197!i
           U  (A)
               ECONOMIC ANALYSIS
                        OF
PROPOSED  AND INTERIM FINAL EFFLUENT GUIDELINES
                        OF
 THE OFFSHORE OIL  AND GAS PRODUCING  INDUSTRY
     L'.S. ENVIRONMENTAL PROTECTION AGENCY
               Economic Analysis Section
         Office of Water and Hazardous Materials
               Washington, D.C. 20460

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    This document vull be available through the National
Technical Information Service. Springfield. Virginia 22151.

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               ECONOMIC ANALYSIS
                      OF
PROPOSED AND INTERIM FINAL EFFLUENT GUIDELINES
                      OF
  THE OFFSHORE OIL AND GAS PRODUCING INDUSTRY
                   report to

     U.S. Environmental Protection Agency
           Economic Analysis Section
    Office of Water and Hazardous Materials
            Washington, D.C.  20460
            Partial Fulfillment of
            Contract No. 68-01-1541
                    Task 20
                 July 31, 1975

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                                PREFACE









     The attached document is a contractor's study prepared for the




Office of Water and Hazardous Materials, Economic Analysis Section, of




the Environmental Protection Agency ("EPA").  The purpose of the study




is to analyze the economic impact which could result from the applica-




tion of alternative effluent limitation guidelines and standards of




performance to be established under sections 304(b)  and 306 of the




Federal Water Pollution Control Act, as amended.




     The study supplements the technical study  ("EPA Development Docu-




ment") supporting the issuance of international regulations under




sections 304(b) and 306.  The Development Document surveys existing and




potential waste treatment control methods and technology within parti-




cular industrial source categories and supports the proposal based upon




an analysis of the feasibility of these guidelines and standards in




accordance with the requirements of sections 304(b) and 306 of the Act.




Presented in the Development Document are the investment and operating




costs associated with various alternative control and treatment techno-




logies.  The attached document supplements this analysis by estimating




the broader economic effects which might result from the required appli-




cations of various control methods and technologies.  This study




investigates the effect of alternative approaches in terms of product




price increases, effects upon employment and the continued viability of




affected plants, effects upon foreign trade and other competitive effects.




     The study has been prepared with the supervision and review of the




Office of Water and Hazardous Materials, Economic Analysis Section of EPA.

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This report was submitted in partial fulfillment of Contract No. BOA




68-01-1541, Task Order No. 20, by Arthur D. Little, Inc., Cambridge,




Massachusetts.  Work was completed as of July, 1975.




     This report is being released and circulated at approximately the




same time as publication in the Federal Register of a notice of interim




final and proposed rule making under sections 304 (b) and 306 of the Act for




the subject point source category. The study is not an official EPA publica-




tion. It will be considered along with the information contained in the




Development Document and any comments received by EPA on either document




before or during proposed rule making proceedings necessary to establish




final regulations.  Prior to final promulgation of regulations, the




accompanying study shall have standing in any EPA proceeding or court




proceeding only to the extent that it represents the views of the con-




tractor who studied the subject industry.  It cannot be cited, referenced,




or represented in any respect in any such proceeding as a statement of




EPA's views regarding the subject industry.

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                           TABLE OF CONTENTS
                                                                 Page
 I.     EXECUTIVE SUMMARY                                           1-1
 I.I.   SCOPE OF WORK                                               1-1
 1.2.   INDUSTRY DESCRIPTION                                        1-2
 1.3.   SUMMARY OF CONCLUSIONS                                      1-4
II.     CHARACTERIZATION OF THE OFFSHORE OIL AND GAS               II-l
       EXTRACTION INDUSTRY
II.I.   INDUSTRY STRUCTURE                                         II-l
       1.1.  Industry Definition                                  II-l
       1.2.  Offshore Oil and Gas Production                      II-l
       1.3.  Demand for Oil and Gas                               II-7
       1.4.  Oil and Gas Supply/Demand                            II-8
II.2.   CHARACTERIZATION OF OFFSHORE OIL AND GAS PRODUCING         11-21
       COMPANIES
II.3.   OIL AND GAS PRICING                                        11-30
       3.1.  Crude Oil Pricing                                    11-30
             •  The Role of Crude Prices in the Economic          11-30
                Impact Analysis
             •  Current Crude Oil Pricing Patterns                11-31
       3.2.  Pricing of Offshore Natural Gas at the Wellhead      11-41
             •  Introduction                                      11-41
             •  Regulation of Natural Gas Producers               11-47
             •  Nationwide Costs of Finding and Producing         11-51
                Non-Associated Gas
             •  Successful Wells Cost                             11-53
             •  Dry Holes                                         11-53
             •  Operating Expense                                 11-55
             •  Return on Investment                              11-55
             «  Some Conclusions                                  11-57

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II.4.   FINANCIAL CHARACTERISTICS                                  11-61
       4.1.  The Role of Financial Characteristics in the         11-61
             Economic Impact Analysis
       4.2.  Income Statements and Profitability                  11-62
       4.3.  Capital Requirements                                 11-71
       4.4.  Capital Structure                                    11-84
       4.5.  Cost of Capital                                      11-90
             »  Introduction                                      11-90
             •  Weighted Average Cost of Capital                  11-90
             •  Estimate of the Cost of Debt                      11-91
             •  Estimate of the Cost of Equity                    11-91
             •  Estimate of the Cost of Capital for the           11-93
                Petroleum Industry

III.    PROPOSED EFFLUENT LIMITATION GUIDELINES                   III-l
III.l.  PROPOSED EPA REGULATIONS                                  III-l
III.2.  CURRENT REGULATIONS                                       III-8
        •  California State Waters                                III-9
        •  Alaska State Waters                                    III-9
        •  Louisiana State Waters                                 III-9
        •  Texas State Waters                                     II1-9
III.3.  COST OF POLLUTION ABATEMENT SYSTEMS                       111-10

 IV.    IMPACT ASSESSMENT METHODOLOGY                              IV-1
 IV.1.  INTRODUCTION                                               IV-1
 IV.2.  GENERAL APPROACH                                           IV-3
        2.1.   Producers Absorb All Costs                           IV-3
        2.2.   Producers Pass On All Costs                          IV-7
 IV.3.  PRODUCTION ECONOMICS                                       IV-8
        3.1.   The Bureau of Mines Model Production Unit            IV-8
        3.2.   Operating Costs                                      IV-11
        3.4.   Investment Costs                                     IV-22

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                                                                  Page

IV.4.   AFTER TAX CASH FLOWS FOR EACH PRODUCTION UNIT              IV-24

IV.5.   NO ALLOWANCE FOR COSTS OF TRANSPORTING OIL AND GAS         IV-25
       ONSHORE

IV.6.   COMPUTER PROGRAM                                           IV-27
 V.    ANALYSIS OF THE DATA  BASE                                    V-l

 V.I.  INTRODUCTION                                                 V-l

 V.2.  GEOGRAPHICAL  SEGMENTATION  OF OFFSHORE OIL AND  GAS            V-l
       PRODUCTION

 V.3.  SOURCE OF DATA AND GENERALIZATION USED  IN THE  ANALYSIS       V-4

       3.1.  Introduction                                           V-4

       3.2.  The Size and Number  of Production Units  Present        V-5
             in Offshore Areas

       3.3.  Estimates of the Annual Volumes of Oil,  Gas,  and       V-9
             Water Produced  and Estimates of the Annual Pro-
             duction Decline Rates

       3.4.  Production Units in  State Waters  and Cook Inlet,       V-17
             Alaska


VI.    ECONOMIC IMPACT ANALYSIS                                     VI-1

VI.1.  SUMMARY                                                      VI-1

VI.2.  FEDERAL WATERS: BASE CASE RESULTS FOR OIL WELLS AND          VI-9
       GAS WELLS

       •  Federal Waters;  Sensitivity Tests by Changes in           VI-13
          Base Case Parameters

       •  Average Cost Increases for Oil and Gas,  Federal Waters    VI-20

VI.3.  STATE WATERS:  BASE CASE RESULTS FOR OIL WELLS AND            VI-22
       GAS WELLS

       •  State Waters;  Sensitivity Tests by Changes in Base        VI-28
          Case Parameters

       •  Likely Average Cost Increases for Oil and Gas,  State      VI-34
          Waters

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                                                                 Page

VI.4.  ALASKA, RESULTS OF A PRELIMINARY IMPACT ANALYSIS           VI-36

VI.5.  CALIFORNIA                                                 VI-43

VI. 6.  INFERRED IMPACT, EXISTING SOURCES IN THE GULF OF           VI-46
       MEXICO

VI.7.  INFERRED IMPACT, NEW SOURCES IN THE GULF OF                VI-50
       MEXICO

VI.8.  DIRECT ENERGY EFFECTIVENESS OF TREATMENT EQUIPMENT         VI-55

VI.9.  ECONOMIC COST PER BARREL RECOVERED                         VI-59

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                       LIST OF TABLES

