJ
C o t- GJ i_ o ai
— t_ a. L. t— cj u
— ' O. H- 3
— * CO tO CO "O
•— 1— O. 1— Q. Q. O
C. t- 01 01 01 0) 01 CO
—•—<—> L. C. C. f
3 ..- .— C3 O O 0
0) M tO H "H "H 15
v^ CO CD CD
.— O O O
d) 01 ••-••-•>- 0)
Kl IM IM O O O M
CO CA
g -85
i^_ •••* 21

3 ^t

H! > O CA
'H J^ C.i>-
a c. L. o 3
c- tt) O 3— •
.^ T) 4-> C •»- TI
3TJ 5 C 01 4J C
— • 0) O OJ E CO CO
U. U 3 6 4J— • CO
3 T) 4-* CO Q.
mT> o co o> g TJ
c o t- ei L. S a>
— t. Q. I- t- CJ 0
— • a. t- 3
•_. co co co T3
•~ *— a. ^ a. a. o
C- < CO <£ CO C/) f-
o QO z m z x a.




m






















































S
4^
4-*
0)
£
UJ




o
3
O
CO
10-4
-------
increases remaining after the tax savings.  The potential losses range from $73 to $87 million
(1986 dollars; $82 to $97 million in 1991 dollars) in the first year of the regulation.  The total
potential revenue loss to the federal government ranges from $114 million to $136 million (1986
dollars; $129 to $153 million in 1991 dollars) in the first year of the regulation. By the fifteenth
year, the loss has dropped to $34 to $81 million for the two regulatory packages (1986 dollars;
$38 to $91 million in 1991 dollars).

       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 $497 million
in apparent high bids. In 1988, OCS sales brought in $1,260 million in bonuses. The potential
loss in federal revenues in the first year due to lower lease bids and tax savings to the companies
(from Table 10-2) ranges from 9 to 10.8 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 losses in federal revenues is the loss of royalties due to early
closure of projects or projects not undertaken. This reduction in royalty revenues would be the
result of a potential loss  in future production, which is investigated in Section Nine.  The loss of
royalties resulting from lost production is not investigated in this report. The potential loss in
production under regulatory Package A results in a decline in production 0.1 percent. This
translates into a 0.1 percent decline in associated  revenues.
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.  For instance, under regulatory Package A, the calculation is $122
million x .66 x .09 or $7.22 million (1986 dollars; $8.13 million in 1991 dollars).  Table  10-4
                                             10-5
-------
 TABLE 10-3
 RECENT DCS LEASE  BONUSES PAID
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
No. of Sales
3
7
5
7
6
3
2
2
7
2
2
Nunber of
Tracts Leased
218
430
357
1251
1387
681
142
640
1621
1049
825
Bonuses Paid
For Leases
(SHillion)*
$4,204
$6,653
$3,987
$5,749
$3,929
$1,558
$187
$497
$1,260
$646
$584
 *  current dollars.
'Source:  HMS, 1991.
                                             10-6
 T10-3.WK3    08-Oct-92
-------



























tu

z
QC
Ul
5
ft
§
<2
O
CJ
B >-
2 5
_l •-*
Ou H-
§co u
g *
So1 S
*. Q u
CJ ^O Q£
*C CO ^~
1- s

_i en i


*- •• -6
2 _1 2
111 —3 **»
O. W *»
—•WOW
ra w -MT3
'C 5 01 ca
01 01 O 01
«-» 3 to

0. 0) 0)
c* c.
o>
— •TJt- 01
CO 01 O Ol
*• N CO
r* — J-J w
,__ M o
CO O CO
300.
g
L. 4-*
• 3
m
«


S-
"o
4J
g
u
4->



M-
£



•



4J

H-
<«-
Ul







0
4-> 01
CO D>
— • CO
CD O
ceo.
CM «-
N! oi
1A 
a> *-
r§ -il

C- C.
Sco
01

CA CO (0
iii

So> a> a> ai
— •— tn a> 
v«,«* «# CO CO CO C.
H- « oi oi ai a
— • c- t. c. x:


••- 4-" 4J O
*"" ^ 5 «^ IF- M— ai
to u-u. o o o N .

I 32
** !§^
3 U-
u t.
t- Q)
i 111


.« ^ 3oa ^ c

3 ^ w C 5 4J C
- & U Of & Q) tS
U. O 3 E 4->— • CO
313 « 03 o.
o)-H 5 o a> e "P
C 0 C. 01 C. S 01
•— c- a. t- t- cj o

i co co en's
U < CO < CO CO C-
o £O z ca a: ^ a.




<


vO CO
in o
S "^





^






i
i 1


So
01
CO
Hrf
TJ (0 M W
C 4-» 4-» 4-»
a .,- .— .„
E E E
•4- 4. ._ .„ ._
 at oi oi
U M W W O)
***i CO W CO CO 0 t-
H- 01 01 Ol 01 01 CO


CJ Z X V)
•n "n "o «p»
OJKiro if c Co
*^ CO O CO
— o o o
01 0, •*— *F- "~ 0)
K»N NO O ON

1 -82
5 !§5
3 it
CJ C-
L. at
^ o5"8
L. Jtf L. •—
O C- t- O 3
t- at o 3 — >
oB 01 4-»3J u_

"§ S 308 -M O

3 TJ at c aj 4-* c
x- 1- Q. I- I— O U

— W W CO^J
*B~ ^_ ft }w ft- ft O
oca ae co z ae o.




GO












































t Imates
CO
UJ
g
Ul



0)
o
3
S
                                                          u
                                                          01
                                                          a
10-7
-------
 summarizes these costs, which range from $7.2 to $8.6 million in the first year of regulation
 (1986 dollars; $8.1 to $9.6 million in 1991 dollars). These costs drop to $2.1 to $5.1 million in
 the fifteenth year of the regulation (1986 dollars; $2.4 to $5.7 million in 1991 dollars).

       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
 waters is on existing leases. California, then, would not suffer any 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 1990, Texas
 produced 1,768,800 bbl of oil and 108,995,500 Mcf of gas from offshore state wells.  In the same
 year, the other major producing state in the Gulf of Mexico, Louisiana, produced 22,829,500 bbls
 of oil and 178,633,000 Mcf of gas from offshore state wells (API, 1992).  These figures convert to
 20,955,278 barrels-of-oil equivalent (BOB) for Texas  and 54,274,267 BOB for Louisiana.  Texas,
 therefore, generated approximately one-quarter (28 percent) of state offshore production in the
 Gulf of Mexico in 1990, while Louisiana produced the remaining 72 percent. Since the
 proportions can fluctuate from year to year, this analysis apportions 25 percent of the states' cost
 of the regulation to Texas and the remaining 75 percent to Louisiana.

       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 projects 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.
                                                     "N
The last parameter is the proportion of production occurring in Texas  state waters in relation to
total production in 1985 for state waters in the Gulf of Mexico.  The potential loss ranges from
                                            10-8
-------






































'
' .
CO
UI
5
C£
111
t—

C/l

UI
§
£
o


B
is
"2
°i

CJ ^5
<: co
i5*~
in *
i _J CO
2 S§


_J HI — 1
en >— «-•
S 25
CO
— * CO O t- CO
CO O *J 0)TJ
4-> at o CD
gat 3 _i
no oi
•M C CO
o oi a
a. > ai
ae
M- OI L. -M L.
o «-> oi c a>
CD 4-» 0) 4-»
§w co g eo
en 3 a.3
«-» z — * co
t- o at co
O C3 > X
OL 01 0)
O 1—
c
H- L. ** *<- O
O 01 C O U
*-» 0) ••-
SCO EH- X
3 a.—- oi
— 0 3 I
•M 0)—- C3
o S > c
O. .u 0» —
CO O
•*-TI 4J 01 CO
O O> C *• I_
•k> at co u
C 0 1 4J *»
o ai H.CO co
•— ~» O 3
*> 0— • C
(. L. 01"-
o a. >
O. 0)
o o us CD cn
'£ 17 ••-
L. 4J Z— >
5 § S
0 CO
I
L. I*
OJH- co
O)

oe
g
'5
«§•
2
g
u

_
H-
Ul









1
H-
IU








O
CD O)
--• ca
U-*

a£
^o in

r- O


~



in in
(M CM

o o


CO CO

o o


-

o o

o o




Nft *&
*o *o
0 0
(M — • co ca 
X*— • —* CD CO O L.
•<- « a> oi o> CD
— • L. L. t- J=
" ,2 — TJ -Q -O .2
— o o a a io
••- 4J *» O

MU-U-OOON
CO CO
'5 '5 —
5U.
c-fc

— * > o co
— ,6 J2 -S
o ^ j.if o]5
iN-ii^'
ul 0 jj 1 Bi CO
g-fg g S g-^g
•— «- a. L. t- o o
— * a. i— 5
-- to coco -a
'C S CO < CO CO U
o m x m aez a.








o «-

«» *»






in in
rvi CM

O C5


S §

0 0




o o-
o o

o o




S $
0 C3
i i
«»
I
o iT
u c-
Sco
a>
1
~B  •*» (^
E E.E
SO C3 01 01 01 01
co co ca o>
•^ ca « co co eo n-
<»- 0) 0) 01 01 01 «0
— ._._. c. t- t-.e
3— — CO CO O O
_o» to m c e e 5
5 2 2 — • — • — • 2

DON NOO ON
tn co TI
S '53
4_* i^ U_
5U.
L.fe



SfesPl
•8SS<>8^g
•S -o ** c »X -B
3"8 S 8 **

g-g g g § I'-g
•«— L. a. L. »- cj o
— a. i— 3
— • CA W CO '6
*u «o < co cy> u
a co =E m z z a.


















































g

§

w


„
O


i
4J CO
O 01
C V


ca
8 °
• ^
c. 2
** UI
c
UI
01

01 fc.

z to
10-9
-------
$1.6 to $1.9 million (1986 dollars; $1.8 to $2.1 million in 1991 dollars) in the first year of the
regulation, and from $0.5 to $1.1 million (1986 dollars; $0.5 to $1.3 million in 1991 dollars) in the
fifteenth year of the regulation.

       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 6 to 7 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 0.1 percent.

       Tables 10-7 and 10-8 repeat the calculations for Louisiana, whose fiscal year runs from 1
July to 30 June.  Ilie potential loss in revenue ranges from $4.8 to $5.7 million (1986 dollars;
$5.4 to $ 6.4 million in 1991 dollars) in the first year of the regulation. 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 after 1987 indicate how this sector
of the economy has begun to recover. Bonuses were $28 million in  1987-1988 and $15 million in
1988-1989. The revenue loss associated with the first year of regulatory Package A is about 40
percent of Louisiana's 1986 bonus income. The impact of regulatory Package A on total state
revenue for 1985-1986 (the lowest total revenue in the series), however, is still less than 0.1
percent.
103   IMPACT ON BALANCE OF TRADE

       The United States is rapidly approaching the time when it imports more oil than it
produces. The Department of Energy projects this time to arrive in 1994 (DOE, 1989), but it 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
concern over maintaining domestic oil sources is 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
                                            10-10
-------
TABLE  10-6
TOTAL  TEXAS STATE REVENUES AMD BONUS REVENUES

Year
1985
1986
1987
1988
1989
Bonus Revenues*
(Will ion)
$60.3
$25.4
$18.4
$26.0
$24.3
Total State Revenues*
($Hillion>
$16,980
$17.952
$17,524
$20,357
$21,479
*  Current dollars.
Source:  Plaut, 1990.
T10-6.WK3    08-Oct-92
                                        10-11
-------





























































h_
o
111
_1
1










































§
UJ
3
of
1U
CO
rf
s
to
1
g
CO
fe
0
u
LU
z
2
5 co
o o;
u%

° S
»_
S*^
25 *~

_1 CO
Z .J
UJ •-!
§5
CO
«rf CO O U 05
a o *• atj
•»- -J 3C*«-
.M oi o ca
Sli-'o,
M E CO
o ol ca
IX > 01
01 -J
c_
•>- oi c o t.
O 4J •- C 01
co co +*
a 3 *• ••- a
•W *•» S 3
c. a Q.O

ia. co— •
55
cj a
u- t- ** t- o
0,01 coo
i£ s.i <5
— o 3 ac
,M 4I->C3
IX *• 01 •»•
co a
ti_ *n •*•* o> co
o oi c *• «-
go 6 *• *•
01 a.c/> ca
*M *O^^ C
L. C. »>•*•
00. >
IX O)
0
o o £^ 3 o)
'w *o ••»
U 4J (D— ' >
O CO X) O O
Q.O-' L_ CO
o u  0)
O -* — • CO CO CO O)
*^M*~* O CO «-« o> oi oi ca
»> *m ? "8 ? S
— • ca co ca ca co
••- ** *J O
ro u_ u. o o o rj

§_«
•SiS
'^ '5-2
3 Iu ""
" c- fe
^ § 0 CO
cZ ^ c. «»-
Q C. U 0 3

4J CO 08 ""
U. O 3 £ *• — * W •
3 •5 *j co a.
OYJ O ID CU e ^J
COC.OIC.OOI

^ CO CO WO
L. < CA < CO C/3 C.
omzmzza.


•e


N- vt

S 8






K K

O O





s «
o o




g g
'o o





o o


«r 8

I
CO «*-
c ••*-
o u.
C- C.

>i >-
m
a
v to ca CA
*"lll
111 111!
l^iiif
0) fl) >P. •*. .*. gi
ION MO o ora

§0)
CO TO
+j 3 — '
3 Uv
u <-
C. 0)
— ' OI >
— < > O CO
ci c. "cf o '5
oa a *•» Vk
<-< ra oa
"5 TI * c o 'C e
5'6 *• co o.
g"8 2 g 2 g^
•^ ua. L.O-CJ y
IS0" CO *" CO tO TO
 .
o o
z en
                                                       8!
10-12
-------
 TABLE  10-8
 TOTAL  LOUISIANA  STATE  REVENUES AND BONUS REVENUES

Year
1984-1985
1985-1986
1986-1987
1987-1988
1988-1989
Bonus Revenues*
CSMUtion)
$59.7
$26.0
$12.1
$27.7
$14.7
Total State Revenues*
( SMill ion)
$8,804
$8.800
$9,306
$9,105
$10,186
*  Current dollars.
Source:  Hoppenstedt, 1990.
T10-8.WK3    08-Oct-92
                                       10-13
-------
continue to import a growing percentage of its domestic oil consumption.  This phenomenon is
occurring in the absence of any incremental pollution control costs.

       The potential loss in production is investigated in Section Nine.  Even under regulatory
Package B with the higher projected costs, production declines over the entire 15-year period do
not exceed 0.2 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 be insignificant
compared to changes caused by outside factors.
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 capital and annual operating costs
required for the disposal of produced water. Since the well operators are the ones who purchase
and operate the disposal equipment, they will ultimately bear the cost. 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.
                                        10-14
-------
 10.5   IMPACTS ON INFLATION
                  «",...•••'"             •    '             "'
       The regulations can lead to higher costs to the operators.  When evaluating this effect on
 typical companies, it was assumed that they could not 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 oil 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, substantial impacts on inflation from increased cost of pollution controls on
 offshore oil and gas effluents are not anticipated. The impacts on the companies (Section Eight)
 and the impacts on production (Section Nine) were investigated under this set of assumptions.
10.6   REFERENCES
API, 1992.  American Petroleum Institute, Basic Petroleum Data Book. Volume XII, Number 2,
       Section XI, Tables 18 & 19, May.
DOE. 1989. U.S. Department of Energy, Annual Energy Outlook:  Long-term Projections 1989.
       Energy Information Agency, DOE/EIA-0383(89), January 1989.
Harvard. 1988.  Harvard University, Lower Oil Prices:  Mapping the Impact. 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. 1991. U.S. Minerals Management Service, Federal Offshore Statistics; 1990. MMS 91-
       0068, TableS.
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.
                                          10-15
-------
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.
                                         10-16
-------
                                  SECTION ELEVEN
                           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.
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.
                                         11-1
-------
-------
                                    APPENDIX A
            SELECTION OF OFFSHORE OIL AND GAS PROJECTS
       Offshore oil and gas platforms vary by size, volume and 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 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 the
Beaufort Sea region of Alaska in 1987.  Future production may occur in other Arctic regions.
The area off the Atlantic Coast is not expected to be developed within the time frame of this
analysis.

       The economics of oil and gas  production and pollution control differ among platforms
because of the variability of platform features.  To capture these differences, representative
model projects have been developed  for the various geograpWcal 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. (EPA, 1985).
                                          A-l
-------
  A.1    GENERAL PARAMETER CATEGORIES

         The model projects presented below reflect three key factors:  geographic region, size,
  and production type.  In all, 32 model projects are presented.  They characterize the range of
  platform types expected to be installed during the study period.
        A.I.I  Geographic Region

        Offshore oil and gas deposits are known to exist in or are posited for:

        «      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
        •      Atlantic - North, Mid-, and South Atlantic

        These areas are shown in Figures A-l and A-2.

        Three regions—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, separate models are developed for each of the three
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. The Atlantic region also has its own characteristics. Due to leasing and
exploration constraints, however, no projects are projected for the Atlantic within the time frame
of the analysis (see Section Four). No models are presented for the Atlantic in this report; see
the economic impact analysis for the 1991 proposal for a discussion of Atlantic models.
                                           A-2
-------
                                                   Cfl


                                                  I
                                                  OJ
                                                  CO
                                                   as
                                                   «
                                                  I
                                                   f
                                                  1
                                                   5
                                                   u
                                                   O    52

                                                   <     ..
                                                          £0)
                                                          f\

                                                    IA    ?
                                                   • M     O
A-3
-------
                                                       I
                                                       I
                                                       • •
                                                       03
                                                       gf


                                                       1
                                                       01
                                                       8
A-4
-------
       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 are a single wellslot structures 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.

       Table A-2 summarizes the number of wellslots per platform in Pacific OCS waters.
Existing and planned structures contain from 15 to nearly 100 wellslots, with an average of 55
wellslots per platform (MMS, 1986). Three structures of varying sizes are chosen to model the
Pacific region; their associated number of wellslots is 16, 40, and 70.
                 i
       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 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:

        •      Cook Inlet -12 or 24 wellslots, depending on type of production
        •      Beaufort Sea - 48 wellslots
        •      Norton Basin - 34 wellslots
        •      Navarin Basin - 48 wellslots
                                            A-5
-------
 gulf#.wk1

 TABLE A-1
 NUMBER OF  STRUCTURES BY THE NUMBER OF UELLSLOTS AVAILABLE
 GULF OF MEXICO, MARCH 1988
Number of
Uellslots
Available
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
Note: Blanks
Number of
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
indicate no
Production Equipment
Yes
20.0%
34.8%
49.7%
60.6%
75.7%
82.3%
90.3%
94.9%
93.8%
96.8%
100.0%
92.3%
100.0%
95.0%
89.7%
97.0%
95.4%
100.0%
77.8%
91.3%
80.0%
100.0%
95.9%
66.7%
80.0%
100.0%
100.0%
100.0%
0.0%
100.0%
100.0%
100.0%
100.0%
100.0%


structures with
No
80.0%
65.2%
50.3%
39.4%
24.3%
17.7%
9.7%
5.1%
6.3%
3.2%
0.0%
7.7%
0.0%
5.0%
10.3%
3.0%
4.6%
0.0%
22.2%
8.7%
20.0%
0.0%
4.1%
33.3%
20.0%
0.0%
0.0%
0.0%
100.0%
0.0%
0.0%
0.0%
0.0%
0.0%


intermediate
        numbers of wellslots.

Source: HMS Platform Inspection System,  Complex/Structure
        Data Base, March 1988.
                              A-6
-------
# slots.wk1
28-Feb-92
TABLE A-2
NUMBER OF WELLSLOTS OM PACIFIC DCS PLATFORMS
         Platform
             Name
Number of
Uellslots
     Year
Installed
     Water
Depth (ft)
Existing A                        57         1968          188
         B                        63         1968          188
         C             .• = ••         60         1977          193
         Edith                    72         1983          161
         Ellen                    80         1980          265
         Eureka                   60         1984          700
         Gail                     36  .       1987          739
         Gilda                    96         1981          210
         Gina                     15         1980           95
         Grace                    48         1979          318
         Habitat        .          24         1981          303
         Harvest                  50         1985          670
         Hermosa                  48         1985          602
         Henry                    28         1979          291
         Hidalgo         .         56         1987          430
         Hillhouse                60         1969          190
         Hogan                    66         1967          150
         Hondo                    28         1976          842
         Houchin ,                 60         1968          151
         Irene                    72         1985          242

Proposed Hacienda                 48           --         '300
         Harmony                  60         1992         1300
         Heritage                 60         1992         1075
         Julius                   70         T989          478

Average Number of Wei Is lots    ,54.9          •-•"•'•
Source:  MHS, 1986; Ocean Industry, 1987a.
                                       A-7
-------
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 16
region/size categories are defined.  These are shown in the left column of Table A-3.
       A.1.3 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 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 platfbrms. 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 either oil with gas or gas only.  W. Guerard of the
California Department of Conservation stated that all oil fields produce some gas, but that as an
oil field gets older, it produces  less gas (Guerard, 1989). For the purpose of evaluating the
pollutant removals from produced water effluent guidelines, all projected platforms that produce
oil are assumed to have associated gas as well.

       In Alaska, projects in the Cook Inlet are assumed to produce oil with gas or gas only.
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-8
-------
                                     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
OIL OIL/GAS
Yes
Yes
Yes
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
Gulf 58             Yes     Yes    No


Pacific 16          No      Yes    Yes

Pacific 40          No      Yes    No


Pacific 70          No      Yes    No


Cook Inlet 12/24    No      Yes    Yes"

Beaufort Sea 48
platforms.

No gas-only platforms among large Gulf
platforms.
No gas-only platforms among  large Gulf
platforms.

No gas-only platforms among  large Gulf
platforms.
- Gravel island
- Platform
Norton Basin 34
Navarin 48
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
infrastructure
infrastructure
infrastructure
infrastructure
for
for
for
for
gas
gas
gas
gas
delivery.
delivery.
delivery.
delivery.
Source:  EPA 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.
                                        A-9
-------
A.2 DESCRIPTION OF MODEL PROJECTS

       A.2.1 Gulf of Mexico Model Projects

       Gu\f 1-, 4-, and 6-Wett 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.

        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.
        Gutftt-Wett and 24-Wett 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

                                            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:  MMS,  1987a.
                                     A-ll
-------
                                  TABLE A-5

                          SAMPLE STRUCTURES USED
                     IN SELECTING 24-WELL MODEL PROJECT
AREA.
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
BLOCK
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:  MMS,  1987a.
                                    A-12
-------
are in use for production at any one time (10 in the model project).  The typical 24-wellslot
steel-jacket platform occurs in 50 to 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, EPA 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 was
installed in Green Canyon in 1988.  Cognac and Bullwinkle are set approximately 15 and 90
miles offshore at depths of 1,023 and 1,353 feet, respectively (Offshore, 1986, MMS Offshore
Platform Inspection System). Information  on the Gulf projects is summarized in Table A-7.
       A.2.2 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 ft?/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
                                            A-13
-------
                                  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:  MMS,  1987a.
                                    A-14
-------
                                    TABLE A-7




                              PROJECT DESCRIPTIONS




                                 GULF OF MEXICO
GULF OF MEXICO PROJECTS
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
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
j acket
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
j acket
yes
yes
20
32.0
100
30
24
18
GULF
40
steel
j acket
no
yes
50
80.4
200
60
40
32
GULF
58
steel
jacket
no
yes
100
161
590
180
58
50
Source:  EPA estimates.
                                        A-15
-------
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-8.
       A.2.3 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/Shelikof 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-9 lists
information about existing platforms in Cook Inlet (Alaska, 1984; 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.
                                            A-16
-------
                                  TABLE A-8




                            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 jacket
no
yes
5
8.0
1,000
300
70
60
Source:  EPA estimates.
                                     A-17
-------
                                   TABLE A-9



                           PLATFORMS IN COOK INLET
FIELD
N. Cook Inlet (gas -only)
Granite Point
Trading Bay
McArthur River
Middle School Ground
Total

A Platform
Bruce
Anna
Granite Point
Spark
TSA
Monopod
King Salmon
Grayling
Dolly Vardin
Steelhead
Baker
A
C
Dillon

YEAR
INSTALLED
1968
1966
1966
1966
1968
1968
1966
1967
1967
1967
1987
1965
1964
1964
1965

WELLS
DRILLED
12
17
26
17
7
9
31
24
37
36
36
20
24
16
14
326
Source:  Johnsion, 1988.
                                      A-18
-------
       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
causeway into the shallow waters of the Beaufort Sea linking two artificial gravel islands. The
islands are located about 2-1/2 miles off the coast in 4 to 12 feet of water. Eighty to 120
development wells are planned. The EPA project is a single island with 48 wells, 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 islands/platforms with a total of 271 wells;
a footnote indicates that the number of wells is probably a minimum.  The EPA project is a
single 48-wellslot structure with 40 producing wells.

       Norton Basin. The Norton Basin has a slightly more temperate 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 EPA model project assumes a 34-wellslot platform 40 miles from  shore in 50-foot water with
28 producing wells.
                                          A-19
-------
       Navarin Basin.  The Navarin Basin has light-to-moderate conditions with 5-month ice

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 proposed location is 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 EPA project is a single structure with 48 wellslots  and 40 producing wells.


       Table A-1Q summarizes the information for the Alaska projects.
A3 REFERENCES
Alaska. 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation Commission, n.d.

Alaska. 1988. 5-Year Oil and Gas Leasing Program. Alaska Department of Natural Resources,
       January.

California. 1987. 72nd Annual Report of the State Oil and Gas Supervisor. California
       Department of Conservation.

Drilling Contractor. 1987. "Endicott oilfield development is on schedule," Drilling Contractor.
       August/September, pp. 25-26.

EPA. 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.

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.

MMS. 1986.  U.S. Department of the Interior, Minerals Management Service, Pacific Summary
       Report/Index November 1984-Mav 1986.  MMS 86-0060.

MMS. 1987a. U.S. Department of the Interior,  Minerals Management Service, Offshore
       Platform Inspection System, Complex/Structure List. April 23.
                                          A-20
-------
                                  TABLE A-10




                            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:  EPA estimates.
                                     A-21
-------
MMS.  1987b.  U.S. Department of the Interior, Minerals Management Service, 5-Year Leasing
       Program Mid-1987 to Mid-1992. April.

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, pp. 35-36.

Offshore.  1986. The Gulf of Mexico," Offehore, February, 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.1    PHASES OF PROJECT DEVELOPMENT

       The financial performance of model projects depends upon the timing of costs and
revenues.  Costs incurred in the present must be offset by future revenues; revenues whose worth
is reduced by inflation (see Appendix J for details).

       In developing the economic models for the 32 model projects, EPA 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 delineation phase is included in the economic model projects
to capture the costs and timing considerations for larger projects.  This phase does not  occur
with all projects and it is generally subsumed within the discussion of exploratory efforts.  Hence,
there is no need for a separate discussion of delineation phase impacts. Delineation wells are
included in the number of projected wells; they are therefore included in the costs of the
regulation.

       The development phase includes planning, building, and installing the platform, and
drilling development wells.  The production phase is the time during which oil and/or gas is being
produced.  EPA 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 (and one operating drilling rig) and 12 per
year are drilled on larger platforms (with two operating drilling rigs).  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-l
-------
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 detemminants 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.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; 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., the date when
drilling begins on the first exploratory well) for all OCS sales held from 1975 through 1984. The
average annual time to first spud is less than 6 months 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.

     •  The time period between the start of delineation and the start of development in the Gulf
4 and Gulf 6 projects is assumed to be 1 year.  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. A two-year period between the start of delineation and the start  of development is
assigned to the Gulf 58 project.
                                          B-2
-------
W////////
                                                   I
                                                   Q


                                                   1
                                                   VI


                                                   I

                                                   5

                                                   .2
                                                   "es
                                                   a)
                                                   ca
                                                   I
                                                   4)
                                                   I
                                                   I
                                                   O

                                                      CO
                                                       §
                                                       CO
                      B-3
-------
       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 6 projects; 2 years are assigned to the larger oil and
oil/gas projects; aind 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 from 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 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 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 (EPA, 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 caused 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).

       In light of these developments, tuning for the Pacific projects has been revised from that
given by EPA (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.
                                           B-4
-------
















o o
z o
5 55
H 1
t*^ bb
P% [£j
^D ^5
AQ ^J
rW 0
































CO
6

g
OS
*•
1



















a

§
J2
o








2
o
13"
M
O
1-9
H
O





fa
J •*
D CM
O
fa

o ""*
fa
. i in
D
O

s <*
§
grt
1
fa
Hi 00
D in
O

fa

O "
B M
o

fa

fa
5
o
fa

o
3r«
(9







§
H
HI

O rH O f) ^1"
,' '' '

O rH O CM CO


O O rH i-l CM


O O rH rH CM

O O O rH ' rH

O CM CM CM VO .