  No.                                                         Page
1-1         Summary of Economic Impacts, The Offshore        1-8 & 1-9
              Oil and Gas Extraction Industry
II-l        Crude Oil and Condensate Production,                II-4
              Total Offshore "State" and "Federal OCS"

II-2        Natural Gas Production, Total Offshore             II-5
              "State" and "Federal OCS"

II-3        Total United States and Outer Continental          II-6
              Shelf Production of Crude Oil and Condensate,
              and Natural Gas, Percentage of OCS Production
              of Total U.S. Production

II-4        U.S. Energy Demand by Primary Source - 1972        II-9
              and 1970

II-5        U.S. Energy Demand by Primary Source - 1985        11-13

II-6        U.S. Crude Oil Production - 1974 to 1985           11-15

II-7        Potential Rates of U.S. Oil Production             11-16

II-8        U.S. Natural Gas Supplies, 1972-1985               11-17

II-9        OCS Lease Acreage and Production, Through          11-22
              September 1971

11-10       Louisiana Land and Exploration Co., Docket No.    11-23 & 11-24
              C173-501, Joint Ownership of Federal Offshore
              Producing Leases

11-11       Louisiana Land and Exploration Co., Docket No.     11-25
              C173-501, Joint Ownership of State of
              Louisiana Petroleum Leases by Large Major
              Producers

11-12       Louisiana Land and Exploration Co., Docket No.     11-27
              C173-501, Major Interstate Gas Pipelines and
              Their Producing Affiliates

11-13       Participation by Interstate Pipeline Company       11-28
              Affiliates in Offshore Louisiana Federal Oil
              and Gas Lease Sale, September 12, 1972

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No.                                                           Page

 11-14       Participation by Interstate Pipeline Company       11-29
               Affiliates in Offshore Louisiana Federal Oil
               and Gas Lease Sale,  December  19, 1972

 11-15       Historical Posted Crude Oil Prices                 11-32

 11-16       Representative Posted Prices and Actual Costs      11-35
               Per Barrel of Foreign Equity Crudes and
               U.S. Crudes
 11-17       Delivered Prices of Foreign and Average            11-37
               Mix Domestic Crude

 11-18       Delivered Price of Foreign and Decontrolled        11-38
               Domestic Crudes

 11-19       Prices Received by Producers for Natural Gas       11-42
               Sales, 1966-1975

 11-20       Lower 48 State Net Reserve Additions,  Inter-       11-43
               state vs.  Intrastate

 11-21       Estimated New Long-Term  Contract Sales by Large    11-45
               Producers,  1970-1973,  Offshore Federal Domain
               vs. All Areas

 11-22       Gas Exploratory Footage                            11-46

 11-23       Gas Development Footage                            11-46

 11-24       Estimated Nationwide  Cost of Finding and           11-52
               Producing  Non-Associated Gas

 11-25       Income Statement of Chase Group for 1971, 1972,    11-63
               and 1973

 11-26       Net Income After Tax  and the Rate  of Return on     11-67
               Equity of  22 U.S. Oil  Companies  (1963-73)

 11-27       Rates of Return for Chase Group: 1971, 1972,  1973  11-68

 11-28       1973 Financial Figures for Offshore Producers     11-69

 11-29       Comparison of Capital Requirements Estimates:      11-72
               Total Dollars, Cumulative 1975-1985

 11-30       Estimates of Petroleum Industry Capital Require-   11-74
               ments

 11-31       Cash Flow of Chase Group for 1973                  11-76

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No.

11-32       Source and Use of Capital for Chase Group in       11-77
              1973

11-33       Estimated Capital and Exploration Expenditures     11-79
              of U.S. Oil Industry

11-34       Estimated Capital and Exploration Expenditures     11-81

11-35       Exploration and Development Expenditures in the    11-82
              U.S.: 1972 and 1973

 11-36       Typical Yearly Capital  Expenditures of Segments    11-83
               of the Oil  Industry in the  U.S.

 11-37       Balance Sheet of Chase  Group,  1973, 1972,  1971     11-85

 11-38       Petroleum Industry Capitalization,  1972            11-86

 11-39       Example of Calculation of Cost of  Capital for      11-94
               1971-1974

 11-40       Oil Stock Prices                                   11-96
III-l        Applicability of Proposed Guidelines              III-3

III-2        Proposed Effluent Guidelines                      III-4

III-3      - Distribution of Effluent Samples from Exemplary   III-6
               Treatment Systems

III-4        Pollution Abatement Equipment Costs: Offshore     111-12
               Gulf of Mexico

III-5        Distribution of Different Treatment Tech-         111-15
               nologies Currently Being Used Offshore
               Louisiana in Federal and State Waters

 IV-1         Possible Alternative  Outcomes of  an Investment      IV-4
              Analysis  in  New Treatment  Facilities  in  1977
              for  a  Production Unit  in State  Waters

 IV-2         Sample Operating  Costs                              IV-13
                                                                IV-15

 IV-3         Calculation of Annual Production  for the BOM        IV-18
              Model  Production Unit, Assuming a 15% Annual
              Decline Rate

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No.                                                            Page

IV-4        Calculation of Operating Costs in $/B and          IV-19
              B/D per Completion
 V-l        Average Daily U.S. Offshore Oil and Lease           V-2
              Condensate Production in 1974

 V-2        Number of  Oil and Gas Platforms Considered          V-6
              and Total Number of Platforms Present  in
              Offshore Areas

 V-3        Gulf of Mexico, Federal Waters; Distribution of     V-8
              Multi-Well Oil and Gas  Producing Platforms
              Over Leaseblocks

 V-4        Louisiana  Federal Waters, Number  of Oil  Pro-        V-10
              due ing Platforms Ranked by  Total Average Daily
              Water Production

 V-5        Louisiana  Federal Waters, Number  of Gas  Pro-        V-ll
              ducing Platforms Ranked by  Total Average Daily
              Gas and  Daily Water Production

 V-6        Actual Production  in 1973/1974  Compared  with the    V-16
              Production in 1973/1974 Implied by  the Use of
              Allowables in the Analysis

 V-7         Size Distribution  of Production Units in Gulf  of    V-18
              Mexico Federal Waters and in  Louisiana State
              Waters
VI-1        Range of Likely Impact in the Gulf of Mexico,       VI-3
              Federal and State Waters

VI-2        Range of Average Cost Increases in the Gulf of      VI-5
              Mexico, Federal and State Waters

VI-3        Federal Waters - Oil, Producers Absorb All Costs    VI-10

VI-4        Federal Waters - Gas, Producers Absorb All Costs    VI-12

VI-5        Sensitivity of Results to Changes in Key            VI-14
            Variables - Oil

VI-6        Sensitivity of Results to Changes in Key            VI-15
            Variables - Gas

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No.                                                            Page

VI-7        Range of Likely Impact in the Gulf of Mexico,       VI-19
              Federal Waters

VI-8        Range for Likely Average Cost Increases in          VI-21
              1977 for Producers in Federal Waters,
              Gulf of Mexico

VI-9        State Waters - Oil, Producers Absorb All Costs      VI-24

VI-10       State Waters - Gas, Producers Absorb All Costs      VI-25

VI-11       Reinjection Required in 1983, Range of Likely       VI-29
              Impact in Louisiana, State Waters

Vl-lla      No Reinjection Required in 1983, Range of           VI-30
              Likely Impact in Louisiana, State Waters

VI-12       Sensitivity of Results to Changes in Key            VI-32
              Variables, State Waters, Reinjection Required,
              Oil

VI-13       Sensitivity of Results to Changes in Key            VI-33
              Variables, State Waters, Reinjection Required,
              Gas, Producers Absorb All Costs

VI-14       Likely Average Cost Increase in 1977 and 1983       VI-35
              for Producers in State Waters

VI-15       1973 Statistics on Oil and Gas Fields Offshore      VI-37
              Alaska, Cook Inlet

VI-16       Alaska, Cook Inlet, Preliminary Estimate of         VI-39
              Likely Impact

VI-17       Alaska, Cook Inlet, Preliminary Estimates of        VI-41
              Likely Impact

VI-18       California; Platforms and Offshore Oil, Gas         VI-44
              and Water Production in 1973

VI-19       Total Inferred Impact for Existing Sources in       VI-47
              the Gulf of Mexico as Derived from the
              Measured Impact

VI-20       Total Inferred Impact for New Sources in the        VI-48
              Gulf of Mexico

VI-21       Total Inferred Impact for New Sources Offshore      VI-52
              U.S.A.