O rH O CM m

O rH O CM ro



O ft O CM to
O C3 rH rH CM



O P rH rH CM

P P O rH rH



C -P
<0 4J O 4J C -P C
0) Vl'O-rl (H TJ Q) M*OC 0) d
« <*H rt c -P m c g ideo a) o
Q) O 4^ * rt (d 4>^ (u wU 4^ A *^ S '^H
rH ffl (DO O 0 JJ 4J 4J
4J C C C rH jj id Q) TS (fl
CM dO-rldOO) CCH jQCVl
0) Ot 0) -H rH 0) -rl > 0) 0) 0) (CO)
0)4J.'d 0)4JQ) Q), m o
Id H Ol rH >
mo o x 4J m Q) 4J m m 4-> rH m jj
K Q) rH )H 0) rl V4 T3 rl H TJ rl (0 B3 H
n) I-H ft id id id id id. id .p ta W 4J 0) <*H 4J Q) >W 4J O Q> 4J
>H 0) 0) {H o m SH o ffl >4OD> H r-l tn

































ta
0)

rt
4J
tn
0)
H
0)
o
VI
s
O
01
B-5
-------
OOOCI DODO
cntnuiw in wen in
                                                                                                e
                                                                                               .2


                                                                                               1
                                                                                               .
                                                                                               .-a
                                                                       in
                                         B-6
-------














i
v^
P"4
; g
: H
^rf^
; 8
; 1
« Q
A £
&3 H
W £j
5 O
M ,

P5 .
• cd
o
o . • •
' 'S'" •
'•J-
1
I


















co
1 §
CQ H
pr fa
" S
rij Ss
i 1
CO D









W
3
H
H
fa
W
co
1
&

<4
H
CO
,-i






1 O
CO Q
ft O

H
O

EH
H
a

0
S3!
§

o
J2
1

i
&
O H
O X
CO H
X EH
W 2
..-OH
O O
a; ft
•J
PM
3 o
CO M
OS W
ft ft S3 ^ '





S
f
1
EH
ft


h- 1
g
1
B
M
1
S
o
H
i
1
8
J3
Q
. H
X

1

H
CO
g















1
0 O O
o o o
00 CM O O rH
vo on - •> i
1 en i en I O o o I 1
I rH i I-H i in vo t- i i
I
— ° °
2 o o o
o oo CM o o m
o vo on -. - i
-.01 cnicni 0001 l
H Vi) 1 i-l | rH | Ul VO Tf j j

f^
O 00 O (^ 00
CM vo r> ao oo
•»Oin oncnonon I | i o
HVOCM «HtHrH.H I || CM
O

r* vo 'tH ^"
o to oo oo
o oo I oncnii ill i
o
o
H f> on O O
oo oo oo oo en - -
f» O I on an on en o II
. ^* r>- 1 rH r-i rH i-l ^« I j g\
o
o
t-t in vo o ro f-
CM 00 00 00 - • O3
<*cMro onicnon o roen
•CM t* «* HIHiH CM HH VO
i . - ?••• f •
• . ' ' O
o
t-l t~ 00 O VD
O 00 00 00 -  |rH H

O
^J
< ft T)A S 2 -3 ^''o &§< 103
0) CO O -P 4J «i4 LI *r(
-pii idcQtd-iH tdi ii (do
 14
« I^QftHft X ft


















id

CO
an
H
S
Offshi
*•»
o
vo
00
an
H
^
i
Q) *«>.
r-l O
A ^
id A
rH «.
"id r2
> co
id on
O -
C vo
oo
C an
0 rH
i j?
M -P
O a
VH 3
c -a
•H C
H
m
§ g
0) Q)
|
*•
« g
tO V4
S g
2 CO
B-7
-------
   18
   15-
   12-
I
   9-
   6-
   3-
                                                             (No walls drilled
                                                                  to  data)
       1963   1964   1966   1968   1975   1979   1981   1982   1982   1983   1984
SALE    PI     P2    • P3     P4     35     48     -53     68    RS53    73     80

                              Laaca ecilac and yaare held
Figure B-3.  Pacific Region:  Time From Lease Sale to First Spud Date


Source: MMS 1986a.
                                       B-8
-------
       Table B-2 indicates that discovery wells typically were drilled 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 Henriosa 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 United States for the 5-year leasing plan (MMS, 1987a)
where West Coast projects 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.
       B.2.3 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.

        Figure B-5 shows the time from lease sale to spud date of the first exploratory well.  The
range is from 5 to 36 months, with an average of 18 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.
                                            B-9
-------
                                  TABLE B-3

                               PROJECT TIMING

                               PACIFIC REGION
TIMING
                                  PACIFIC
                                    16
                                             OIL AND
                                             OIL/GAS
PACIFIC
  40
                         GAS   	
                         ONLY
PACIFIC
  70
PACIFIC
  16
Years between lease sale and start    1
of exploration

Years between start of exploration    1
and start of delineation

Years between start of delineation    1
and start of development

Years between start of development    2
and start of operation

Total years between lease sale and    5
start of operation
              10
Source:  EPA estimates.
                                      B-10
-------
   70
   60-
   50-
   40-
   30-
   20-
   10-
        (no production)

                                         81. ZD
        i
                 (no production to data)
        1963    1964    1966
SALES    PI      P2      P3
1968    1975    1979    1981    1982    1983    1984
 P4      35      48      53  RS53 & 68  73      80
Leaca sales and yearn held
Figure B-4. Pacific Region: Time From Lease Sale to Initial Production

Source: MMS 1986a.
                                          B-ll
-------

                           40-

                           35

                           30



                           20



                           10

                            5

     1976  1977  1978  1979  I960
SALE  39    CI    BF    55   80
                                       LOOM
                                              lo* and y*ar
1981
 71
> h«ld
1982
 70
                                                                  1983
                                                                   57
Figure B-5.  Alaska Region:  Time From Lease Sale to First Spud Date


Source:  MMS 1986a.
                                                B-12
-------
       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 time between the start of development and the start of
production for the  Cook Inlet projects (MMS, 1987b;  Ocean Industry, 1987d).

       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 for 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 began production in 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 1 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-4.  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.
 B 3    REFERENCES

 Drilling Contractor. 1987a. "Arctic: Poor economics delay prospecting," Drilling Contractor.
        February/March, pp. 17-19.
                                           B-13
-------
                                  TABLE B-4

                               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:  EPA estimates.
                                      B-14
-------
Drilling Contractor. 1987b.  "Endicott oilfield development is on schedule," Drilling Contractor.
       August/September, pp. 25-26.

EPA. 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.

MMS. 1982.  U.S. Department of the Interior, Minerals Management Service, Draft Regional
       Environmental Impact Statement. Gulf of Mexico, August.

MMS. 1986a.  U.S. Department of the Interior, Minerals Management Service, PCS National
       Compendium. MMS 86-0017, May.

MMS. 1986b.  U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico
       Summary 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-Mav 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 86-0127, January.

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, pp.
       24-27.

Ocean Industry. 1987a. "Chevron's Gail platform launched—finally." Ocean Industry. May, p. 11.

Ocean Industry. 1987b. "1987 Platform Survey," Ocean Industry. March, pp. 64-68.

Ocean Industry. 1987c. "Chevron skirts obstacle, will drill from Gail early next year," Ocean
       Industry. December, p. 9.

Ocean Industry. 1987d. "Steelhead brings new life to aging Cook Inlet field," Ocean Industry.
       November, pp. 35-36.

Offshore.  1987a. "Field developers proceed cautiously in recovery," Offshore. November, pp. 30-
       36.

OGJ. 1988. "Oil and gas production to build on 5-year-old leases in Gulf," Oil and Gas Journal.
       4 January, pp. 15-18.

OTA. 1985. Office of Technology Assessment.  Oil and Gas Technologies for the Arctic and
       Deepwater. Washington, DC, May.
                                         B-15
-------
Rau, D. 1987. Personal communication between Maureen F. Kaplan, Eastern Research Group,
       Inc., and Denny Rau, Minerals Management Service, Pacific Office, Ventura District, 15
       December.
                                         B-16
-------
                                     APPENDIX C

                                   LEASE PRICES

       The economic model begins with the purchase of the lease for exploration and
development.  The lease cost is amortized over the productive life of the project, and is taken as
a depletion allowance on a company's income statement (see Section J.2.4.1).
       The lease price for each model project is a function of four factors:
       Lease Price    =
Price per     X     Exploratory Wells
Tract               Discovery Well
                           Ratio of Expected
                           Production
                      Platforms
                    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 Pacific and Alaska were held in 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 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.
                                           C-l
-------
S
                                                                         m eo
                                                                          Hft   VXAVt
                                                                            ?   s§;
                                                                    «— CM CM CM   *-«—«-
                                                                    in in in in
                                                                                   gR!
                                                                    o KI vr co
                                                                    ^- f\j "4- h-
                                                                    in o co ^f   CM co
                                                                                      o*
                                                                                      O
                                                                         vj- h-    ro in co
                                                            ) T3
                                                            ) O
>*-   r^-CMO
>o   o«-«
                                                                    N. co O in   ^j o -*
                                                                    - '  -
-------
       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 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 information for Alaska is presented in Table C-3. 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 five 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-4. 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
                                            C-3
-------
        CO   *—   «—
             8
        cvj   CM   «-
        5   g
u-n
n o
                           •8
        S
                                         C-4
-------






















































s,
LU
CJ


Q.
Ul
C/l
«— IO UJ
3 CJ

I- O
4^




M- (A TJ
0 4-« 5
U tA
.U CD (0
£ *"" ™*
Z

»*- IA *q
O 4-» CO
o c-
C. (D O
0) C. M-

"e o
*





c
o
O)
0)
C£




CO
0)




^ oo

sO COCO

O N- CO


IS2
l^'rJ'rJ'
CO -* O
to NS-CO
"^ iJ "*
ro in N.-

in in in






CM OCM
ro co ro
co stro
t^ ^o%±
*- CM**

« « «



§t^ in
w- «—
CO ON 00
in o *o
to in co



,
O *O in
u-» o. tn





.££









oro
CDCO
fe°-
c8^
O U -1
•M <
c- • 1—
o «-> o
Z CO 1—




- 8
ro i>
o
to fo ro
WWW
ro N- r*—
Ov IM CO
in in in






ro CM in
roro-o
* — it in
Ok
•O CO-*
w w »

w

fvi-gco
r>--,t CM
tM°!n
O (M CM

*— «— CM


SfO^





K) «- in
o>**d-

in «— NO




(0
CD
CO**
CO
il:
ro 3  ID 1—
 H> O
z ca >—




cS
2-





in in «- co
O in CM ro
kkS- «— fc
o
0
i
o

1


.^

'&
u
u
Q.
s
5
0;


o

o
.M
ID

.£"

I)
U
t.
Q_


!>
D)
C
[3.
1



•o
s
'S

-Q
O

to a>
L. U •
10 ••- «—
-^ Q-tj



C 0 ID
0> il) t~
t. — k
I- O O
o a. w

CA
(I)
kv
o















































co

^
ID
M
a>
ID

i5
eo
t>

fc
C/3
-E

,.
0>
U
C.
3
O

C-5
-------
disc_eff.wlc1
TABLE C-4
TOTAL EXPLORATORY OFFSHORE WELLS DRILLED TO JANUARY 1,  1985
Region
                                                                      Number of
                                                                    Exploratory
                                                         Discovery    Wells Per
                          OH      Gas      Dry    Total Efficiency   Discovery
Alaska
California
Oregon
Washington
Federal Pacific
TOTAL PACIFIC
Alabama
Florida
Louisiana
Texas
Federal-GOH
TOTAL GULF OF MEXICO
GRAND TOTAL
20
44
0
0
0
44
0
0
267
45
0
312
376
7
10
0
0
0
10
2
0
349
273
0
624
641
73
294
8
6
38
346
0
24
3999
1732
241
5996
6415
100
348
8
6
38
400
2
24
4615
2050
241
6932
7432
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.14
3.70




7.41





7.41
7.31
 Mote:  Well count includes wells in both Federal  and State waters.
        na = not applicable

 Source:  API 1988;  HHS 1986b.
                                                        C-6
-------
 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    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.

        A 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-4). 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)7936, 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 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 OCS 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 on whether the project is larger or smaller
                                          C-7
-------
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 thai: 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.

       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 fewer (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 the Arctic projects, 40 producing wells is considered typical, thereby
giving the smaller Norton Basin project a production ratio of 0.7.

       Table C-5 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-5 is the model project lease price used in the
economic analysis.
C5  .  REFERENCES
Alaska.  1987.  Alaska Department of Natural Resources, Five-Year Oil and Gas Leasing
       Program, January.
API. 1988. Basic Petroleum Data Book. American Petroleum Institute, Vol. VIII, No. 1,
       January.
                                            C-8
-------
$lease.uk1
21-Dec-92
TABLE C-5
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
Alaska Cook Inlet
Cook Inlet-gas
Beaufort-gravel
Beaufort-plat.
Norton
Navarin
1
4
6
10
18
32
50
14
33
60
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
0.7
1.0
Exploratory
Lease Wells/
Price Discovery
($000) Well
$1,318
$1,318
$1,318
$1,318
$1,318
$1,318
$1,318
$1,423
$1,423
$1,423
$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
3.70
3.70
3.70
3.70
3.70
3.70
Model
Platforms/ Project Lease
Discovery Price ($000)
4.3
4.3
4.3
4.3
4.3
4.3
4.3
2.0
2.0
2.0
.0
.0
.0
.0
.0
.0
$568
$2,271
$3,407
$5,678
$10,221
$18,170
$28,391
$2,236
$5,272
$9,585
$56
$56
$7,097
$7,097
$4,968
$7,097
Note:  1986 dollars.
Source:  EPA estimates.
                                                        C-9
-------
MMS.  1986a. U.S. Department of the Interior, Minerals Management Service, Outer
    •   Continental Shelf Statistical Summary 1986. OGS Report, MMS 86-0122, December.

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.
                                         C-10
-------
                                    APPENDIX D
                     EXPLORATION PHASE 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.  Exploratory costs are apportioned to successful efforts (see Section
D.4). Hence the economic model addresses costs from all phases prior to production and
through the operating life of the project.
D.1    GEOPHYSICAL AND GEOLOGICAL COSTS

       Before a decision to drill is made, 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 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 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-l
-------
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 is discussed in Section C.2.
The discovery efficiencies are repeated in Table D-l for convenience.
D3    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.  The data in Table D-2 include exploratory,
delineation, and development wells (Oshinski, 1988).

       Table D-3 summarizes average well depths and costs. It is apparent 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, which 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.  The average regional well depths shown
here are similar to but not the same as those shown in the Development Document or preamble
because these reflect one year of data (1986) while the Development Document estimates reflect
five years of data.
                                           D-2
-------
disceff2.wk1
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
GRAND TOTAL
Oil
20
44
0
0
0
44
0
0
267
45
0
312
376
Gas
7
10
0
0
0
10
2
0
349
273
0
624
641
Dry
73
294
8
6
38
346
0
24
3999
1732
241
5996
6415
Number of
Exploratory
Discovery Wells Per
Total Efficiency Discovery
100
348
8
6
38
400
2
24
4615
2050
241
6932
7432
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.14
3.70




7.41





7.41
7.31
Note:  Well count includes wells in both Federal  and State  waters.
       na = not applicable

Source:  API 1988;  HMS 1986a.
                                                      D-3
-------



































?
•g
u.
. 1
CO
CM
^
H-
—I
1
S
i
<:
>-
4
0
1—
CO
*— o

• CM -J
4j 1 f

U UJ
— ^ CD CO
CD «C O»
IX »— *-




"CD
4-*
O










l_
Q










CO
CD










_
*o












4-1
CO
o.
CJ


o
en
03
4-J
O
O
U.