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No.                                                            Page

VI-22       Economic Cost per Barrel of Oil Recovered,          VI-61
              Federal Waters

VI-23       Economic Cost per Barrel of Oil Recovered,          VI-62
              State Waters

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                       LIST OF FIGURES

 No.                                                           Page


II-l         1977 U.S. Petroleum Supply and Demand              11-19
               Functions (Accelerated Development Scenario)

II-2         Non-Associated Gas Reserves Additions per          11-54
               Foot Drilled in Wells Productive of Gas and
               Condensate, United States Excluding Alaska,
               1947-1972

II-3A        New Contract Production                            11-60

II-3B        New Field Wildcats Drilled                         11-60

II-3C        New Contract Gas Price                             11-60

II-4         After Tax Return on Net Worth, Petroleum vs.       11-66
               Other Manufacturing Companies - 1960 to
               1970

IV-1         Lease Plat Showing Platforms,  Wells, and Flow       IV-9
               Lines in Model

IV-2         Scheme of Production Platform A,  Model of a         IV-10
               Gulf of Mexico Operation

IV-3         Operating Costs (in $/B) Versus Average             IV-20
               Completion Productivity

IV-4         Age Distribution on Platforms  in Louisiana          IV-22
               Gulf Coast (Federal and State Waters)

IV-5         Total Investment in Production Unit as a            IV-23
               Function of Number of Platforms in Unit,
               Total Production Capacity of Unit

IV-6         Computer Flow Diagram,  Federal Waters               IV-28

IV-7         Computer Flow Diagram,  State Waters                 IV-29
 V-l         Percentage of Gas and Oil Producing Platforms       V-13
               with Daily Water Production Less Than or
               Equal to Water Production

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No.                                                         Page

VI-1        Sensitivity Tests, Gulf of Mexico,              VI-17
              Federal Waters

VI-2        Sensitivity Tests: Louisiana, State Waters;     VI-27
              Gulf of Mexico, Federal waters

VI-3        Power Requirements for Brine Treatment          VI-57
              Systems

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I.  EXECUTIVE SUMMARY






I.I.  SCOPE OF WORK







     The U. S. Environmental Protection Agency (EPA) is issuing interim




final effluent guidelines for the 1977 Best Practicable Technology Currently




Available and .proposed effluent guidelines for the 1983 Best Available Tech-




nology and the New Source Performance Standards for offshore oil and gas




production.  An economic impact analysis of the guidelines was performed by




Arthur D. Little, Inc. (ADL), under contract with the EPA and is reported




here.




     The economic impact analysis evaluated how many well completions would




be shut in rather than brought into compliance, the investment required by




the operators to come into compliance, and how much oil and gas production




would be foregone as a result of the guidelines.




     The impact analysis used costs of compliance developed by EPA and given




a general review by ADL.  The capability of the assumed treatment technologies




to meet the effluent standard and the availability of platform space for




installing the equipment has not been evaluated by ADL.




     Oil and gas is currently produced from three offshore U.S. areas:  the




Gulf of Mexico, California, and Alaska's Cook Inlet.  In 1973 the Gulf of




Mexico produced 74% of U.S. offshore oil and 97% of offshore gas.  California




produced 15% and 1%, respectively, and Alaska produced 11% and 2% of offshore




oil and gas.




     The economic impact analysis deals principally with the regulation's




effects in the Gulf of Mexico.  This is the area with the majority of production
                                 1-1

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and the area to experience the major impact.   Over 95% of the production




from offshore California leases appears to be in compliance at this time




with the 1983 treatment requirement.  The potential impact of the guidelines




on Cook Inlet production has not been possible to treat completely   because




of a lack of relevant data on the costs of production and the costs of treat-




ment and reinjection.  The potential impacts on Cook Inlet production have




been discussed qualitatively.






1.2.  INDUSTRY DESCRIPTION







    Beginning in the late 1940's, oil and gas have been produced from fields




off the U.S. coast.  In 1973, 17% of total United States oil production and




17% of gas production was from offshore wells.  While there was a small fall-




off in offshore oil production in the early 1970's, the offshore areas are




generally regarded as an increasingly important source of oil and gas




production.




     Historically, offshore operations have been dominated by the larger oil




companies.  In 1971, 63% of offshore oil production was from wells owned by




individual majors and another 34% was from wells owned by groups of majors.




The Department of the Interior has  encouraged the participation by smaller




firms in recent years and the predominance of the majors is declining.




     Revenues from offshore oil  production amounted to $1.64 billion as




compared with total U.S. oil production revenues of $10.35 billion in 1973.




Revenues from offshore natural gas  production were about $740 million in 1973.
                                   1-2

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    Prices of oil and gas are partially regulated.  Oil sold without




price regulations has a price approximately corresponding to the world




market, while regulated oil is sold at $5.25 per barrel.  Natural gas




sold in intrastate markets is selling at prices determined by supply and




demand; however, natural gas sold in interstate markets (the majority




of Gulf of Mexico production) is regulated to be $0.51 per thousand




cubic feet (MCF)).




    The prices of both oil and natural gas are a subject of strong




debate.  Serious proposals exist to deregulate both old oil and natural




gas in order to encourage more exploration and development of domestic




supplies.  On the other hand, major groups, such as segments of the




Congress, believe oil prices in particular are too high and more controls




should be imposed.  The economic impact analysis has tested a range of




potential prices since it is not possible to say with any certainty what




future price levels will be.




    The profitability of the oil industry has also been a subject of con-




siderable debate.  Historically, the industry has been about as profitable




as the average U.S. manufacturing sector.  However, a shadow of uncertainty




exists because of pending decisions by Government agencies on a number of




proposals which would vitally affect the industry.  Tax policies have




already been changed and may be changed again.  Decisions on price controls




and the excess profits taxes are not resolved.  The resolution of these




conflicting influences on the industry will be of far greater importance




to its profitability and financial structure than the proposed pollution




abatement regulations
                                  1-3

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1.3. SUMMARY OF CONCLUSIONS






     Based upon the assumptions stated In the body of this report, the




major conclusions of the economic impact ,  .lysis of the proposed




effluent guidelines on offshore U.S. oil and gas production and the




producing companies can be summarized as follows.








1.  The capital investment required to bring wells producing in 1974 in




    the Gulf of Mexico into compliance will be approximately $64-145




    million in 1977 and $50-56 million in 1983  in 1974 dollars.   Addi-




    tional investment will be required for wells drilled in tne Gulf after




    1974.







2.  Since almost all production from leases off the California coast is




    now in compliance with the proposed regulations, additional required




    investments will likely be very small, if any.






3.  The required investment for bringing offshore Alaska production into




    compliance has not been determined.  The costs will be higher than




     in the  Gulf  of Mexico  on  a per  barrel  of water  treated basis.






4.  The average  costs  including capital recovery  of  producing  oil from wells




    completed  in or  prior  to  1974  in  the Gulf of  Mexico will be  increased




    by about 9-31 cents per barrel  in  federal waters and about 12-16  cents




    per barrel in state waters in  1977. The production cost increase




    in state waters  in 1983 will
                                   1-4

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   be about  $.77-$1.08 per barrel. The costs of producing natural



    gas  from gas wells in the Gulf will  be increased by less than one-half




    cent per MCF in federal waters and state waters in 1977.  The estimated




    increase in production costs in 1983  will be  about one cent per MCF




    in state waters.  Production cost increases associated with California




    wells are expected to be negligible.
5.  For oil wells producing in 1974 in the Gulf of Mexico, and for which




    no price increases are possible, the effluent guidelines will result




    in 14-28 million barrels of oil and lease condensate not being ulti-




    mately produced, due primarily to shortened well life after 1983




    rather than well closures in 1977 or 1983.  The foregone production




    represents 0.6% to 1.2% of the total remaining potential production




    from the wells from 1977 to the end of their economic life, which may




    be beyond the year 2000, in the absence of the guidelines.  Similarly,




    the foregone production of non-associated and associated natural gas




    will be 81 to 249 million MCF in the absence of price increases to




    recover the costs which represent 03% to 1.0% of the total potential




    production from 1977 on.






6.  There will be      no       closures of companies as a direct result




    of application of the guidelines.






7.  There will be no significant effects on the profitability of the




    industry as a whole.  The profitability of firms operating primarily




    in state waters might be affected.






                                 1-5

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 8.   The  added  estimated  investment  in offshore  treatment and reinjection




     equipment  for  the  Gulf  of Mexico represents approximately 0.2-0.4%




     of expected  total  industry  capital  investment  in offshore production




     ($48 billion)  during the 1976-1983  period.  As  such, the pollution




     abatement-related  investment  should not materially alter investment




     plans of  the industry.






 9.   The  guidelines are not  expected to  discourage  the exploration  for or




     development  of new oil  or gas wells.   However,  the total lifetime




     production of  the  new wells will be reduced.   The 0.5%  to 1.2% re-




     duction in volume  produced  over the remaining  lifetime  in the  absence




     of price  increases of existing  oil  wells  in the Gulf of Mexico can




     be regarded  as an  upper limit to the percentage reduction in total




     lifetime production  of  oil  from new wells.   It's an upper limit because




     the  value of total lifetime production of the  wells producing  in 1977




     is  significantly larger than  their  remaining  lifetime production value




     as  of 1977.   The 0.3% to 1.0% loss  of remaining gas production can




     also be regarded as  an  upper  limit  for the foregone gas production




     from new wells if  price increases  are not possible  to recover the




     pollution abatement  costs for the  same reason.







10.   U.S. crude oil prices are now controlled  (old oil)  or move  with the




     world oil price (new or released oil). The higher  production costs




     resulting from compliance with the  proposed regulations may be re-




     coverable through allowed increases in old oil prices,  though such  an




     allowance is not assured,  nor are  the procedures  for  allowing such




     an  increase well established.  The  higher production  costs  associated
                                    1-6

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     with uncontrolled oil already priced competitively with imported  oil


     will likely not be recovered through price increases directly resulting


     from the added pollution control cost.   The added operating costs of


     pollution control would result primarily in reduced revenues for  the


     producer.



11.  The increases in the costs of producing interstate natural gas (the


     majority of Gulf of Mexico production)  will probably be substantially


     recovered by price increases approved by the FPC.  The procedure  for


     allowing such cost recoveries is well established, though cumbersome,


     and the pattern of recent FPC decisions indicates that the FPC would


     rule favorably on price increases to recover increased operating  costs


     as a result of new government regulations.


                                                  *
12.  The reduction in U.S. oil and gas production will be made up primarily


     by imports.  At $11 per barrel, the foregone oil production from  wells


     producing in 1974 represents $154 to $306 million in oil purchases


     abroad which would not otherwise have been made over about 25 years.


     The lost gas production from 1974 wells would require purchases of


     $162-498 million of foreign natural gas at $2.00 per MCF also over


     about 25 years.  The required purchase of imported oil and gas


     assumes the foregone domestic production will not be replaced by  coal,


     or nuclear power, and that U.S.  domestic production will not  equal


     U.S.  demand over the 25 year period.
                                    1-7

-------
                              TABLE 1-1
                       SUMMARY OF ECONOMIC IMPACTS
             THE OFFSHORE OIL AND GAS EXTRACTION INDUSTRY
Industry Description
  Number of Platforms
                       (Portion of SIC 1311)
                                Gulf of Mexico
  Number of Platforms
    Directly Discharging
  Number of Platforms with
    BPCTCA in Place
Costs (1974 Dollars)
(Gulf of Mexico wells producing
in 1974)
  Total for Industry
  Average per Platform
  Percent of Average Annual
    Investment in Offshore
    Production
Annual
  Total for Industry
  Average per Platform
  Percent of Sales
    Oil (Federal waters)
    Gas (Federal waters)
Expected Price Increases
(due to added pollution
control costs)
  Oil
  Gas
Platform Closures
(rather than invest in
abatement equipment)
750
510

180
California
   14
    0

   14
Alaska
  14
  14

  NA
       BPCTCA

    $64-145 million
    .11-.25 million
        1-2%
           BATEA

         $50-56 million
         .09-.10 million
             0.7%
    $36-78 million
    $71-153 thousand

       lZ-3%
           $20 million
           $40 thousand
                                none
                                none
        none
      < 0.5%
                none
                 2%

                27
                                   1-8

-------
                          TABLE 1-1 (Con't)
                                  BPCTCA
                          BATEA
Foregone Production
(between 1977 and 2000)
(from wells producing in 1974)

  Oil


  Gas
Jobs Lost

Community Effects

Impact on Industry Growth

Balance of Payment Effects
(Over 25 years)
14-28 million bbl's
(0.
-------
II.  CHARACTERIZATION OF THE OFFSHORE OIL AND GAS EXTRACTION INDUSTRY








II.1.  INDUSTRY STRUCTURE








1.1.  Industry Definition



     The activities of the oil and gas industry to be covered by the pro-



posed and interim final effluent limitation guidelines and the New Source



Performance Standards include production from offshore oil and gas wells.



     This report applies only to those offshore production facilities



physically attached to and an integral part of the production equipment.
                                             »


Firms which are primarily engaged in contract exploration activities or



contract drilling of wells are not covered by the effluent guidelines.



The drilling and exploration activities of firms operating offshore wells



are also not covered by the regulations.






1.2.  Offshore Oil and Gas Production



     Following lease sales to interested parties, the first phase of off-



shore development begins with exploratory drilling from mobile drilling



rigs which are positioned over suitable geological features located pre-



viously by geophysical techniques.  The purposes of exploratory drilling



are to define the existence of oil and/or gas fields.  Results of explora-



tory drilling are used to establish a plan for the development of the



newly discovered accumulations.  Several or more wells may be drilled to



confirm or deny the presence of hydrocarbons on any given oil and gas



prospect.
                                   II-l

-------
     The second phase of offshore development begins with the installa-




tion of fixed platforms from which a number of wells are directionally




drilled to tap the hydrocarbon pools existing in the oil and gas field.




Offshore drilling procedures are much the same as drilling on land,




except that marine drilling requires special equipment and considerable




logistical support with resulting higher costs/foot drilled than on on-




shore prospects.






     The engineering, construction, and operation of fixed offshore




platforms has evolved gradually since the first well was drilled out of




sight of land off of the coast of Louisiana in 1947. As offshore development



activity  has moved  into deeper waters and  increasingly hostile  environments,




fixed  platforms have become  extremely large,  self-contained  facilities which




can support as  many as  30  or 40  development  wells.   As the majority or all  of




the development wells  from a platform are  completed,  the platform begins




production of one or a  combination of crude  oil,  natural gas and  gas conden-




sate.   Formation water  —  typically a salt brine  — is usually  produced in




conjunction with oil.






     Typically, several producing platforms are linked by a pipeline




 gathering system to a  centrally located production processing platform.




 If oil and gas are  produced in association with each  other  (a common  case),




 the two are separated  at  the processing platform.  When only gas  is pro-




 duced, it may require  removal of associated water  (dehydration).  Formation




 water produced with oil is  separated and disposed  of.
                                    II-2

-------
     The producing areas discussed in this report are located off the




coasts of Louisiana, Texas, California, and Alaska.  Leases have also




been sold on acreage off Mississippi, Alabama, and Florida, and produc-




tion is expected in these areas.  The offshore areas are divided into




those in state waters within the three mile limit and those beyond the




three mile limit in Federal waters.  The Federal waters are called the




Outer Continental Shelf (DCS).






     Table  11-1  lists  the  historical  totals for offshore production  of oil




and condensate.  Table II-2  lists  the  natural gas  production, and Table II-3




compares  the offshore  production with  total U.S. production of oil and gas.




     As shown  in Table II-3,  total oil production  peaked in 1970 at  3.5




billion barrels  and declined in 1973  to 3.4 billion barrels.  While  the OCS




has  a large     potential  for new  production, 1971 saw  a peak OCS production




of 419 million barrels which declined  to  395 million barrels in 1973.  OCS




production  accounted for about  12% of  total U.S. oil production for  1971,




1972, and 1973,  up from 4.4% in 1964.   Total U.S.  gas production only increased




 from 20.7  trillion cubic  feet  in  1969  to 22.9 trillion cubic feet in 1973.




 The percent of  OCS gas production increased from  9.4% to 14% over the same




 period.







     In all of the  states  except Alaska,  where  there has been a jurisdic-




tional dispute,  the relative importance of the  producing areas has moved




from the  state waters  to the deeper  OCS waters.  Louisiana produced  429




million of  the 583 million barrels of  total offshore oil production  and 3.6




trillion  of the  3.9 trillion cubic feet of offshore gas production.  Louisiana's




oil production is 87%  from OCS  waters,  while  21% of California's is  from the OCS.
                                  II-3

-------






















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II-6

-------
1.3.  Demand for Oil and Gas

     It is not the intention of this report to analyze in detail future

energy demand or supply for the U.S.  The report will draw from the work

of reputable sources to broadly sketch the likely demand for oil and gas

over the period of interest.  The estimates will then be used as the

background for estimating the impact of the proposed pollution control

requirements on the offshore and onshore industry.

     The principal conclusion coming from an examination of the U.S.

demand for crude oil and the available supply is that demand is and will

likely continue to exceed domestic production under most realistic

scenarios.  The total demand for crude oil has grown at about 4.5% per

year over the period 1965-1973.  This growth, combined with a slow

decline in U.S. production since 1970, has resulted in an increasing

reliance on imports of both crude oil and refined products.  Growth in

domestic refining capacity has been less than the growth in U.S. con-

sumption of refined products.  The difference has been made up by

importing products from foreign refineries; in 1973, product imports

approximated 17% of total product consumption and were also 46% of both

crude and product imports.