CO

 CM sf ro
f>roo CMroin
** N, %o CO O *~ *T
co ro CM CM otn«»
in co N. »o ** *- in
K--S o
T^
o *— >O NO in ** CM
CM CM <3 »- o in in
r- -
in ^o >*• co »o ro CM
ro ro «- CM CM co oo
in^ «^
ro o o in ro N- cvj


0oro0^g;S
•— ro r*» co *~ o*
CM to ro CM co co
c\3 rooooS
o «-^— OCMO
VHA **
CM ro CM o o «—
ro v± o» *o o ro
o* ^f f™1 *Q ^~ in
*" ro S ^S1'1
CM*
*— in f£

*— CM in »o o o o
O COCMN- V>0 V>

O CM in CM -J-
O* *J-O CO
«— •»j- so ro o in o
CM tn tn CM in
tw OK *^ ND ro
N. CM ro N- co
v-CXJCM CM
ro co *-
*-
*-CMCMO oroo
CM -O *-

«— in w— in o O CM
K» «(— O O* N- *•*•
r*- fMOCM CM^
in ro o CM N- «—
•^ %^ CO *"* O O
\o vt  3 •—
t- CO CO O O
O O "* ^^ CO
^£ H- W (0 < i O.
CO '^ '5 X TJ T3 T3
— * CD o cj c5 cy o ro
o o» «—
in oo in
in ro co
O o tn
,-T
CO-O CM
CM»-in
in in r*-
-*rog
M"
tn tn co
to
KSS

cTcM*CM"
!^ro ^
««g
CM in ro
h- o* *•*
*~ro
CM
-CMS*
CM


PinR
in >a- co
Hf
OKI O
N- O in

00 «- O
or» in
*-ro 
1— 1 U.
1 U .1
:*<£ 3
"
g


in
"^
o
o
^
«—
i


ro
CO
in
ro
rt
ro .
in
S
1
S
^
g"
ro
CM"
^
8


0
c^
c5
cT
*3-
O
O ,
CM
O
.g
ro
R
ro


UJ

=
u.
g
_J
_l
<









































CO
^
CO
^> f2
"°c>
11
U CL
t. <:
5

(U
• • U
O t-
2 V)
D-4
-------
o

•8
   8
                           -* o o*» co *O *o *o    o CN o   in
                           CM eo tr\ o- u\ NO eo    eo oj CD   CD
                           in  *O N-    CN O «—   CO

                           cQc*u\a*c>*-?t^   «T»o*«-^   -o in o    <\j «o >o   (M

            o      w      o co O" ro r\j *^ co    CM ox ps   ro
                           ro ""a* o* ro NJ- >o in    \O<\IN.   co
                           XKM OJ ** CO *O -O

                 cj 6
                    o
                   **-

                           o o Nt *- co ro >O    inino   ^

                 	        -* co ro M co co co    «-coK-   ^*
                 c>^-^        »•.•....»....    *««     «










                           in os *o CK ^ «— ro    *- PO in   *-
                           ^N Q£ ^K ^ in CD O*    *~ OA in   CD
                           O U-i CO (\J CH <-3- N-    OS-in   ^O


                 CO—'      *-    OOv3-COCO    ^CQm   O
                 o oj      *-    ru«-mcoco    co co ro   m
                   2      _•>     *.•.(.<»•.     «     oc>v-   o
                 cU4-(      o as in o %o «— in    oinoo   N>
           O    CL*^        • UJ  •»•••     •••     •
                   ^      N-    c\i >o c\j«— po    N-roo*   %o

                           o    forocoSco    incoro   .     •.•.*..•.     «.««
                 ct        o    ooco c\ir«-
                 fr!
                o
 CA—•
 O 0)

U 3
                O 4-1
                "§
.!_ •'"•




flj vx
                                       .
                           co o co sr uj co uj
                        K3
                                                   i1^ in
                                                 - *o in
                                                           in

                                                           a"
                           KJ\jfoc8   »o      SiFJc?
                           r- N. CO in Q£ fO O£
                                    » oc S- a:
                           in ro rooo
                           N* co in co
                           •o in •*> in    ro in
                                to •*«-   >o

                                fcSS   8

                                 "«-^-**   >o*
                                   >*>O   CM
                           K» «—
                           V)«
                                        CO PO    M «-P
                   o    *- CNJ
                CM to    N-in
                «*»    v» w
                             co N- o ce co N-
                             co >o ro uj in f*-
                                                N-eo s.   -j


                                                in N. o   «—
                                                  OJI
                                                  N- C
                          0^ O. CO    "-
                                           u
                              CO      CO H- —

                             'EC   «"3^
                              I- CO   CO O U
                           CO  O "~   —'    CO
                          ^H- co u < i a.
                           CO '— "- CO i     i
                           CO—- D XTJ T3 "D
                          —'  CO O Ol CO CU O
                          «C CJ .J t— u. u. u.
                                —•   u.
                                O t-  i    O
                                I*- I  U-
                                i CJ _1   —I
                                ^ < 13   _J
                                « a. u   <
                                                                     9
                                                                   CA
                                                                   c. o
                                                                   CD C
 O 0( .Q
T> 4JI>-

4,g§

 g-s^

 t— CC Q.
 3 oe <
U UJ


     01
 CA   U

£   ^
 o   o
                                                              D-5
-------
D.4    NUMBER OF PLATFORMS PER DISCOVERY WELL


       The cost of the lease and exploration efforts is shared by 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:


       •     Alaska - one platform per discovery

       •     Gulf - 4.3 platforms per discovery

       •     Pacific - 2 platforms per discovery.



D.5 REFERENCES


API. 1986. 1984 Survey on Oil and Gas Expenditures. American Petroleum Institute,
       Washington, DC, October.

API. 1987a. 1986 Survey on Oil and Gas Expenditures. American Petroleum Institute,
       Washington, DC, December.

API. 1987b. 1986 Joint Association Survey on Drilling Costs. American Petroleum Institute,
       Washington, DC, November.

API. 1988. Basic Petroleum Data Book. American Petroleum Institute, Vol. VIII, No. 1,
       January.

Commerce. 1982. U. S. Department of Commerce, Bureau of the Census, Annual Survey of Oil
       and Gas. 1980. Current Industrial Reports, MA-13k(80)-l, 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. Atlantic Summary/Index;  January 1985 - June 1986. U.S. Department of the
       Interior, Minerals Management Service, 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.
                                         D-6
-------
                                     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 petroleum supply. This usually involves drilling one or more delineation wells.  Not
all projects have a delineation phase. The phase is included in the economic model to capture
the costs and timing considerations for larger projects. Delineation efforts are generally included
in discussions of oil and gas exploration.  Hence there is no need for a separate analysis of
delineation phase impacts.  Delineation wells are included in the number of projected wells; they
are therefore included in the cost of the regulation.                              ,

       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, 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:

       •     Alaska - $13,851,011.
       •     Pacific - $5,887,793.
       •     Gulf of Mexico - $4,354,555.
                                           E-l
-------
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 these data show, the OTA estimates are too high.  In
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, EPA 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, 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. "Gas & Oil Wrapup," Ocean Industry. June.  pp. 113-119.
Ocean Industry. 1986a. "Exploration and development continue in Beaufort Sea," Ocean
       Industry, October,  pp. 34-40.
Ocean Industry. 1986b. "Gulf of Mexico operators respond to new challenges," Ocean Industry.
       October, pp. 15-20.
OGJ.  1984.  "Exxon Wants Big Expansion Unit on North Slope," Oil and Gas Journal. February
       20. pp. 34-35.
                                          E-2
-------
delin.wkl
                                  28-Feb-92
TABLE E-1
NUMBER OF DELINEATION WELLS FOR TYPICAL OFFSHORE PROJECTS
Region
                Field    Block
                                  Number of
                                Delineation
                                      Wells
                                         References
Alaska
Endicott
(Sag River/
 Duck Island)
Seal Island
Sandpiper
Colvilie Delta
Pacific  Sockeye
         Huesco
Gulf of
Mexico
High Island

Vermillion
S. Marsh Is.
Matagorda Is.
Mustang Is.
Green Canyon
         Viosca Knoll
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
                                                  OGJ 1984
                                                  Ocean Industry 1986a
                                                  Ocean Industry 1986a
                                                  Ocean Industry 1986a
                                         PEI  1983
                                         PEI  1983
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
1982
1982
1982
1982
1986b
1986b
1986b
1986b
1986b
1986b
                                                  E-3
-------
Oshinski.  1988. Personal communication between Maureen F. Kaplan, Eastern Research
    .   Group, Inc., and John Oshinski, Statistics Department, American Petroleum Institute, 25
       February.

OTA.  1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of Technology
       Assessment, Washington, DC.

PEL 1983. "The Pacific Coast," Petroleum Engineer International 55, December,  pp. 21-23.
                                          E-4
-------
                                    APPENDIX F
                     DEVELOPMENT PHASE ASSUMPTIONS
       The development phase involves the construction and installation of production structures
 and the drilling of development wells.  The development phase is included in the economic
 model to address timing considerations and costs incurred to produce oil and gas once a
 reservoir has been identified by the exploration and delineation phases. 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.1    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 useful 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...
                                         F-l
-------
       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. 1)

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.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 HI; Oshinski, 1988). 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. 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-l).

       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 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
                                           F-2
-------
Equip.wk1

TABLE F-1
LEASE EQUIPMENT COSTS - GULF AND PACIFIC
»
f
Region Project
Gulf 1b
4
6
12
24
48
58
Pacific 16
40
70
lumber of
'reducing Lei
Wells Co:
1
4
6
10
18
32
50
14
33
60
ase Equipment
sts ($MM 1986)
$1.166
$4.664
$6.996
$11.660
$20.988
$37.312
$58.300
. $16.324
438.478
$69.960
Source:  EPA estimates.
                       21-Dec-92
                                                      F-3
-------
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). 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.

       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, right-hand 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.
                                            F-4
-------
        u>
        I—
        CJ
        ^
        v>
1—      Q.
v>   t— -i
£_—•<-*
4-.^£
CO
5 |
en t- E
'.S8.&
D (0 -M
•a — • to
t- E ^N
O. O CO
s- O

CO (U
t_ E ^
u. O CO
»*- O.
4-» +•• w-
CO (D
S— ' Z
a. SE:
w
H- CO
0 ^* E
CO £-

45 tO -M


z « a.
0)4-»>J-
c c co

r^ s*»-
t- — • 5E
•D o«
1 > ^^
§0
0 4-»
Z CO
o
CJ

c coCT

fcj o*
'r"
•1 1
CO \*f
Q






4^
u
o
*cT
£_
a.
c> «- r*i in o o
in «- CM i^ o o
N. ro >O jg in in


S 5 R S 8 2


N- ** m o o o
K» ** s* O O O
o c\i N. f*- o in


O in t\J o o o
S^O 1A O O O
oj r*— h«- o m
ro in «— r\j *- t»

N> ' r*» ^ CNJ (\i ""d*






•»* in f*» o o o
o^* in o o o o
~- S N- in CM i\j
t>r i"^






exi o co o
*O *Q fl O
•T-  t, to o o
0) (D O O O O
CO Z Z CO CJ O
















,












CO
t.
(D
"o
s

T—
c

2!
CD
CO
4J
s


4t


CO
o
o
=c
                                                                   o


                                                                  4-»
                                                                   fll
                                                                   C
                                                                  O)

                                                                  c.
                                                                  o
                                                                  H-


                                                                  O!
                                                                  C_
                                                                  O
                                                                  4-*
                                                                  10
                                                                  _o

                                                                  §•«•
        §
                                                                          I
                                                                         a:
                                                                          u
                                                                          o

                                                                         £
•gp-   2
 CO 0)   O

5 to   "S
        »f-

        s
                                                                 X £1
                                                                 •4 a
°-3
 x'   i'
.a -    co

-5,2   £
 
-------
F.3    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
development well
Cost per 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.
 F.4    NUMBER OF PRODUCTION WELLS PER PLATFORM

        The number of production wells in use at an offshore platform varies 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 three-fourths to
 five-sixths of its wellslots. Model projects were defined to fall within these bounds.
  F.5    RATE OF INSTALLATION OF DEVELOPMENT WELLS

        EPA 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
                                           F-6
-------
        <


        a
a.
UJ
a
     8u_ ui
        u
 U   UJ <
—•   -Id
—'   ca uj

 $   S3
              i  £• ^> t     "^ ^3 Q* (Q \Q *n *A   c) O* o   in
              *  5> W i      *o o <3> N-   o o «—   oo

              •  4-* •—* i     co o in o* o f* ^-   co ^o *™   s^1

              i  O CJ i     Sf- N» ^ O K) CO in   N>(MO   O











           O  i    «  i     O CO O FO (M «- CO   CM O O   «M
          i—  t  4-* v^ i     ro s? o to o in   >Q t\j r-*.   co

              I CJ O  1     V>«WW^»W»   4A4A4A   4*

            .  i    O  i               tfl '
              I    H-  i
              t       I





              1 O    i    O ^ O «-CO «—%O   O *O O    cT

              It                 *~     *^   ^    *~
             I       I

                     I
                     t
                     I


             'IJ;^1    jnc*NOO%o«-fo   «-rom    «-
             » fP O

             1 *^ —'  •    *O   K» «— O >O N-   *- N- >»   CO
             > eg —'  i    t—   o o «* co co   in co tn   o

             ' «S S  i    *^   tV*~p(^*°*   eoS>ro   in
             t       t    o
             i       i    <—

             i       i
             i       i
             i       i


          >.i  t-^i    tnoeroinojoo   oo*-

          a  !  8.^ I    °£1^0;'0.^^   ^^5*2

            •  •»-» 2» I    !*   ^g*^*-^   r^MO*




            i    O i    ^        ^         M

            l    H- l

            I       I
            ' J— **^ '    (M Q£ CO O CO *"" PO   *O fi ^~
            t4-*4-*i    •OC^CQCO^<}O<)   CoQJiN.
            i  Q.*^  i    ->O UJ CO CO CO fO O   ^- O ^

            tO    i    O*   OC*€Qi   o «—
                    .  0)

                    i  O
                    i  CJ
                 U>  i  <- r* i
                 to  i  ei 4J i
                 (3  i  Q.H- i
               '« :
                 O i
            •  an- .    rC^cSS
            i  d> *-* i     ........
            i  O    i    N- >O O «—   O
2L£:


u) ^  i
O 0}  i
U 3  •
                                                      ~

                                            JoSo   o
                          Rf
                       ^  ^orut>
                       N- *O O O UJ CM N
                                    -o M
                                    OK-
                                    CM in
                            CM
                            M
5s?    O   ^ f\J   fO ^O N*   frt

                            S8   fe»   8»S   S
                                     > ro ujin

                               o'^oToo"   ^
                                             K
                                             co c
               §i
                         o
            (0      ID H- —

            'EC    io ^ .t    _1 < P
            t.0    (000    <»-O
          njo-»-    —*    a)    t— o >—
         ^H-eocA o a> v    ^
-------
dev disc
TOTAL DEVELOPMENT OFFSHORE WELLS DRILLED TO JANUARY 1,  1985


	                      Number of
                                                                           Development
                                                             Discovery       Wells Per
                                   Gas      Dry    Total     Efficiency   Producing^Well
Alaska
California

Alabama
Louisiana
Texas
Federal-GOM
TOTAL GULF OF MEXICO
259
3516

8144
104
69
8318
13
25
4
4283
454
19
4757
32
327
1
4480
700
58
5239
304
3868
3
16907
1258
146
18314
0.89
0.92
0.67
0.74
0.44
0.60
0.71
1.12
1.09

1.40
 Hotei"well count includes wells in both Federal  and State waters.


 Source:  API, 1988.
                                       F-8
-------
devjcost.wkl



DEVELOPMENT WELL COST - 1986 DATA*

Region
Gulf
Pacific
Alaska

Type of
Production
oil, oil/gas
gas
oil, oil/gas
gas
oil, oil/gas
gas
Number of
Development
Wells Per
Producing
Well
1.4
1.4
1.09
1.09
1.12
1.12
Average
Depth
(ft)
9,885
11,174
6,872
6,477
10,868
7,721
Cost per foot <$/ft>
Productive Dry
$340.37 $389.81
$408.05 $389.81
$267.98 $833.59
$721.18 $833.59
$335.47 $1,507.90
$231.95 $1,507.90
Composite Cost
per
' Development
Well ($)
$4,905,866
$6,301,845
$2,357,117
$5,157,007
$5,612,431
$3,187,985
 Note:  Current dollars.
 Source:   EPA estimates,  see Table D-2.
                                                   F-9
-------
 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.

API. 1987b. 1986 Survey on Oil and Gas Expenditures. American Petroleum Institute,
       Washington, DC, November.

API. 1988. Basic Petroleum Data Book. Vol. VIII, No. 1, American Petroleum Institute,
       Washington, DC, January.

Economic Report. 1987. Economic Report of the President. 1987.  Council of Economic
       Advisors, Washington DC, January.

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.

Ocean Industry. 1987a. "Giant fields set to boost California, Alaska output," Ocean Industry.
       October,  pp. 27-33.

Ocean Industry. 1987b. "Endicott oilfield development is on schedule," Ocean Industry.
      August/September,  pp. 25-26.

Offshore. 1986. "The World Offshore:  Alaska," Offshore. July. p. 11.