     Domestic gas production has historically approximated consumption

and domestic supplies have not been sufficient for several years.  As a

result, imports are expected to grow to over 10% of consumption by 1985.
 Project Independence Blueprint, Final Task Force Report-Finance, p. 66,
 FEA, November 1974.
                                  II-7

-------
Note that the growth in natural gas usage averaged about 6.5% per year




from 1965 through 1970.  Annual growth following 1970 has been about




2.5%.  U.S. production increased by about 1% per year from 1970 through




1973.  The difference has been made up by imports which accounted for




about 7% of consumption in 1974.







1.4.  Oil and Gas Supply/Demand




     Petroleum and natural gas are primarily consumed as fuels.  Prior




to 1973, these energy forms and others were relatively inexpensive in




the United States.  The combined effects of industry practices and




government tax and pricing measures served to keep energy prices low.




The measures encouraged gas consumption.




     In the last 25 years, there has been a shift from a significant




dependence on coal to meet the U.S. energy demand to a predominant depen-




dence on oil and natural gas.  Table II-4  lists the components of U.S.




energy demand for 1970 and 1972.  Oil was the primary source of 45.5% of




energy consumed in 1972.  Natural gas accounted for 32.3%.  In 1950, coal




accounted for 37% of U.S. energy consumption, but coal's share had fallen




to 18% in 1974.




     With energy prices low, energy consul ntion has been regarded as




relatively price inelastic, particularly in the short run.  However, the




1973-1974 oil embargo, the rise in imported petroleum prices, and current




interest in energy conservation have highlighted the complex nature of




the energy demand function.  Energy consumption depends in a vital way




on a multitude of factors other than the short-run cost of producing the
                                   II-8

-------
                            TABLE II-
         U.S. ENERGY DEMAND BY PRIMARY SOURCE - 1972 and 1970
Energy Form                       1972                       1970
Oil
  Quadrillion Btu /year           32.8   (45.5%)              29.6   (44.1%)
  MM bbl/day                      16.5                       14.6
Gas
  Quadrillion Btu /year           23.3   (32.3%)              22.0   (32.7%)
  Trillion cubic feet/year        22.6                       21.4
Coal
  Quadrillion Btu/year            12.5   (17.2%)              12.7   (18.9%)
  MM Tons /year                   517                        532
Nuclear

  Quadrillion Btu /year           0.6    (0.8%)                0.2   (0.3%)


Hydro and Other

  Quadrillion Btu/year           2.9    (4.2%)                2.7   (4.0%)
Total
  Quadrillion Btu /year          72.1    (100%)               67.2   (100%)
SOURCE:   U.S. Bureau of Mines ,  cited in Project Independence Blueprint,
          Final Task Force Report - Finance, p. A-7, FEA, November 1974
                                  II-9

-------
energy.  Use of public transportation, living standards, building codes,




driving habits, land use planning, home heating habits, and industrial




processes are only a few of the factors affecting energy demand.  Many




of these factors are a reflection of the long-run price of energy but are




not readily changed in the short run.  It is also clear that political




considerations will be an important factor in determining both total




energy usage and the relative use of various energy formn.




     Prior to the embargo, total energy consumption was growing at 4.3%




per year.  This growth has since been reduced to 3.2% to 3.5% per year.




There was an actual decline of 2% in 1974, but there is no expectation




of a permanent decline trend in the foreseeable future.  The growth rate




may be temporarily or permanently lower, but there will be a continuing




and growing demand for new energy.




     In the case of petroleum, there is the potential for some substitu-




tion away from oil, such as the conversion of electric power plants to




coal.  There is also some potential for an absolute reduction in petro-




leum/energy usage in transportation; smaller cars and public transportation




at least present this possibility.  However, at best, the expectation  is




for growth in oil demand to be held very low but not to decline.  Since




1970, all of the growth in U.S. oil demand has been met by imported oil.




The Project Independence Report examined the potential for reducing the




level of oil imports and concluded that if there were strong government




action to accelerate domestic production and conservation and if world




oil prices were $11 per barrel, it would be possible to end imports by




about 1985.  At lower prices and with less vigorous government action,




some level of  imports would still be required in 1985.
                                   11-10

-------
     The continuing flow of imported oil at least to 1985 at prices




likely to be well in excess of production costs of all but marginal




domestic production will prevent even relatively large increases in the




costs of domestic production from acting to reduce demand for the domes-




tic crude below domestic production capacity.  Either increases or




decreases in total U.S. petroleum demand will mean changes in the level




of imports, not the level of U.S. petroleum production.  This pattern




will be particularly true for wells which are now in production.  Some




individual wells which are now high cost producers will be made uneco-




nomical by the higher production cost resulting from pollution control




requirements.  Short of domestic discoveries of unprecedented magnitude




and productivity, the demand for domestically produced oil will continue




to be well in excess of U.S. production capacity.




     A similar situation is seen in the case of natural gas.  There is




long-term potential for some substitution away from gas, for example, to




nuclear power and coal for electric power generation.  Imports are not




yet as important a factor as in oil, since the volume is not as great.




     Unlike oil, interstate gas is usually sold under long-term contracts




at regulated prices,which at present are low relative to the costs of




developing new gas wells or of close substitutes like oil.  Interstate




natural gas prices were (1974) 1/3 to 1/4 of the price of fuel oil prices




per BTU in major natural gas consuming areas.  Since the price of natural




gas is presently well below the next most expensive substitute, it is




unlikely that even relatively large pollution control costs, by themselves,




would have the effect of shifting demand away from gas to substitute
                                   11-11

-------
products.  The overall demand for natural gas will thus not be reduced

below U.S. supply capacity.  However, the supply might be affected if

some individual wells were made uneconomical as a result of higher pol-

lution control costs.

     Many estimates have been made of the future demand and supply of

oil and gas.  For this study, the estimates made in the Project Indepen-

dence Blueprint Report, November 1974, have been used.  The report

presents a series of estimates under different sets of assumptions.  The

assumptions include different levels of government efforts to encourage

energy conservation, to accelerate domestic energy production, and the

level of OPEC  oil prices.  The report makes clear that there are both

choices and uncertainties.  The oil and gas estimates are used in this

report in that light.

     The report constructed a set of estimates for a "base case" and

"accelerated supply case" under both a $7 and $11 per barrel world oil

price.  Table II- 5  lists the estimated U.S. energy demand by form, with

imported oil reported separately.  The base case assumed that government

policy towards energy, and particularly petroleum production, will be

essentially unchanged.  Leasing on the Outer Continental Shelf (OCS) will

remain at about 2-3 million acres per year.  Government royalties for
 Organization of Petroleum Exporting Countries, including Saudi Arabia,
 Iran, Venezuela, Nigeria, Libya, Kuwait, Iraq, United Arab Emirates,
 Algeria, Indonesia, Qatar, Ecuador and Gabon, which is an associate
 member.  The United Arab Emirates is a federation of Abu Dhabi, Dubai,
 Sharjah, Ajman, Umm al Quwain, Ras Al Khaimah and Fujairah.
                                    11-12

-------
                                  TABLE II-5
Energy Form




U.S. Oil




Imported Oil




Gas




Coal




Hydro & Geo.




Nuclear




Synthetics







    Total
U.S. ENERGY DEMAND BY PRIMARY SOURCE -



1972

22.4
11.7
22.1
12.5
2.9
0.6
(Quadrillion Btu's)
1985
$7 Oil
Base Case Accelerated
Supply
23.1 30.5
24.8 17.1
23.8 24.7
19.9 17.7
4.8 4.8
12.5 14.7
1985


$11 Oil




Base Case Accelerated
Su]
31.3 38
6.5 0
24.8 25
22.9 20
4.8 4
12.5 14
pply
.0
.0
.5
.7
.8
.7
Ji.
72.1
109.1
109.6
102.9
104.2
SOURCE:   Project Independence  Report,  FEA,  November 1974,  p.  45
                                           11-13

-------
the leases would remain at one-sixth.  Natural gas for interstate sale




would be regulated at $0.89 per thousand cubic feet.  Under the "accele-




rated development" case, leasing would be increased to 10 million acres




per year, and royalties would be reduced to one-eighth.  Natural gas




price regulations would be ended, with prices rising to $1.75 per thousand




cubic feet by 1988.  Development would also be allowed in the Naval




petroleum reserves.




     The values in Table II-5  reflect FEA's estimate  (based on $7/bbl




crude) of long-term growth rate of U.S. energy consumption (3.1%/year).




At oil prices of $11 per barrel, the annual energy growth rate was esti-




mated to be 2.9%.  There is some shift away from oil to gas and coal,




but not a significant reduction in overall energy demand.  The projection




of such reductions from the historic growth rate of 4.3% are an important




uncertainty in the analysis.




     Table II-6  is a more detailed  listing of U.S. oil production esti-




mates with the additional estimate of production levels if the world




price dropped to $4 per barrel.  In  all cases, domestic production would




continue to decline out to 1977.  Table II-7  lists the estimated sources




of new U.S. oil production if the world oil price is $11 per barrel.