OGJ.  1986. "New Cook Inlet platform to get drilling modules," Oil and Gas Journal. 17
      November,  p. 32.

Oshinski. 1988. Personal communication between Maureen F. Kaplan, Eastern Research Group
      Inc., and John Oshinski, Statistics Department, American Petroleum Institute,
      Washington, DC, 25  February.

OTA. 19S5. Oil and Gas Technologies  for the Arctic and Deepwater. Office of Technology
      Assessment, Washington, DC, May.
                                         F-10
-------
                                   APPENDIX G
              PROPUOTPN/OPERATION PHASE ASSUMPTIONS

       Hie production and operation phase of an offshore project encompasses the period of
time from first oil or gas production until shutoff of all wells.  It is during this phase that
revenues are accrued. The project shuts down when the revenues for the year are insufficient to
cover that year's costs. Project lifetime determines,  in part, the amount of oil and gas produced,
as well as total revenues  for the project.

       Parameters required to define this phase include:
       a     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.1    PEAK PRODUCTION RATE

       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 rate and production decline rate 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-l
-------
       6.1.1 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 varies by region. 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).

       To use the information in the EIS in this analysis, we begin by examining at the
cumulative production per well.  This ranges from 470,000 bbl to 1,579,000 bbl per well. Gas
production ranges from 5.3 BCF to 10 BCF (MMS, 1986 and 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 of Mexico 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.

                                           G-2
-------
                            J O. «-N->O O. O i
                        >flOfr-J"OKlCO'- I
                        o»oo«— o*»«-co •
         $
                       »- O IN) CO «-«-«-«-
               '£
                       OOOOOOQOi
                       IA f*» >* N. r— N- CO ^ i
                       *""• CO CO 00 ^O CO *^ f"" i
               2
                       OOOOOOOO i
                       <> »o <\i o *- CM ro rg .
                       f\J «- 0 jr- CM «>
                      ^O N. ^ O **N- v- N3-
                      ru «— AJ ^ «— rvi

                      ** fM PO -O CM s3-
                     ~a t-~m    E
                     i;S«   £
                     £S£    S
                     030   3
                                              I


                                              CO
                     OCJM   in
         u  at
         o — i <
§
(A
                                             G-3
-------
       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 4 years
at peak production. Cumulative production 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.1.2 Pacific

       The California Department of Conservation maintains records of oil and gas 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 at 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.
                                           G-4
-------
ca_prod.uk1
                               27-Mar-92
TABLE G-2
PEAK PRODUCTION RATES - CALIFORNIA
Field
                  Year of
                  Peak
                  Production
               Peak Production
               bopd or Mcf/day
OIL PRODUCTION

Beta
Hondo
Hueneme
Santa Clara

Average oil
1981
1981
1982
1980
   535
 2,840
 1,074
   286

 1,184
GAS PRODUCTION

Pitas Pt.
1985
11,185
Source:  Guerard, 1988.
                                                G-5
-------
ca_og.wk1
                              27-Har-92
TABLE G-3
1986 GAS TO OIL RATIOS - CALIFORNIA



Region
State


Federal








Field or Area
District 1
District 2
District 3
Beta
Carpinteria
Dos Cuadras
Hondo
Hueneme
Santa Clara
1986
Oil and
Condensate
(bbl)
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
1986
Associated
Gas
(Hcf)
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

Gas to Oil
Ratio
(cf/bbl)
245
2316
790
347
771
505
934
277
1256
TOTAL
63,353,459    33,621,541
                                                                531
Source:  California, 1987.
                                                 G-6
-------
        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. We use 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.

        Arctic Alaska

        The Endicott field in the Beaufort Sea began production in late 1987. Sixteen wells
 began production in October 1987.  Table G-5 summarizes the November and December
 production from those wells, i.e., the first two full months of production.  Production is likely to
 drop from the impressive 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.

       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). EPA 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 represents 10 to 15 percent of total reserves for the first 2 years and then
declines approximately 15 percent per year (Muskat, 1949; North, 1985).
                                          G-7
-------
cook.wkl





AVERAGE'FIRST-YEAR PROOUCTIOM FOR OIL WELLS  IN  COOK  INLET, ALASKA
Completion Date
Platform
Dolly Varden








Grayling









King Salmon




Year Hon
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
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
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) Gas (Hcf)
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
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 Daily
Production
Oil (bbl) Gas (Kef)
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
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-8
-------
endicott.wkt
27-Mar-92
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 (bbl)
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-9
-------
                               TABLE G-6

        ENGINEERING ESTIMATE OF PEAK PRODUCTION RATES - ALASKA
                                               PEAK
                                           PRODUCTION RATE
DATA SOURCE REGION
EIS St. George Basin
N. Aleutian Basin
Norton Basin
Scenario Studies Norton Basin

Beaufort Sea
Norton Basin
Navarin Basin
OIL GAS
BOPD MMCF/DAY SOURCE
4,000 26.3
3,500 26.6
1,570 10.3
3,000-
4,000
4,000
2,000
4,000
MMS 1985a
MMS 198 5b
MMS 1985C
MMS 1985d

OTA 1985
OTA 1985
OTA 1985
Source:  AEI noted.
                                  G-10
-------
                                   TABLE G-7

                 PEAK OFFSHORE PER-WELL PRODUCTION RATES
 REGION
 Gulf
 Pacific
                         PROJECT
  1
  4
  6
 12
 24
 40
 58

 16
 40
 70
Alaska3
  Cook Inlet

  Beaufort Sea - Gravel
  Beaufort Sea - Platform
  Norton
  Navarin
12
24
48
48
34
48
       OIL ONLY
         BOPD
   500
   500
   500
   500
   500
   500
   500

   900
   900
   900
1,960
1,960
1,960
1,960
1,960
                                                  OIL AND GAS
                                                BOPD    MCF/DAY
   500
   500
   500
   500
   500
   500
   500

   900
   900
   900
1,960
                                                            478
                                                            478
                                                            478
              900
                                 GAS-ONLY
                                  MCF/DAY
835
835
835
835
835
835
835
4,000
4,000
4,000
4,000
4,000
4,000
4,000
5,000
                                  15,000
Source:   EPA estimates.

           is no infrastructure to transport produced gas from the Arctic
                                    G-ll
-------
       The decline rate for the Pacific is based on the need to balance to conflicting sets of
information. The decline rate used in the MMS estimates of future production use a 40%
decline rate (MMS, 1985e). Since this information is the basis for the NSPS projections
presented in Section 4, it is necessary that the decline rates used in the models be very similar in
order to maintain comparability between the two sets of projections.  EPA reduced the decline
rate to 33% in response  to the field data presented in DOE, 1989.  Decline rate assumptions are
summarized in Table G-8.

G.3    YEARS AT PEAK PRODUCTION

       The length of time each well remains 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.
 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 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, and/or dehydrators/line heaters (for gas operation)
 located on the platform surface. The third cost category is workover costs. For a 12-wellslot
                                           G-12
-------
                                 TABLE G-S

                        PRODUCTION DECLINE RATES
                                             PRODUCTION DECLINE RATES (%)
REGION
                 PROJECT
                       OIL-ONLY
                       OIL/GAS
                                                                   GAS-ONLY
Gulf
Pacific
Alaska
 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 Bagin               10
Navarin Basin              10
15
15
15
15
15
15
15

22
                                                                        15
— = Not applicable.

Source:  EPA estimates.
                                     G-13
-------
                                  DRILY  GflS.  MCF/DflT
                                                      X1D3
100
           so
                      0 1000
                                                                             I
                                                                              2
                                                                              a,
                                                                             *
                                                                             ffi
                                                                             t>
                                                                             HH
                                                                              6
                                                    Jf


                                                    I




                                                     1
                                                     o
iba         so         a looo

  NO. OF  PROD.  HELLS
       too           10

DfULT  HflTER.  BBLS/DflT
                                G-14
-------
 gulf_o&m.wk1
              27-Har-92?
TABLE G-9
1986 PPERATION AND MAINTENANCE COSTS FOR GULF OF MEXICO PLATFORMS
Wellslots
     Water
Depth (ft)
      Cost
  (1986 S)
         12
         12

         18
         18
         18
       100
       300

       100
       300
       600
12,366,500
$2,482,300

$2,833,400
$2,963,100
$3,268,100
Source:  DOE, 1987.
                                              G-15
-------
OiH_gulf.wk1
ANNUALGOPERAnHG COSTS - 12-SLOT PLATFORM IN GULF OF MEXICO
100 FT WATER DEPTH (1986$)

Component
Labor Subcategory
Labor
Supervision
Payroll Overhead
Food Expense
Labor Transportation
C annum cat ions

Component Subcategory
Cost ($) Cost ($>
$1,265,200
$528,900
$79,300
$211,600
$55,200
$374,700
$15,500
Model Projects
Gulf 1 Gulf 4 Gulf 6
$770 $140,578 $210,867


Equipment & Administrative Subcategory
  Surface equipment                     $84,600
  Operating Supplies                    *lf'|22
  Administrative                       $*IHS2
  Insurance                            $252,200
                $605,900
Workover Subcategory
  Uorkover
SUBTOTAL COSTS
Costs  for operation of  remote
  production platform
 TOTAL COSTS
  $495,400      $495,400
$2,366,500    $2,366,500
                                                                    $50,492   $201,967  $302,950
$148,620   $346,780   $396,320
$199,882   $689,324   $910,137
$172,331
                                     $2.366,500    $2,366.500      $372,213   $689,324   $910,137
 Source:   DOE,  1987.
                                                 G-16
-------
 platform, it is assumed that the workover rig takes one day to travel to the platform, two days to
 set up, nine days to 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.

       These assumptions make it inappropriate to use 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 categories 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 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 the 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 the hours required for the Gulf 12 platform.  The labor
 costs for the Gulf 4 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 costs borne each year is (9/2)/15 or 30 percent.
The Gulf 4 and Gulf 6 projects are assumed to have  an average of one and a half and two wells
worked over 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 O&M
                                          G-17
-------
0&H_gulf.wk1
TABLE G-11
LABOR ASSUMPTIONS FOR SHALL GULF PROJECTS
Labor Component
                            DOE/EIA
                              Study
                      Model Project
               Gulf 1   Gulf 4    Gulf 6
Hours per Day
Days per Year
People per Crew
Person-hours per Year
Fraction of DOE/EIA study
     24
    365
     12
105,120
    100*
   8        8
   4      365
   2        4
  64   11,680
0.06X   11.11%
     8
   365
     6
17,520
 16.67X
Source:  DOE, 1987; Funk, 1989.
                                             G-18
-------
 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)

 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 and Cook Inlet 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.  For Cook Inlet
 scenarios, a multiplier of 1.6 is used (EPA, 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: iQSfi
       Department of Conservation. Division of Oil and Gas, Publication No. PR06,1987.
Crawford. 1988. Personal communication between Maureen F. Kaplan, Eastern Research
       Group, Inc. and Gerald Crawford, MMS, GOM Regional Office, New Orleans, LA, 4
       March and 7 March.

DOE.  1986.  Natural Gas Annual 1985. U.S. Department of Energy.  Energy Information
       Administration. DOE/EIA-0131(85), November.
                                         G-19
-------
gulf_o&m.wk1


OPERATING COSTS FOR GULF OF  MEXICO PLATFORMS
Project
                             Nunber  of
                             WeUslots
         Water
     Depth  (ft)
             Cost
           ($1986)
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6

Gulf 12
Gulf 24
Gulf 40
Gulf 58
 1
 1
 4
 6

12
24
40
58
 33
 33
 33
 33

 66
100
200
590
  $372,213
  $199,882
•  $689,324
  $910,137

$2,311,861
$3,310,725
$4,688,455
$6,471,456
Source:  EPA estimates.
                                                G-20
-------
gulf_o&m.wk1

TABLE G-13
OPERATING COSTS FOR PACIFIC AND  COOK INLET PLATFORMS
Project
Pacific 16
Pacific 40
Pacific 70
Cook Inlet 24
Cook Inlet 12
Number of
Uellslots
16
40
70
24
12
Water
Depth (ft)
300
300
1000
50
50
Cost
($1986)
$2,831,820
$4,772,439
$7,786,100
$3,268,733
$2,298,424
Regional
Cost
Factor
1.44
1.44
1.44
1.60
1.60
Estimated
Cost
($1986)
$4,077,821
$6,872,312
$11,211,984
$5,229.973
$3,677,478
Source:  EPA estimates.
                                                 G-21
-------
ca cost.vikl
                                          27-Har-92
RATIO OF11986 OPERATION & MAINTENANCE COSTS - CALIFORNIA AND GULF COAST
    Well     Operation & Maintenance Cost - 10 Primary Oil Wells

    (ft)       California    Louisiana   West1 Texas  South Texas  Average Gulf
California/
Gulf Coast
Ratio
2,000
4,000
8,000
10,000
.
$119,700
$162,400
$280,200
$403,700

$117,600
$171,700
$203,000
$252,800

$88,300
$102,200
$141,700
$188,900

$98,500
$146,500
$175,100
$232,400

$101,467
$140,133
$173,267
$224,700

1.18
1.16
• 1.62
1.80
1.44
Source:  DOE, 1987.
                                                G-22
-------
ak_o&m.wk1

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 ($HM 1984) Platforms
$168.0
$132.0
$73.0
$120.0
7
7
4
7
Cost per
Platform
($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 5.56% based on change  in consumer price index.

Sources:  OTA, 1985;   Economic Report.  1988.
                                              G-23
-------
DOE.  1987. Costs and Indices for Domestic Oil and Gas Field Equipment and Production
       Operations 1986.  U.S. Department of Energy. Energy Information Administration.
       DOE/EIA-0185(86), September.

DOE 1989  Department of Energy Comments on the Technical, Economic, and Environmental
       Data Made Available in 53 FR 41356 on October 21,1988 for the Offshore Oil and Gas
       Subcategory Effluent Guidelines, January 19.

Economic Report.  1988. Economic Report of the President. Council of Economic Advisors,
       Washington, DC, February.

EPA.  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.

Guerard.  1988. Personal communication between Maureen F. Kaplan, Eastern Research Group,
       Inc., and William Guerard, California Department of Conservation, 2 March.

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.

MMS. 1985a.  U.S. Department of the Interior, Minerals Management Service, St. George Basin
       Sale 89: Final Environmental Impact Statement. MMS 85- 0029, April.

MMS. 1985b.  North Aleutian Basin Sale 92:  Final Environmental Impact Statement. U.S.
       Department of the Interior, Minerals Management Service, MMS 85- 0052, September.

MMS. 1985c.  Norton Basin Sale 100:  Final Environmental Impact Statement. U.S. Department
       of the Interior, Minerals Management Service, MMS 85-0085, December.

MMS. 1985d. Scenarios for Petroleum Development of the Nnrtnn Basin Planning Area -
       Northeastern Bering Sea. U.S. Department of the Interior, Minerals Management
       Service, OCS Report, MMS 85-0013.

 MMS. 1985e. Certain Input Values Used in the 30-Year Projection of Future Oil and Gas
       Production from United States Outer Continental Shelf Areas. Attachment to 30-Year
       Projections of Oil and Gas Production from United States Outer Continental Shelf
     •  Areas. Memorandum from Chief, Offshore Resource Evaluation to Associate Director
       for Offshore Leasing. U.S. Department of the Interior.  U.S. Minerals Management
       Service.

 MMS. 1986.  Final Environmental Impact Statement: Proposed Oil and Gas Lease Sales 110
       ' and 112:  Gulf of Mexico  OCS Region. U.S. Department of the Interior, Minerals
        Management Service, OCS EIS, MMS 86-0087, November.
                                          G-24
-------
MMS. 1987a.  Final Environmental Impact Statement: Proposed Oil and Gas Lease Sales
       113/115/116:  Gulf of Mexico PCS Region. U.S. Department of the Interior, Minerals
       Management Service, OCS EIS, MMS 87-0077, October.

MMS. 19875.  Federal Offshore Statistics:  1985. U.S. Department of thP TnfPr.w
       Management Service, OCS Report, MMS 87-0008.

Muskat, M. 1949. Physical Principles of Oil Production. McGraw-Hill, New York, NY.

North, F.K. 1985. Petroleum Geology. Allen & Unwin, Boston, MA.

OTA. 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office
      Assessment, Washington, DC, May.

USGS. 1981. United States Geological Survey. Circular 860.
                                        G-25
-------
-------
                                    APPENDIX H
                       PRODUCED WATER ASSUMPTIONS
       Peak water production is used in determining the equipment required on the platform to
 comply with 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 annual average volume of produced water
 generated during the 15-year 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, Engineering and Analysis 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.1    MODELING ASSUMPTIONS

       Modeling assumptions differ depending upon whether a well produces oil or only gas.
These assumptions are outlined in the sections below.
       H.1.1  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
                                         H-l
-------
       •      Functional form of oil production decline
       •      Decline rate of oil production
       •      Initial watercut (i.e., percentage of water in the initial production fluid)

       Oil production is assumed to decline at an exponential rate. The rate of decline varies by
region (see Appendix G for more details). As oil production declines, water production
increases to mamtain 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 watengas ratio.  Water production for gas
wells is assumed to be a function of gas production times a watengas ratio. A constant watengas
ratio was used in the economic impact analysis of the disposal of onshore production wastes
under Section 8002(m) of RCRA (EPA, 1987).

       An Appalachian basin survey is the only survey that investigates water production from
gas wells (Flanriery 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 watengas ratio of 17.2 bbl per MMcf.
                                           H-2
-------
BARRELS

     120
     100
                      Figure H-l

             Water  : Oil Relationship
                 Exponential Oil Decline
       0   2  4  6  8  10 12  14  16  18 20 22 24  26  28 30
                           H-3
-------
  3
  a:
UJ —
_j i—
CD •-
                                                                        CO
                                                                        1C
                                                                        UJ


                                                                        L.
                                                                        O
                                                                                       CD

                                                                                      "5.
                                                                                       g      O
                                                                                       03      —•
                                                                                     !°
                                                                                     18
                                                                                  co *j eg  •
                                                                                     StD *O &•
                                                                                    •- OsO

                                                                                  08^£
                                                                                  o» to C
                                                                                  .e en ••— t_
                                                                                  *-» m    o
                                                                                  0)  - CO 4J
                                                                                  C.T3 4-< <0
                                                                                  CD 0> » •»-
                                                                                               g

                                                                                              I
                                                                                               m

                                                                                              UJ
           1

           o
           L.
           a.

           a>
           8.
           (U  •
           '-§
           sl
                                                                                  — C c_ C    O u
                                                                                     O O O    C-JJ
                                                                                  JC ._ S- —    0,0)
                                                                                   E u> -  t-
                                                                                   L. CO Q. 01
                                                                                   O O)— -u
                                                                                  H-   «-- CD
           "3. £
           '> O
3 •-* ••-     "D '
' C .£= O    C
            i
            UJ
                                            H-4
-------
        For comparison, the waterrgas 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 fourfold from 1985 to 1986. The 1986 waterrgas ratio for gas wells in
 State waters is 16.2 bbl per MMcf, which is similar to the ratio from the Appalachian basin.  The
 waterrgas ratio for gas wells in State waters climbs another fourfold from 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
 waterrgas ratios range 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 watengas 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 waterrgas  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 revealed 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 waterrgas ratio
 seen in the offshore and onshore data is about 67 bbl of water per MMcf produced. This high
value, however, 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 waterrgas ratios seen for the Alaska data, offshore Federal California gas wells, and offshore
                                           H-5
-------
1000
          DRILY  CHS.  MCF/OflT


              100	   10
                             X1Q3
                                                                   i
                                                                   §
                                                                   CO
  1000
      ico	      »o


GflILT HRTER.  BBLS/OflT
                  H-6
-------
 h20_gas.wk1
 TABLE H-2
 OFFSHORE  WATER:GAS  RATIOS  -  CALIFORNIA
Year
1985


1986

1987


Number
Region of Wells
State
Federal
Combined
State
Federal
Combined
State
Federal
Combined
6
15
21
6
15
21
4
18
22
Gross Gas
Production
(Hcf)
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 Water:0i I
Production Ratio
-------
State California gas wells for two of the three years of data. The 17 bbl/MMcf is the watengas
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 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 in Year 19 is 104,088 bbl/day.

       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 is 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.
                                           H-8
-------
h20 mex.ukl
                                                           27-Mar-92
TABLE H-3
WATER PRODUCTION ESTIMATES - GULF OF MEXICO
GULF 24 MODEL
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
 15% decline rate
  1% initial watercut
 18  producing wells.
                                              H-9
-------
peakji20.wk1
                                                      21-Dec-92
TABLE H-4
PEAK WATER PRODUCTION RATES - EXISTING AND PROJECTED  STRUCTURES
Project
Type     Region   Model
                       Economic Lifetime
                       of Project (Years)

                       Existing Projected
                  Peak Water Production
                     Rate per Project
                        (bbl/day)

                    Existing    Projected
OIL
ONLY









Gulf







Pacific


Cook Inlet*
Beaufort
Platform
Beaufort Island
Navarin
Norton
OIL
AND
GAS








Platform
Platform
Gulf


,




Pacific


1a
1b
4
6
12
24
40
58
16
40
70
24
48
48
48
34
1a
1b
4
6
12
24
40
58
16
40
70
13
17
18
18
16
18
20
22
8
9
11
**
**
**
**
**
14
18
19
19
17
19
21
23
8
9
11
15
19
20
20
18
20
22
24
9
10
12
30
28
30
30
27
16
20
21
21
19
21
23
25
9
10
12
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
**
**
**
**
**
434
468
1,894
2,841
4,582
8,489
15,312
24,161
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
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
      Cook Inlet*
              24
                                            30
                                    37,449
GAS
ONLY
   Gulf       1a
              1b
               4
               6
              12
              24

   Pacific    16

Cook Inlet*   12
14
18
19
20
17
19

11
16
20
21
21
19
21

13

29
   68
   68
  272
  408
  680
1,224

1,190
   68
   68
  272
  408
  680
1,224

1,190

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, or  Norton 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:  EPA estimates.
                                                 H-10
-------
 H.3   AVERAGE WATER PRODUCTION

       H.3.1  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 davs/vr  /    1000
              Economic lifetime of model project
or,
              112.667
* 365 /j
                     20  /
1000 = 2,056 kbbl/yr
                                                      Average
                                                      annual
                                                      water
                                                      production
                                                      (kbbl/yr)
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.
       H.3.2 Projects with Gas-Only Production

       For average water flow rates, regional average watengas 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 projects.  For Alaska, a 1:1  ratio is used, based on

                                           H-ll
-------
avg_h20.wk1
                                        21-Dec-92
TABLE H-5
AVERAGE ANNUAL WATER PRODUCTION RATES - EXISTING AND PROJECTED STRUCTURES
Project
Type     Region   Model
         Economic Lifetime
         of Project (Years)

         Existing Projected
                             Average Annual
                        Water Production
                           Rate per Project
                              (kbbl/yr)

                        Existing   Projected
OIL Gulf
ONLY






Pacific


Cook Inlet*
Beaufort Platform
Beaufort Island
Navarin Platform
Norton Platform
la
1b
• 4
6
12
24
40
58
16
40
70
24
48
48
48
34
13
17
18
18
16
18
20
22
8
9
11
**
**
**
**
**
15
19
20
20
18
20
22
24
9
10
12
30
28
30
30
27
90
107
443
665
994
1,939
3,505
5,486
2,358
5,213
9,324
**
**
**
**
**
99
114
469
703
1,071
2,056
3,696
5,767
2,579
5,720
10,128
9,247
17,100
17,766
17,766
12,054
OIL
AND
GAS
         Gulf
         Pacific
1a
1b
 4
 6
12
24
40
58

16
40
70
14
18
19
19
17
19
21
23

 8
 9
11
      Cook Inlet*   24
16
20
21
21
19
21
23
25

 9
10
12

30
   95
  111
  456
  685
1,034
2,000
3,604
5,631

2,358
5,213
9,324
   104
   117
   480
   720
 1,105
 2,109
 3,782
 5,893

 2,579
 5,720
10,128

 9,247
GAS
ONLY






Gulf





Pacific
Cook Inlet*
la
1b
4
6
12
24
16
12
14
18
19
20
17
19
11
**
16
20
21
21
19
21
13
29
6
5
20
28
54
89
112
**
6
5
18
27
49
81
98
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,
          or Norton 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:  EPA estimates.
                                               H-12
-------
 the data from the North Cook Inlet field (see Section H.1.2; this value is rounded upwards to a
 1:1 ratio).  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 watengas
 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 is 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.4.1 Existing Structures (BAT)

       Gulf of Mexico

       The number of structures in production in the Gulf of Mexico is presented in Table H-6.
The count include both structures in State and Federal waters. The data sources and
methodology used to derive the count of structures likely to incur BAT costs is described in
Section Four.
       The estimated annual water production for projects in the Gulf of Mexico is 903 million
bbl/yr (see Table H-7). 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
                                          H-13
-------
TABLE H-6

BAT STRUCTURES IN OFFSHORE WATERS
BASED OH 4 NAUTICAL MILE CUT-OFF
Number of Structures
Project Type
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 16
Pacific 40
Pacific 70
Pacific Totals
Totals
Oil Only
Gas Only
Oil and
Gas
Within Beyond Within Beyond Within Beyond
102
11
26
1
0
0
0
140
0
0
0
0
140
43
10
18
18
22
5
1
117
0
0
0
0
117
151
30
13
3
0
0
0
197
0
0
0
0
197
376
240
163
157
104
39
0
1079
1
0
0
1
1080
27
16
16
2
4
8
0
73
7
0
7
14
87
195
82
104
125
215
188
2
911
1
5
11
17
928
Total
Within Beyond Total
280
57
55
6
4
8
0
410
7
0
7
14
424
614
332
285
300
341
232
3
2107
2
5
11
18
2125
894
389
340
306
345
240
3
2517
9
5
18
32
2549
           There are currently no facilites  in the Atlantic region.
           There are no facilities in the Alaska  region that do not already re-inject their produced water.
Notes:


Sources:   EPA estimates; HHS, 1988; CCC,  1988;  SAS runs dated July, 1990.
                                                  H-14
-------
TABLE H-7

ESTIMATED AVERAGE ANNUAL PRODUCED WATER GENERATED BY PROJECTS
IN THE GULF OF MEXICO
Structure
Type
Oil
Gulf 1a
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
Total
Average Annual
Water Production
Per Project
Number (kbbl/yr)

145
21
44
19
22
5
1
0

222
98
120
127
219
196
2
0

527
270
176
160
104
39
2.517

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

Water
Production
Per Project
Ckbbl/yr)

13,050
2,247
19,492
12,635
21,868
9,695
3,505
0

21,090
10,878
54,720
86,995
226,446
392,000
7,208
0

3,162
1,350
3,520
4,480
5,616
3,471
903,428
 Source:   EPA estimates.
                                                  H-15
-------
IN REPLY
REFER TO:
                                  ATTACHMENT H-I
          WATER PRODUCTION IN THE FEDERAL GULF OF MEXICO - 1987 DATA
              United  States Department  of the  Interior

                         MINERALS MANAGEMENT SERVICE
                            ROYALTY MANAGEMENT PROGRAM
                           PRODUCTION ACCOUNTING DIVISION
                                   P.O. BOX 17110
                              DENVER, COLORADO 80217
PAD/RGB
Mail Stop 657
                                                            .'JAN 2 7 1939
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,
                                       %'chael A.^ilUr, Chief
                                       Reporter Contact Branch
                                    H-16
-------
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 58 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.
       California

       The categorization of structures off the California coast is done on the basis of the
number of available wellslots. Table H-6 lists the number of structures by category, while
Table H-8 presents the estimated annual water production.

       The 1987 water volumes for the Federal OCS and the Huntington, South Elwood,
Summerland, and Carpinteria fields were added for an actual count of 107 million barrels.  The
estimated water production is 213 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
       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 to comply with State requirements. No BAT costs, therefore, are
incurred by existing Alaska projects.
                                           H-17
-------
TABLE H-8

ESTIMATED AVERAGE ANNUAL PRODUCED WATER GENERATED  BY PACIFIC PROJECTS
   Structure
     Type
Number
  Average Annual
Water Production
     Per Project
       (kbbl/yr)
      Water
 Production
Per Project
  
Oil

Pacific 16
Pacific 40
Pacific 70

Oil with Gas

Pacific 16
pacific 40
Pacific 70

Gas

Pacific 16
     8
     5
    18
    .1
                      2,358
                      5,213
                      9.324
           2,358
           5,213
           9,324
                        112
     18,864
     26,065
    167,832
                                              112
Total
                        32
                                          212,873
Source:  EPA estimates.
                                                H-18
-------
       H.4.2 Projected Structures (NSPS)


       Section Four presents the methodology used to project the number of structures for the

15-year time period after the regulation goes into effect. Table H-9 summarizes the number of

structures under the $21/bbl oil price scenario. Table H-10 lists the annual average volume of

water produced during this tune period.  The average annual volume of water produced is

approximately 454 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.

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.

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.

CCC.  1988.  Oil and Gas Activities Affecting California's Coastal Zone. California Coastal
       Commission, 2nd edition, December.

ERG.  1987.  Report to Congress, Management 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.

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.

Lowenhaupt. 1989. Personal communication between Maureen F. Kaplan, Eastern Research
       Group, Inc., and Jake Lowenhaupt, MMS, Gulf of Mexico Office, 9 January.

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.

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.
                                          H-19
-------
TABLE H-9

NSPS STRUCTURE ALLOCUTIONS
$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-Hiles
Total

23
60
43
14
0
0
Oil

0
27
15
14
0
0
Gas

23
33
28
0
0
0
Beyond 4-Miles
Total

53
175
80
166
114
27
Oil

12
62
19
70
62
27
Gas

41
113
61
96
52
0
Alaska
          Cook Inlet 12             101
          Cook Inlet 24             110
          B. Gravel Island*         220
Total Platforms - All Regions     759      311      448          142       58

*  Oil only; all other projects are assumed to produce oil  and casinghead gas.
 0
 0
 0

84
  1
  1
  0

617
  0
  1
  0

253
  1
  0
  0

364
                                                   H-20
-------
TABLE H-10

ESTIMATED AVERAGE ANNUAL NSPS WATER PRODUCTION
S21/BBL RESTRICTED DEVELOPMENT SCENARIO
Average Annual
Project Water Production Number of
Type Model 
-------
-------
                                    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
 EPA 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

                                          1-1
-------
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.


       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 fomiula is referred to as the Economic Limit Factor (ELF).