Offshore production amounts to 2.9 million barrels per day, or 19% of



the total U.S. production, under the "business as usual" (base case)




scenario in 1985.  New DCS production is 4.8 million barrels per day




(24%) under the accelerated development case.




     Table II-8  lists the estimated gas production assuming the $11 per




barrel world oil price and accelerated development.  The report saw very
                                    11-14

-------
                                  TABLE II-6


                    U.S. CRUDE OIL PRODUCTION - 1974 TO 1985
                            (millions barrels per day)


                            "Business as Usual" Case

World Price ($/bbl)          1974     1977     1980     1985

      4
      7
     11
       4
       7
      11
10.5
10.5
10.5
9.0
9.5
9.9
9.3
11.1
12.2
9.8
11.9
15.0
                            "Accelerated Development" Case
10.5
10.5
10.5
9.7
10.2
10.3
11.1
12.9
13.5
11.6
16.6
20.0
SOURCE:  Project Independence  Report, FEA, November 1974, p. 81
                                 11-15

-------
                                       TABLE II- 7
    Production Area
    Onshore - Lower 48 States
    - Conventional fie
      primary fields
    - New secondary
    - New tertiary
    - Natural gas liquids
    - Naval Petroleum
    Alaska
    - North Slope
    - Gulf of Mexico
    - California DCS
    - Atlantic DCS
4.   Heavy Crude and Tar Sands
POTENTIAL RATES OF U.S. OIL PRODUCTION



f barrels per day, at $11 per barrel world prices)

"Business
1974 As Usual"

ates 8.9 9.1
; and new
6.4 3.4
2.4
1.8
i 2.0 1.5
erve #1
0.2 3.0
2.5
eluding OCS) 0.2 0.5
erve #4 - -
.ental Shelf 1.4 2.6
1.3 2.1
0.1 0.5
-
;ands - 0.3
1985
(change)
(1-2)
(-3.0)
(2.4)
(1-8)
(-0.5)

(2.8)
(2.5)
(0.3)
,
(1.2)
(0.8)
(0.4)

(0.3)

"Accelerated
Development"
9.9
3.5
2.4
2.3
1.6
0.2
5.3
2.5
0.8
2.0
4.3
2.5
1.3
0.5
0.5
(change)
(1.0)
(-2.9)
(2.4)
(2.3)
(-0.4)
(0.2)
(5.1)
(2.5)
(0.6)
(2.0)
(2.9)
(1.2)
(1.2)
(0.5)
(0.5)
    Total Potential Production
10.5
15.0
(4.5)
20.0
(9.5)
    SOURCE:  Project Independence Report, FEA, November 1974,  p.  83
                                           11-16

-------
                              TABLE II-8
                 U.S. NATURAL GAS SUPPLIES. 1972-1985*
                  (trillions of cubic feet per year)

Source                            1972        1977       1980       1985

Lower 48 States,Onshore           19.4        16.7       17.4       15.5
Lower 48 States, Offshore          3.0         4.4        6.1        8.2
Alaska (except North Slope)        0.08        0.02       0.03       0.1
Naval Petroleum Reserve #4         0.0         0.0        0.0        0.8
North Slope                        0.0         0.0        0.8        2.5
Coal Conversion                    0.0         0.0        0.0        0.2
   TOTAL                          22.5        21.1       24.3       27.3
 Assumes $11 per barrel world oil prices and accelerated development scenario.

SOURCE:   Project Independence  Report,  FEA,  November 1974 , p. 48
                                  11-17

-------
limited potential for U.S.-produced gas to maintain its present share




of energy consumption.  Offshore production is estimated to account for




31% of gas production in 1985 under an accelerated development assump-




tion, as compared with 13% in 1972.




     The essential conclusion from an examination of the supply and




demand forecasts for oil and gas out to 1985 is that even relatively




large increases in the cost of producing domestic crude and gas will not




result in a reduction of demand below the capacity of U.S. production at




$7 or $11 per barrel price levels.




     To illustrate the role of imports in the relationship between U.S.




oil supply and demand, Figure II—1A was constructed from the crude oil




supply and demand estimates in the Project Independence Report.  An




imports supply curve has been drawn showing that at $11 per barrel, at




least 5 MM bbl/day can be purchased but none can be purchased for less




than $11 per barrel.  With a supply/demand relationship as shown in




Figure II-l , a shift in the U.S. supply curve as a result of an industry-




wide change in production economics, such as resulting from new pollution




control costs, will not change the intersection of the total U.S. supply




curve and the U.S. demand curve.  The total quantity of oil consumed will




remain essentially unchanged, as would the price.  The difference between




total demand and available U.S. supply would be made up by imports. Thus,




the demand for U.S. production at the equilibrium price of $11 per barrel




would remain both unchanged and greater than U.S. production capacity at




$11 per barrel.
                                   11-18

-------
15

14


13


12

11


10

 9
I   8
Q.
0)
-a
             o
             Q.
             a
             1/3
             o
             O
             to
             D
                                                      Total U.S. Petroleum
                                                      Demand Curve
                                    U.S. Offshore Plus Onshore
                                    Supply Curve,
                                                             Total U.S. Crude Oil
                                                             Supply Curve
                                   6789

                                   Demand/Production
                                    (MM bbls/day)
                                                    10
11
12   13
14
15
                FIGURE 11-1    1977 U.S. PETROLEUM SUPPLY AND DEMAND FUNCTIONS
                               (Accelerated Development  Scenario)
     SOURCE:   Drawn from projected  supply and demand  values in  Oil:  Possible  Levels
               of Future  Production,  Project Independence Blueprint,  FEA, Nov.  1974
                                            11-19

-------
     Figure II-l  also shows the domestic supply curve to be almost ver-




tical above $9 per barrel.  Increasing prices from $9 to $11 per barrel




will increase total U.S. production by only a small amount in 1977, accor-




ding to the Blueprint estimate shown in the figure.  While a shift in the




U.S. supply curve as mentioned above will result in lower U.S. oil pro-




duction (to be made up by imports), the nearly vertical U.S. supply curve




suggests that the production losses will be small for production cost




increases as large as $2 per barrel.
                                  11-20

-------
II.2.  CHARACTERIZATION OF OFFSHORE OIL AND GAS PRODUCING COMPANIES






     Until the early 1970's, the vast majority of U.S. offshore oil and




gas production came from wells owned and operated by the large integrated




oil companies.  The large "up front" costs of lease bonus payments and




the massive investments required for exploration, development, production,




and processing facilities tended to discourage all but the largest firms




from undertaking offshore projects.  Table II-9  shows the participation




of the major oil companies in offshore production in 1971; in that year,




the major integrated companies operating independently or in groups




accounted for 97% of OCS oil production.  Recent efforts have been made




by the Interior Department to allow more participation by smaller com-




panies.  Since 1971, there has been an increased participation by the




independents in acquiring offshore acreage.  For the three lease sales




of September and December 1972 and June 1973, single majors acquired 21%




of the acreage, groups of majors acquired 14%, single independents




acquired 17%, and groups of independents and majors acquired 47% of the




acreage.




     The companies attempting to acquire offshore acreage for oil and gas




development bid either independently or in groups for the right to develop




and produce the fields.  If a consortium of companies wins the bidding,




one of the firms will be responsible for drilling and operating the wells.




Table 11-10 lists, as an example, the ownership relationship of the firms




operating in Federal waters off Louisiana in 1973.  Table 11-11 lists




major oil companies and their partners owning leases in Louisiana state




waters the same year.
                                    11-21

-------
                              TABLE II-9
         PCS LEASE ACREAGE AND PRODUCTION, THROUGH SEPT. 1971
Lessee
Acreage (%)
Production (%)
Individual Majors

Groups of Majors

Groups of Independents

Individual Independents
46
35
17
2
63
34
2
1
SOURCE:  U.S. Department of the Interior, reported in Outer Continental
         Shelf Policy  Issues, p.  61, Committee on Interior and  Insular
         Affairs, U.S.  Senate, 1972
                                     11-22

-------
                        TABLE II-1Q
-LOUISIANA LAND 1 EXPLORATION CO., DOCKET NO CI73-501, JOINT OWNERSHIP OF FEDERAL
                     OFFSHORE PRODUCING LEASES