       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 xWD
                                    PEL

             (ELF  =  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/well is
used for the economic limit (PEL) in this analysis (Logsdon, 1988).
                                           1-2
-------
      As an example, suppose monthly production is 50,000 barrels. Then the ELF is:

                                        460x30
                                        9,000

                           /    9.000
                    ELF = (l -  50,000

                    =  (0.82)1'533 = .74
      If the ELF is greater than 0.7, then the tax rate is the nominal rate. If 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.
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.
                                           1-3
-------
Three thousand Mcf/day/well or 90,000 Mcf/month/well 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.
L3    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, Hie 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 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.
                                           1-4
-------
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%
       YearS  8.93%
       Year 6  8.92%
       Year?  8.93%
       YearS  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).
1.6    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.
                                          1-5
-------
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 ejrpensing 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  _
          in Year X
 Depreciation in Year X
                YearX
(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:
                                           1-6
-------
              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 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 EPA 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
       S
       U
adjusted basis of leased property
units sold during the period
units remaining at the end of the period.
                                          1-7
-------
        The initial basis of the property used in the EPA 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 downwards to account for the depletion taken in each
 period. The portion of the adjusted basis taken as depletion in any 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).
                                          1-8
-------
 1.13   WINDFALL PROFITS TAX

       A phaseout of the Windfall Profits Tax of 1980 began in January 1991. Though the low
 price of oil, however, meant it had no effect in recent years. For these reasons, the effects of the
 Windfall Profits Tax have not been included in the analysis.
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
                     Capital
=   I 1 + nominal cost  I -
    j_l + inflation ratej
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, EPA 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 or equity in the firm's value.
                                           1-9
-------
      The debt cost is the after-tax cost of debt, i.e., the product of the current cost of debt and
(1 minus the cor]x>rate 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 EPA 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 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 hi the table.  The estimated cost of capital is 7.55 percent. This value is rounded
upwards to 8 percent for use in the analysis.
US  REFERENCES

API.  1986.  1984 Survey on Oil and Gas Expenditures, American Petroleum Institute,
      Washington, DC, October.
Brealey, R.A. and S. Meyers.  1984. Principles of Corporate Finance. McGraw-Hill, New York,
      NY, 2nd edition.
Brigham, E.F. 1982.  Financial Management: Theory and Practice, The Dryden Press, New
      York, NY, 3rd edition.
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.
Commerce. 1983.  Annual Survey of Oil and Gas. 1981, U. S. Department of Commerce,
      Bureau of the Census, Current Industrial Reports,  MA-13k(81)-l, March.
                                          MO
-------
                                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
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
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
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
Average
                  8.63
                                         10.54
                                                                 5.3
Source:   Economic Report,  1987; Table B-68  (10-year U.S.  Treasury securities
         and Moody's Baa corporate bonds) and Table B-4 (inflation rate).
                                    1-11
-------
                                         TABLE 1-2

                                 DEBT/CAPITAL RATIO (%)
          MAJOR INTEGRATED OIL COMPANIES IN 19-COMPANY EPA GROUP
                                         (1977-1985)

Amerada Hess
American Pctroffna
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-HcGee
Mobil Oil
Hurphy Oil
Occidental Petroleum
Phillips Petroleun
Shell Oil (Royal Dutch
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
1978
36
45
34
38
13
4
14
16
25
.0
.8
.6
.4
.3
.7
.1
.6
.6
40.5
39
16
18
.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.
10.
--
--
23.
35.
13.
47.
64.
14.
7
4


4
8
7
6
3
6
Petroleun)

Standard Oil of California
(Chevron)

Standard Oil of Indiana
(Amoco)

Standard Oil of Ohio

Sun Company

Texaco

Union Oil Company

Unweighted
Company Averane*
      19.7  17.2   13.0   12.4   11.3   10.6   43.4   28.9


      23.5  21.1   18.8   21.4   22.0   20.1   17.3   16.9


      65.4  50.3   39.8   36.1   33.8   29.2   26.4   25.4

      19.4  16.8   34.5   28.6   24.7   24.8   25.3   20.7

      24.8  21.8   18.0   15.1   12.8   14.1   41.0   31.6

      28.6  26.0   21.9   18.3   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
16.2


25.2


71.9

18.9

19.1
Souica:   S&P  1982;  S&P 1986.

      •Simple average  calculated from the ratios for all  companies  in the
sample.
                                              1-12
-------
                                TABLE 1-3



                      COST OF CAPITAL CALCULATIONS
PARAMETER
                        VALUE
                                       SOURCE
Risk- free return
Industry beta
Market risk
Risk premium
Cost of debt
Debt cost
Debt share
Equity share
Inflation rate
Nominal cost
Real cost
8
0
8
6
10
6
25
75
5
13
7
.63%
.84%
.00%
.72%
.54%
.96%
.00%
.00%
.30%
.25%
.55%
See Table 1-1.
Kavanaugh, M. 1987. Average beta
for 24 petroleum companies. Standard
& Poor ' s Stock Reports .
Brealey and Myers 1984.
Calculated.
See Table 1-1.
Tax Reform Act of 1986, highest
corporate tax bracket is 34 percent.
See text.
See text.
See Table 1-1.


Source:  as listed.
                                    1-13
-------
Coopers and Lybrand.  1986. Tax Reform Act of 1986: Analysis. New York NY.

Economic Report. 1987. Economic Report of the President 1987. Council of Economic
      Advisors, January, 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.

Logsdon, C. 1988.  Personal communication between Maureen F. Kaplan, Eastern Research
      Group, Inc., and Charles Logsdon, Alaska Department of Revenue, March 15.

Snook, S.B. and W.J. Magnuson, Jr. 1986. "The Tax Reform Act's Hidden Impact on Oil and
      Gas," The Tax Adviser. December, pp. 777-83.
                                        1-14
-------
                                    APPENDIX J
  EPA ECONOMIC MODEL FOR OFFSHORE PETROLEUM PRODUCTION
J.I    INTRODUCTION

       The EPA 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.1.1 Model Phases                                                 *

       The project life of an offshore well producing 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
                                          J-l
-------
delineation, (3) from the start of delineation to the start of development, (4) from the start of
development to the start of 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 EPA 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 continues to operate as long as
operating cash inflows exceed cash expenses.
       J.L2.1 Cash Flows - Categorizfftion

       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.
                                           J-2
-------
Exploration Phase:
Delineation Phase:
Development Phase:
Production Phase:
Cr&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 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.

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.

Incremental capital costs - additional costs due to new equipment
required for additional pollution control of produced water,
treatment and workover fluids, and/or produced sand.

Revenues from oil and gas production - production levels
multiplied by price forecasts.

O&M costs - cost of operating and maintaining the well.

Incremental O&M costs - additional cost due to new or revised
regulations concerning produced water, treatment and workover
fluids, and/or produced sand.
       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, 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
                                            J-3
-------
2
S w
H H
EH W


W 0*

O W
                                     CO
                               CJ H
                               O( EH
                                  . . CO

                                  OS O
                                  Q 0
                                     w
                                     EH
                                     CO
a
                           H  H
                           Ol  M
   0}


   W
                                     3
                                     w
                                     CJ
                                     to

                                     CO
                                     CJ
                                     I
                                     fa
                                                                   WI

                                                                  JS
             2  i
             (1)  O
             TJ  O
             01  a
             En  H
                                                                   0)     rH
                                                                                                         M-l

                                                                                                         4J
                                                                       H
                                                                        o  a
                                                                       H  S
                                                                       MH  O
                                                                                                         ,ta  o
                                                                                                             to
                                                                                                         4J  A
                                                                                                          0)  O
                                                                                                          C
                                                                                                             a)
                                                                                                          n)  CQ
                                                                                                         H -H

                                                                                                            4J

                                                                                                          II -H
                                                                                                                    O
                                                                                 JS
                                                                                                                   >H
                                                                                 M-l
                                                                                                                    a  o
                                                                                                                    V rH
                                                                                 0) -H
                                                                                 CO  01
                                                                                 0)  (D
                                                                                 w  u
                                                                                 a)
                                                                                 Q>  0)
                                                                                 M  CO
                                                                                 u  n)
                                                                                 a)  a)

                                                                                 Qb
                                                                                  II  01
                                                                                    •o
                                                                               CO
                                                                 J-4
-------
 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 1.10.)
 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 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 te.|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.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 (Jine_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
                                           J-5
-------
                                  TABLE J-2

         EXOGENOUS VARIABLES PROVIDED TO EPA 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:  EPA estimate.
                                       J-6
-------
 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 is used throughout the
 code to discount future cash inflows, cash outflows, and production in order to express them in
 present value terms.                                                   .

       LineS 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. An oil
 company can expense, in the period incurred, costs that would normally be capitalized.  This
 immediate expensing of a portion of capital costs provides a significant tax advantage.

       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 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%. 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
                                           J-7
-------
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 buill: 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 GOM project, the annual exploratory well costs are:
       Annual
       Explora-
       tory Well
       Costs
(well cost + incremental drilling fluid cosfl
(discovery efficiency * no. of platforms per
       successful well)
(4.355 + (ft  -5- 1   = $7,234
(.14 * 4.3)
                                          Years
                                          of
                                          Exploration
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
       Successful Efforts
Annual Total Well Cost
* Discovery Efficiency
($7,234 * .14) = $1,013
      ' 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:
                                             J-8
-------
       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.
                                           J-9
-------
       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 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
       Delineation
       Well
       Cost
(well cost + incremental drilling fluid cost)
* number of delineation wells
-s- number of platforms per successful discovery
($4,355 * 2) -^ 4.3
$2,026
                                            J-10
-------
       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:
       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 (lineSl) 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:
                                             J-ll
-------
       Present Value = cost in Year 1 -s- 1.081
For the expensed cash flow, this is
       PV expensed cash flow
$561 4-  1.08
$520
Present values are calculated for expensed cash flow, capitalized delineation costs, and total
delineation costs (lines 32-35).
       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 2 years between the start of development and
the start of production (line 66).  Costs for both types of construction are allocated over the first
year or over the years of construction minus 1 year (line 47).

       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

                                           J-12
-------
  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 the 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 ss. respectively.


        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 EPA 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 EPA 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.

                                           J-13
-------
       Since not all wells are turned into producing wells (e.g., some are 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. respectively.  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.
            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 (line 78) 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
                      Year 4
6 wells * 500 bopd
3,000 bopd
(6*500) + (4*500)
3,000 + 2,000
5,000 bopd
                                            J-14
-------
                     YearS
                     Year 6
(6 * 500 * 0.85) + (4 * 500)
2,550 + 2,000
4,550 bopd
(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.2.4.1 Income Statement

       Lines 85 through 107 comprise an income statement that is repeated annually for a 30-
year project lifetime. Since most projects become uneconomical before this, lines 108 through
114 check for .a negative net cash 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:
                                           J-15
-------
       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
For Year 3
                     =     Capitalized Costs in the Exploration Phase
                            + 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 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 H- (1 + inflation rate)Ye"x or $3,658 + (1.042)3 = ($3,658
 •*• 1.131) = $3,234; see line 99 and note rounding.

       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
                                            J-16
-------
       Line 101. earnings before interest and ODA (oil depletion allowance), subtracts
depreciation and amortization from operating earnings. For Year 3,
       Earnings Before
       Interest and ODA
       $20,212- $3,234  = $16,978 (note rounding)
       For major integrated producers; the depletion allowance is calculated on a cost basis, that
   the leasehold cost is amortized over the productive life of the well:'         -
       Depletion
       Allowance     =
       in "Year X"
Leasehold
Cost
Taken
Depletion
Allowance      x
from "Year X"  "
"Year X" Production
Total Production
For Year 3, the depletion allowance for the Gulf project is:


              ($11,952-0)* (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
       Allowance
       in "Year X'
       (line 90)
Depletion Allowance
in "Year X"       /(I + inflation rate)Year x
                                         fJ-17
-------
For Year 3 in tfie project, the adjusted depletion allowance is:

              $943 •=- (1.042)3
              $834

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 116V

       Earnings before interest and taxes (line 1041 is defined as the earnings before interest
and ODA (line 1011 minus the adjusted oil depletion allowance (line 102V  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
                                            J-18
-------
       Project shutdown
   Net cash flow (Line 1071
-  (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.  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.
           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).
                                           J-19
-------
       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 given in terms of present value and are annualized over
the economic lifetime of the well.  The annualized cost is given in line 207.
       Oil and gas production is also discounted to give present value equivalent (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
       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 219).

       The net present value of the project, line 220. is calculated as:
                                           J-20
-------
H
03







J
a
Q
0
s
§
CO
D





1
CJ fe
ft EH
H <3
Q H
i . — .
U EH CO
J g CO H
ft O O CO
H H U <-
Q EH — ffl


S!
M £•*
88
co u
ft EH
S co
O U













H
8
3
CO
o
u


+




.{-






+


-(.





*

to
4->
to
O
o
g
-H
JJ
2
0
hold cost
xpenses
capitalized expl
0) (1) i-H
to re
re o jj
a) «a o
. H) O EH


+






















CO
4J
W
O
o
g
•H
4J
RS
0)
a
capitalized deli
rH
m
4J
o
EH


+






















to
CO
O
u
4J
8
1
rH
capitalized deve
rH
Rl
4J


















^-






to
s
0
(H

CO
R)
O
i)
a
V)
expensed investm
o
5)

















H-













to
capitalized cost
M-i
o
^1














+


•r "r H*

to
a
o
4-) Rl
re 4J

a) 'a,
Pi R)
O 0

i i
to
JJ
to
0
u
1-1
pollution contro
royalties
ii i it I
o o
> >
M4 Pi














+ +


H* + 'H~ I 1












§tn
4J
-H 0)
JJ O
severance taxes
operating costs
income taxes
excess depletion
surplus deprecia
all investment o
IM IIH tu IM IM IH
o o o o o o
£ Ei Us £ 5; 5;
































present value.
n
ft
                                               J-21
-------
       Net Present   =
       Value
PV of Cash
Inflows
PV of Cash
Outflows
                     =      PV of Operating Cash Rows
                            - 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} 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-22
-------
Run Date:
Project Type:

Lease Bid:
G&G Expense:
Leasehold Cost:
Real Discount  Rate:
Inflation Rate:
Yrs Btwn Lease Sale  & Strt of  Exp:
Percent Costs  Expensed:
Drilling Hud Cost Increment:
Corporate Tax  Rate:
08-Feb-90
Gulf 12
OIL and GAS
   $5,678
   110.50SJ
  $11,952
     8.00X
     4.20X
        0
    42.00%
       $0
       34X
                                                    1986 data
                                                                                                                            LINE
                                                                                                                             NO,
                                                                                               1
                                                                                               2
                                                                                               3
                                                                                               4
                                                                                               5
                                                                                               6
                                                                                               7
                                                                                               8
                                                                                               9
Cost Per Exploratory Well.:
Drilling Hud Cost Increment:
Discovery Efficiency:
Platforms per Successful Expl. Wei
EXPLORATION COSTS

   $4,355
      -$0

      4.3
Explor. Costs Per Platform:
Cost of Successful Efforts:
Expensed Costs:
Expensed Cash Flows:
Capitalized Cash Flows:

PV of Expensed Exploration Cash Flows:
PV of Capitalized Expl. Cash Flows:
Total Capitalized Expl. Costs:
PV of all Exploratory Costs:
Year
0
$7,234
$1,013
$6,647
$4,387
$587
lows:
;:


Year Year
1
$0
so
$0
$0
$0
$4,387
$587
$587
$7,234
Year
2
$0
$0
SO
$0
$0




3
$0
$0
$0
$0
$0




                                                                                              10
                                                                                              11
                                                                                              12
                                                                                              13
                                                                                              14
                                                                                              15
                                                                                              16
                                                                                              17
                                                                                              18