Company
The majors:
Amerada-Hess 	


Atlantic-Rich field 	






Cities Service 	






Continental 	









Getty 	











Gulf 	




Marathon 	




Mobil 	 	 	








Phillips 	





Shell 	
Chevron 	



Amoco 	








E««on 	
Sun 	 —







Teiaco 	 	 	 	
Union Oil 	




Number of Independently
leases owned Major partners
15 0 Marathon 	 	 	
Signal 	
Louisiana Land 	
	 94 3 Cities 	
Getty 	
Continental 	 	
Tenneco' 	
Standard Oil of California
(Chevron) 	
El Pasoi 	
	 101 1 Atlantic 	
Getty 	 	 	
Conti nental 	
Mobil 	
Tenneco' 	
Standard Oil of California
(Chevron).
	 119 1 Atlantic 	
Cities 	
Getty 	
Mobil 	
Tenneco ' 	
Standard Oil of California
(Chevron).
Superior 	
Trans ocean 	 	
Southern Natural > 	
	 100 2 Atlantic 	
Cities 	
Continental 	
Mobil 	
Tenneco ' 	
Standard Oil of California
(Chevron).
Phillips 	
Superior 	
Transocean 	
Southern Natural1 	
Allied Chemical 	
51 34 Mobil..
Standard Oil of New jersey
(Exxon).
Phillips ..
Kerr-McGee 	
	 18 0 Amerada.
Signal 	 	 	
Louisiana Land. . . .
Union... . 	
Sun 	
52 6 Continental 	 - 	 --
Cities 	 	 	
Getty 	
Gulf 	
Standard Oil of California
(Chevron)
Standard Oil of New Jersey
(Exxon).
Standard Oil of Indiana (Amoco).
Pennzoil 8 	 	 	 	
16 3 Kerr-McGee 	 	
	 Gulf 	 	 	
Getty 	 	
Standard Oil of Indiana (Amoco).
Sun 	
Southern Natural" 	
Allied Chemical 	
68 64 Standard Oil of California
(Chevron).
105 86 Mobil 	
	 Getty 	
Atlantic 	
Cities 	 	
Continental 	
60 3 Texaco 	
Union 	
Southern Natural ' 	 	
Mobil 	
Kerr-McGee 	
Superior 	
Tenneco ' 	
Phillips 	 	 	 	
Pennzoil' 	
Texas Eastern ' 	
52 43 Gulf 	 - 	
	 Mobil 	 	 	 --
19 0 Burmah 	
Murphy 	 	 	
Kerr-McGee 	 .-
Union 	
Phillips 	
Marathon 	
Cabot 	
Diamond Shamrock 	 	
Anadarko1 ._ 	
55 16 Standard Oil of Indiana (Amoco)
Tenneco '.. 	 	
37 18 Standard Oil of Indiana (Amoco).
Marathon 	
Superior — 	
Sun 	
Texas Eastern ' 	
Number
of |omt
ventures '
13
14
1«
85
83
87
4

2
2
85
93
91
2
7
2

87
91
87
19
8
2

2
2
2
83
93
87
8
4
3

3
2
2
2
3
7
6

4
2
13
13
13
5
3
19
8
8
7
5

4

4
2
7
4
3
3
3
2
3
2
5
3
2
2
2
29
12
8
4
4
4
3
3
4
2
6
4
11
10
4
3
3
3
3
3
3
29
12
4

2
                             11-23

-------
                         TABLE II-1Q  (Con't)
            -LOUISIANA LAND i  EXPLORATION CO, DOCKET NO CI73-501, JOINT OWNERSHIP OF FEDERAL-
                          OFFSHORE PRODUCING LEASES—Continued




Number of Independently
Company
Selected medium sized firms.
Tenneco Oil * 	 	 	






Kerr-McGee 	


Carjot Corp 	 _.
Pennzoil -. . - 	 - 	
Consolidated • 	



Columbia Gas ! 	 	



Texas Gas '.. 	



ForestOil 	 . . 	



Murphy-Ocean 	

Burmah 	 	 	

Signal 	 - 	


Louisiana Land & Exploration 	


Superior 	 _ 	


Transocean 	



Hunt 	


Ashland 	 - 	


Southern Natural! 	

Allied Chemical 	 	 	

Anadarko' 	 ; 	

Diamond Shamrock 	

Texas Eastern1 	 	 	

f.l Paso' 	 	 	
Placid 	 	 	


leases

51






29


12
9
33



33



28



34



32

23

15


14


21


14



17


7


15

3

3

4

2

2
15


owned

24






0


0
1
0



0



0



c



1

0

1


0


10


c



3


0


0

0

0

0

0

0
0


Major partners

Texaco . . 	
Continental.. 	 	 	
Cities.. , 	 	 	
Consolidated * 	
Columbia Gas ! 	
Texas Gas Transmission - . ...
Forest 	 	 	 	
Phillips 	
Cabot 	 	 	
Soutnerr, Nat : 	
Sun .-. . - 	 - 	 -
Kerr-McGee 	 	
S'andard Oil cf Insiana 	 ..
Columbia Gas - 	
Texas Gas Trarsmission: 	
Forest 	 	
Tenneco :. . 	 ... 	
Consolidated : 	
TexasGas* 	 	 	 	
Fo'es; 	 - 	 	
Tenneco ' 	
Consolidated >. 	 - 	
Columbia Gas' 	 	
Forest 	
Tenneco' 	
Consolidated' 	
Columbia Gas '. 	
Texas Ga;' 	
Tenneco1 	 	
Sun 	
Burmah 	
Sun 	
Murphy-Ocean 	
Amerada 	
Marathon 	
Louisiana Land 	 	 	
Amerada 	
Marathon 	
Signal 	
Standard Oil of Indiana (Amoco).
Union 	
Transocean 	 	 	
Superior 	 	 	
Hunt 	 - 	 - 	
Placid 	 	
Ashland 	 - 	
Transocean 	 	
Placid 	
Ashland... 	
Transocean 	 --
Hunt 	
Placid 	 	 	
Standard Oil of Indiana (Amoco).
Kerr-McGee 	
Getty 	 	 	
Phillips 	
Sun 	
Diamond Shamrock 	
Sun 	
Anadarko' 	 	
Standard Oil of Indiana (Amoco).
Union 	 	
Atlantic 	 	 	
Transocean 	 	 	 	
Hunt 	
Ashland 	 	 	 	
Number
of joint
ventures >
-
9
8
7
6
6
e
6
7
12
t
3
12
4
26
25
26
6
26
27
33
6
25
26
23
6
2?
37
26
8
10
21
11
a
14
13
14
14
13
14
4
4
7
7
7
7
7
7
9
7
7
7
7
8
8
3
3
3
I
3
3
2
2
2
7
t
^
       • Mav add to more than total number of leases v.hen 3 or more firms participate m mdtudua1 joint ventures.
       ' This company or an afftliats is a major interstate gas pipeline
SOURCE:   U.S. Dept.  of  the  Interior, cited  in Market Performance
           and Coiivpeuition in the Petroleum  Industry,  p.  iibD,
           Committee  on Interior  and  Insular  Affairs,  U.S. Senate, 1974
                                 11-24

-------
                                              TABLE 11-11
                                . —LOUISIANA LAND & EXPLORATION CO., DOCKET NO CI73-501

                  JOINT OWNERSHIP OF STATE OF LOUISIANA PETROLEUM LEASES BY LARGE MAJOR PRODUCERS
           Company, major partners, and jointly held State
             leases.
                                                Number
              Amerada-Hess.
                 Phillips	   36
                 Amoco		   10
                 Sohio   	    2
              Atlantic-Richfield.
                 Cities   	   27
                 Continental	   28
                 Getty	   26
                 Union	_	   10
                 Marathon	_.	    7
                 Texaco		-	    4
                 Tenneco	    4
                 Amoco		'	    3
                 Chevron			    2
                 Sohio	    2
              Cities Service
                 Atlantic	   27
                 Continental		   27
                 Getty	   31
                 Exxon	    2
              Continental.
                 Atlantic	   28
                 Cities	   27
                 Getty	   27
                 Mobil	   16
                 Exxon	   13
                 Amoco    	-	   11
                 Sun..	   11
                 Tenneco	    3
                 Gult	    3
              Getty:
                 Gulf	   51
                 Atlantic	   26
                 Cities	   31
                 Continental	   27
                 Exxon  		 27
                 Sohio		  <
                 Tenneco	  4
                 Amoco			  4
                 Mobil    	  3
                 Sun	  3
                 Shell		  2
                 Texaco	  2
              Gulf
                 Exxon				- 62
                 Getty		 51
                 Sohio	 13
                 Shell..	 12
                 Amoco.			  7
                 Texaco	  6
                 Chevron		  6
                 Tenneco.			  5
                 Mobil		  5
                 Continental		  3
                 Sun..	  3
                 Phillips	  2
                 Amerada	  2
              Marathon*
                 Atlantic.	  7
                 Tenneco			  3
              Mobil.
                 Continental	 16
                 Amoco     			  8
                 Gulf	  5
                 Sun	_	  4
                 Texaco			  4
                 Tenneco	  3
                 Getty	  3
                 Exxon			  2
              Phillips:
                 Amerada  			 36
                 Sun	  7
                 Amoco	  3
                 Gulf	  2
              Shell:
                 Gulf	 12
                 Chevron	  8
Company, major partners, and jointly held State
  leases
                                     Number
       Exxon			   5
       Amoco	-		   5
       Texaco	   5
       Getty	   2
   Chevron:
       Shell	   8
       Gulf	   6
       Texaco	   3
       Exxon	_	   3
       Atlantic	   3
   Amoco'
       Texaco	   11
       Continental		   11
                                          10
                                          8
                                          7
                                          5
                                          5
                                          5
                                          4
                                          4
                                          3
                                          3
                                          3