                                                                                              19
                                                                                              20
                                                                                              21
                                                                                              22
                                  DELINEATION COSTS
 Years Between Start of Expl.
     and Delineation:
 Number of Delineation Wells
     Drilled:
 Cost per Delineation Well:
 Drilling Hud Cost Increment:
 Platforms Per Find:
 Total Delineation Costs:
 Tax Shield:
 Expensed Cash Flow:
 Capitalized Cash Flow:
        1

        2
   $4,355
       JO
      4.3

Year     Year     Year     Year
        1234
$2,026
$289
$561
$1,175
$0
$0
£0
$0
$0
$0
$0
$0
SO
$0
$0
$0
                                                                                              23

                                                                                              24
                                                                                              25
                                                                                              26
                                                                                              27
                                                                                               28
                                                                                               29
                                                                                               30
                                                                                               31
                                                            J-23
-------
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 btwn Delineation  & Constn:
Hwber of Wells Drilled:
Nurber Uells Drilled  Per Year:
Drilling Co«t Per  Well:
Drilling Cost Per Well:
Drilling Hud Cost Increment:
Well Start:
Hurfoer of Uells Drilled:
Total Drilling Costs for Year:
Annual Platform Cost:
Annual Poll Cont Capital Costs:
Total Annual Capital Cost:
Tax Shield:
Expensed Cash Flovi:
Capitalized Cash Flow:

PV of All Construction Costs:
PV of Expensed Construction Costs:
PV of Capitalized Construction Costs:
FINANCIAL RATES
Percent Vater Cut in 04G to Start
Oil/Cat Prod. Decl. Rate/Year (X)
Coct Escalator (X):
Royalty Rate (X):
Federal Tax Rate (X):
Average Depreciation tife (years)
   Deprec. rate (subs, years):
State Severance Tax Rate-Oil:
    (If Alaska enter 99)
State Severance Tax Rate-Gas:
    (If Alaska enter 99)


$520
ts: $1,175
tsc S1.08S
S1.876
CONSTRUCTION COSTS
$11,660
$0
0
10 ' •
6
$4,906
Year Year Year Year fsar . Year Year Year Year
12345 6 7 S 9
$4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906
$0 SO $0 $0 $0 $0 $0 SO SO
01234 5678
06 4 0 0 0 0 0 0
SO $29,436 $19,624 $0 $0 $0 SO SO $0
$11,660 $0 $0 SO $0 $0 SO SO $0
$0 $0 $0 SO $0 $0 SO SO SO
$11,660 $29,436 $19,624 $0 $0 $0 $0 $0 SO
$1,665 $4,203 $2,802 $0 $0 $0 $0 SO $0
$3,232 $8,160 $5,440 SO $0 $0 SO SO SO
$6,763 $17,073 $11,382 $0 $0 $0 $0 $0 $0
$51,611
: $14,307
sts: $29,934
:: 10X
: 85X
OX
22X
34X
: 7
14.29JC 24.49X 17.49% 12.49X 8.93X 8.92X 8.93X 4.46X
6.19X
LINE
NO.
32
33
34
35

36
37
38
39
40
41
•'ear
10
$4,906 42
$0 43
9 44
0 45
$0 46
SO . 47
$0 48
SO 49
$0 50
SO 51
$0 52
53
54
55
56
57
58
59
60
61
62
63
6.19X
                                                                                         64
                                                           J-24
-------
Gas Only? <1=yes, 0=no):
Yrs Btwn Strt Dev & Strt Prod <<5)
Number of Years at Peak Prod (=>1)
Oil Peak Prod. Rate/Well(bb):
Gas Peak Prod. Rate/Wei I(MMCF/D):
No. of Producing Wells:
No. of Wells Put in Service/Year:
Price of Oil Per Barrel:
Price of Gas Per MCF:
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/Barret of Oil:
 MMCF of Gas Per Day:
 HHCF of Gas Per Year:
 Price/HCF of Gas:

 Annual Oil Revenues ($000):
 Annual Gas Revenues (SOOO):
 Total Revenues ($000):
 Royalty Payments-Oil  ($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 Revenues  ($000):

 Total Operating Costs ($000):
 Exp. Poll.Cont.Cap.Costs ($000):
 Poll.Con.Operating Costs ($000):
 Capitalized Costs (SOOO):
 Adjstd Deprec I Amort ($000):

 Operating Earnings ($000):
 Earnings Before  Interest and COA:
 Adjstd Depletion (Cost Basis):
 Surplus Depletion:
PRODUCTION
0
i 2
l 2
500
0.835
10
6
S23.82
$2.57
$2,312
$0
365
Year
3
COSTS
LINE
Ktn
65"
66
67
68
69
70
71
72
73
74
75

Year
4

Year
5

Year
6

Year
7

Year
8

Year
9

Year
10

Year
11

Year
12
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
$23.82

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
SO
$0
$25,598
$3,233
$20,212
$16,979
$834
en
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
$0
$0
$11.382
$6,697
$35.228
$28,531
$1,334
so
8
2773
$2.57
$39,559
$7,128
$46,487
$8,703
$1,568
$1,910
$344
0.19
-2.95
$34,162
$2,312
$0
$0
$0
$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
$0
$0
$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
$0
$0
$2,780
$22,370
$19,590
$773
$0
5
1703
S2.57
$24,294
$4,377
$28,672
$5,345
$963
$1,173
$211
ERR
-5.43
$20,979
$2,312
$0
.$0
$0
$2,374
$18,667
$16,293
$632
$0
4
1448
$2.57
$20,650
$3,721
$24,371
$4,543
$819
$997
$180
ERR
-6.56
$17,833
$2,312
$0
$0
$0
$2,280
$15,521
$13,241
$516
$0
3
1231
$2.57
$17,553
$3,163
$20,715
$3,862
$696
$847
$153
ERR
-7.90
$15,158
$2,312
$0
$0
SO
$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
*o
$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
OO
88
Qf\
89
f\f\
90
O T
91
rto
92
flO
93
<"» A
94
95
Of
96
97
98
99
100
101
102
103
                                                          J-25
-------
Earnings Before Int and Taxes:
Statutory Tax:
Earnings Before Int After Tax:
Het Cash Flow:

Shutoff?
Actual OH Prod./Year (Barrels.):
Actual Gas Prod./Year (HMCF):
Actual Gross Revenues ($000):
Actual Het Revenues ($000):
Actual Het Cash Flow ($000):
Actual Taxes Paid ($000):

Capitalized Costs Hot Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels OH Per Year:
Price Per Barrel:
HNCF Gas Per Day:
WCF Cas Per Year:
Price Per HCF:

Oil Revenues ($000):
C«s Revenues ($000):
Total Revenues ($000):
Royalty Payments-Oil ($000):
Royalty Payments-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Sev. Taxes-Oil.".
ELF for Alaska Sev. Taxes-Gass
Het RevenuesCSOOO):

Operating Costs:
Exp. Poll.Cont.Cap.Co«s ($000):
Pollution Control Operating Costs:
For PV Poll. Control:
Adjstd Deprec t AMort ($000):

Operating Earnings  ($000):
Earnings Before  Interest and OOA:
Adjstcd Depletion (Cost Basis):
 Surplus Depletion:
 Earnings Before  Int and Taxes:
LINE

$16,145
$5,489
£10,656
$14,723
1
1095000
1829
$30,783
$22,524
$14,723
$5,489
$0
$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
$0
Year
17

$15,661
$5,325
$10,336
$13,343
1
1019908
1703
$28,672
$20.979
$13,343
$5,325
$0
$0
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
SO
Year
20

$9,906
$3,368
$6,538
$7,204
1
626351
1046
$17,608
$12,884
$7,204
$3,368
$0
$0
Year
21

$8,360
$2,842
$5,517
S5.797
1
532398
889
$14,967
$10,951
$5,797
$2,842
$0
$0
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
$23.82
117
118
119
120
CAS PRODUCTION
2
756
$2.57
$10,779
$1,942
$12,722
$2,371
$427
• $520
$94
ERR
-13.49
$9,309
2312
$0
i: $0
SO
$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
SO
$5,414
1
546
$2.57
$7,788
$1,403
$9,191
$1,713
$309
$376
$68
ERR
-19.05
$6,726
2312
SO
$0
SO
SO
$4,414
$4,414
$152
SO
$4,262
1
464
$2.57
$6,620
$1,193
$7,813
$1,456
S262
$320
$58
ERR
-22.59
$5,717
2312
SO
$0
SO
SO
$3,405
$3,405
$124
$0
$3,281
1
395
$2.57
$5,627
$1,014
$6,641
$1,238
$223
$272
$49
ERR
-26.76
$4,859
2312
$0
SO
SO
SO
$2,547
$2,547
$101
SO
$2,446
1
335
$2.57
$4.783
S862
$5,645
$1,052
$190
$231
$42
ERR
-31.65
$4,130
2312
SO
SO
SO
SO
$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
' SO
SO
so
so
$1,199
$1,199
$67
$0
$1,131
1
24?.
$2.57
$3,456
$623
$4,078
$760
$137
$167
$30
ERR
-44.20
$2,984
2312
SO
SO
SO

$672
$672
$55
SO
$617
1
206
$2.57
$2,937
$529
$3,467
S646
$116
$142
$26
ERR
-52.17
$2,537
2312
$0
SO
SO

$225
S225
$45
$0
$180
0
175
$2.57
$2,497
$450
$2,947
$549
$99
$121
$22
ERR
-61.56
$2,156
2312
SO
SO
SO

($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-26
-------
 Statutory Tax:
 Earnings Before Int After Tax:
•Net Cash Flow:

 Shutoff?
 Actual Oil Prod./Year (Barrels):
 Actual Gas Prod./Year (HHCF):
 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:
 MMCF Gas Per Day:
 HHCF Gas Per Year:
 Price Per MCF:

 Oil Revenues ($000):
 Gas Revenues ($000):
 Total Revenues ($000):
 Royalty Payments-Oil ($000):
 Royalty Paywsnts-Gas ($000):
 Severance Taxes-Oil ($000):
 Severance Taxes-Gas ($000):
 ELF for Alaska Sev Taxes-Oil:
 ELF for Alaska Sev Taxes-Gas:
 Net Revenues($000):

 Operating Costs:
 Pollution Control Operating Costs
 For PV Poll. Control:

 Operating Earnings ($000):
 •Earnings Before Interest and ODA:
 Adjsted 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
$1,841
$3,573
$3,760
1
384658
642
$10,813
$7,912
$3,760
$1,841
SO
$0
$1,449
$2,813
$2,965
1'
326959
546
$9,191
$6,726
$2,965
$1,449
$0
$0
81,115
82,165
$2,289
1
277915
464
87,813
85,717
82,289
$1,115
$0
SO
$832
$1,614
$1,716
• 1 ,
236228
395
$6,641
$4,859
$1,716
$832
$0
$0
$590
$1,146
$1,228
1
200794
335
$5,645
$4,130
$1,228
$590
$0
$0
$385
S747
$814
1
170675
285
$4,798
$3,511
$814
$385
$0
$0
$210
S407
S462
1
145074
242
$4,078
$2,984
$462
$210
$0
$0
$61
$119
$163
1
123312
206
$3,467
$2,537
$163
$61
$0
$0
LINE
NO.
(565)144
($127)145
($91)146
0
0
0
$0
$0
so
so
$0
$0
147
148
149
150
151
152
153
154
155
Year Year Year Year Year Year Year Year Year Year
23
24
25
26
27
28
29
30
31
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
S23.82
67
365
24277
$23.82
57
365
20636
$23.82
156
157
158
159
GAS PRODUCTION
0
149
$2.57
$2,122
$382
$2,505
$467
$84
$102
$18
ERR
-72.60
$1,833
2312
: SO
SO
(S479)
($479)
$77
$77
($556)
($189)
($367)
0
126
S2.57
$1,804
$325
$2,129
$397
$72
S87
$16
ERR
•85.58
$1,558
2312
SO
SO
C$754)
($754)
$65
$65
($819)
($279)
($541)
0
107
S2.57
$1,533
$276
$1,810
$337
$61
$74
S13
ERR
-100.86
$1,324
2312
SO
SO
<$988)
(S988)
$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
$0
($1,187)
($1,187)
$47
$47
($1,234)
($419)
($814)
0
78
$2.37
$1,108
$200
$1,307
$244
$44
$53
S10
ERR
-139.99
$937
2312
$0
SO
($1,355)
($1,355)
$40
$40
($1,395)
($474)
($921)
0
66
$2.57
$942
$170
$1.111
$207
$37
$45
$8
ERR
-164.87
$813
2312
SO
SO
($1,499)
($1,499)
$34
S34
($1,533)
($521)
($1,012)
0
56
$2.57
$800
$144
$945
$176
$32
$39
$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
$0
($1.724)
($1.724)
$25
$25
($1,749)
($595)
($1.154)
0
41
$2.57
$578
$104
$682
$127
$23
S28
$5
ERR
-269.09
$499
2312
$0
$0
($1,813)
($1,813)
$21
$21
($1,834)
($623)
($1,210)
0
34
$2.57
$492
$89
$580
'$108
$19
$24
$4
ERR
-316.75
$424
2312
$0
$0
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
{$1,888)i76
($1,888)! 77
$18
$18
178
179
($1.905)180
($648)181
($1,258)182
                                                           J-27
-------
Met Cash Flow:

Shutoff?
Actual Oil Prod./Year (Barrels):
Actual Gas Prod./Year (HHCF>:
Actual Gross Revenues ($000):
Actual Het Revenues ($000):
Actual Het Cash Flow (MOO):
Actual Taxes Paid ($000):
PV of Het Revenues:
PV of Excess Depletion:
PV of Surplus Depreciation:

PV of Expensed Invest Cash Flows:
PV of Capitalized Costs:
PV of Leasehold Cost:
PV Poll. cent. Costs:
PV of Royalties - oil:
PV of Royalties - gas:
PV of Severance taxes - oil:
PV of Severance taxes - gas:
PV of Income Taxes Paid:
PV of Operating Costs:

Total Cocpany Costs:
Total Cowpany Costs - Oil:
Total Company Costs - Gas:
Annualized Poll.Coot.Costs:


($290)
• 0
0
0
SO
SO
SO
SO
$152,784
S30
SO
$19.213
$31,610
$11,952
SO
$38,923
$7,013
$8,542
$1,539
$37,393
$19,036

$175,192
$148,445
$26,747
$0


$476) ($633) ($767) ($881) ($978)
0000 0
0 00 0 0
0000 0
$0 $0 $0 $0 $0
$0 $0 $0 SO SO
$0 $0 $0 $0 $0
$0 $0 $0 $0 $0
191 pv Equiv. of Oil (bbt): 7,427,539
192 pv Equiv. of Gas (MMCF): 12,404
193 pv BOE 9,611,069
194 Amortized Company Cost per bbl:
195 Amortized Company Cost pep Hef :
196 Amortized Company Cost per BOE:
197
198 pv of Social Costs - Total: $86,031
199 pv of Social Costs - Oil: $72,896
200 pv of Social Costs - Gas: St3,135
201
202 Amortized Social Cost per bbl:
203 Amortized Social Cost per Hcf :
Amortized Social Cost per BOE:
204
205 Net Present Value of Project:
206 internal Rate of Return:
207 NO. of Years of Production: 19


($1,060) ($1,130)
0 0
0 0
0 0
$0 $0
SO $0
$0 SO
$0 $0



$19.99
$2.16
$18.23





$9.81
$1.06
$8.95

$33,610
0.201

LINE
NOo
($1,189) ($1,240) 183
0 0 184
0 0 185
0 0 186
$0 SO 187
$0 $0 188
SO so 189
$0 $0 190
208
209
210
211
. 212
213

214
215
216

217
218
' 219

220
221
222
                                                           J-28
-------