                                          62
                                          27
       Continental	  13
   Amerada
   Mobil...
   Gulf	
   Shell....
   Sun	
   Tenneco.
   Exxon...
   Getty....
   Atlantic.
   Phillips.
   Union...
Exxon'
   Gulf	
   Getty
       Texaco.
       Tenneco..
       Shell	
       Amoco...
       Chevron.
       Mobil....
       Cities	
       Union	
   Sohio:
       Gulf	
       Getty	
       Atlantic..
                                      11
                                       5
                                       5
                                       4
                                       3
                                       2
                                       2
                                       2

                                      13
                                       4
                                       2
   Amerada		-		  2
Sun.
   Continent 1		 11
   Phillips...	  7
   Amoco			  5
   Mobil			  4
   Getty	  3
   Gulf				  3
   Tenneco		  3
   Union		—		  3
Tenneco
   Exxon...	  5
   Amoco	—	  5
   Gulf		  5
   Atlantic				  4
   Getty		  4
   Continental..	  3
   Marathon	,		  3
   Mobil	  3
   Sun		,	  3
Texaco:
   Exxon	 11
   Amoco	-		 11
   Gulf....	  6
   Shell	  5
   Mobil..	  4
   Atlantic	--  4
   Chevron	  3
   Getty	-	  2
   Union			  2
Union Oil:
   Atlantic	 10
   Amoco	  3
   Sun	  3
   Exxon	  2
   Tex»co	  2
SOURCE:    U.S.  Dept.  of  the  Interior,  cited  in  Market  Performance
               and   Competition  in  the  Petroleum  Industry,  p.1167,  Committee
               on  Interior  and  Insular  Affairs,  U.S.  Senate,  1974
                                                       H-25

-------
     Besides the major integrated oil companies,  the largest group of




offshore participants are the interstate gas pipeline companies.




Tables 11-12, 11-13* and 11-14 list the major pipeline operators  and




show their 1972 participation in the lease bidding.   In the December 19,




1972, bidding on Federal OCS acreage off Louisiana^  pipeline companies




participated in 51.7% of the successful bids and paid 19.5% of the bonuses.




     On February 21, 1975, the Interior Department published a proposed




regulation in the Federal Register that no companies producing more than




1.6 million barrels a day of crude oil, natural gas (equivalent), and




natural gas liquids could jointly bid with other such companies on OGS




leases,  the intent of the regulation is to further reduce the dominance




of the major oil companies in offshore production.
                                   11-26

-------
                                      TABLE  11-12
                  -LOUISIANA LAND AND EXPLORATION CO., DOCKET N6. C173-501-MAJOR INTERSTATE GAS PIPELINES
                                         AND THEIR PRODUCING AFFILIATES


              Interstate pipeline companies     Exploration, development, and producing affiliates


          Arkansas Louisiana Gas Co	 Arkla Exploration Co.
          Cities Service Gas Co		 Cities Service Oil Co., Cities Service Gas Resources Co., Hydrocarbon Production
                                           Co., Inc.
          Colorado Interstate Gas Co	 Coastal States Gas Producing Co., LO-VACA Gathering Co , Colorado Oil and Gu
                                           Corp.. Nueces Industrial Gas Co.
          Columbia Gas Transmission Corp	 Columbia Gas Development Corp.
          Consolidated Gas Supply Corp	 CNG Producing Co.
          El Paso Natural Gas Co		 Odessa Natural Gasoline Co., Odessa Natural Corp., Trebol Drilling Co., PecosCo.
          Florida Gas Transmission Co	 Florida Gas Exploration Co.
          Lone Star Gas Co	 Lone Star Producing Co.
          Michigan Wisconsin Gas Co	 American Natural Gas Production Co.
          Natural Gas Pipeline Co. of America... Harper Oil Co.
          Northern Natural Gis Co	(Produces under its own name )
          Panhandle Eastern Pipeline Co	 Anadarko Production Co., Pan Eastern Exploration Co., Panhandle Western Gas
                                           Co.
          Southern Natural Gas Co	SONAT Exploration Co., The Offshore Co.
          Tennessee Gas Transmission  Co	Tenneco Oil Co.
          Tennessee Gas Pipeline Co.	 Tenneco Exploration, Ltd., Tenneco Offshore Co , Inc.. Tenneco West, Int.
          Texas Eastern Transmission Corp	 La Gloria Oil and Gas Co ,  Texas Eastern Gas Supply Co., Texas Eastern Maroc,
                                           Inc., Texas Eastern Exploration Co.. Texas Eastern Oil Co.
          Texas Gas Transmission Corp		Texas Gas Exploration Corp.
          Transcontinental Gas Pipeline Corp	 Transcontinental Production Co., Trans-Gulf Transmission Corp.
          Transwestern Pipeline Co '	 Transwestern, Inc., Transwestern Gas Supply Co.
          Trunkhne Gas Co.1	
          United Gas Pipeline Co	 Pennzoil Producing Co., Pennzoil Petroleums, Ltd , Pennzoil Louisiana & Tex«s
                                           Offshore, Inc., Pennzoil Offshore Gas Operator, Inc.


            1 Subsidiary of Texas Eastern Transmission Corp.
            ' Subsidiary of Panhandle Eistern Pipeline Co.
SOURCE;    U.S.  Dept.   of  the  Interior,  cited  in Market  Performance
               and  Competition  in the  Petroleum Industry,   p.  1170,
               Committee  on  Interior  and   Insular  Affairs,   U.S.   Senate
               1974
                                                    11-27

-------
                                   TABLE  11-13
         -PARTICIPATION BY INTERSTATE PIPELINE COMPANY AFFILIATES IN OFFSHORE LOUISIANA FEDERAL
                           OIL AND GAS LEASE SALE, SEPT. 12,  1972
     Interstate pipeline affiliation/bidding group
  Successful
bids (number
   of leases)
Bonuses paid
  by pipeline
    affiliate
   (dollars)
    Pipeline
   affiliates'
  percent o*
bonuses paid
    (rangt)
Texas  Eastern Transmission Corp.. Texas  Eastern  Exploration
  Co ,' Amoco Production Co . Union Oil Co of California	
Cities Service Gas Co :  Cities Service Oil Co.,' Tenneco Oil Co,'
  Continental Oil Co , Getty Oil Co	
Tennessee Gas Pipeline Co Tenneco Oil Co ,' Cities Service Oil
  Co.,1 Texaco, Inc , Continental Oil Co.	_.
United Gas Pipe Line Co : Pennzoil Offshore Gas Operators,' Penn-
  zoil L & T. Offshore,  Inc.,' Cult Oil Corp . Mobil Oil Corp	
United Gas Pipe Line Co • Pennzoil Offshore Gas Operators,' Penn-
  zoil L & T  Offshore. Inc ,'• Mesa Petroleum Co., Burmah Oil
  D«v  , Inc , Canadian Occidental Ca.. Inc	
Florida Gas Transmission Co.  Florida Gas Explor. Co.,' Shell Oil
  Co., Sabme Explor Corp , Drillamex, Inc., Kirby Petroleum Co.,
  Royal Gorge Co., American Independent Oil Co	
Consolidated  Gas Supply Corp.. Consolidated Gas Supply Corp.,'
  Aztec Oil and Gas Co	
     Total pipeline affiliates' successful bids.

     Percent of total successful bids	
         21

         2

         4

         4
                                                              33
  19, 523, 520

   1,993,685

   6, 568,143

  30.039, 200


   4,532,792


    747.600

    191.925
                63, 5%, 865
      24-36

      33-34

      33-80

       7-1J


        JJ


        12
                                                            53.2
                                                                          10.8
  i Corporate affiliate of interstate pipeline company.
  Source: Bid recap sheets, Bureau of Land Management, Department of the Interior, oil and (as lease sate, oftshort
Louisiana, Sept. 12,1972.

cited   in  Market  Performance   and   Competition  in  the

Petroleum  Industry,  p.   1170,  Committee  on  Interior

and  Insular  Affairs,  U.S.  Senate,   1974
                                             11-28

-------
                                      TABLE  11-14
           -PARTICIPATION  BY INTERSTATE PIPELINE COMPANY AFFILIATES IN  OFFSHORE LOUISIANA
                         FEDERAL OIL AND GAS LEASE SALE, DEC. 19, 1972
     Interstate pipeline affiliation/bidding group
              Bonuses paid
  Successful      by pipeline
bids (number        affiliate
   of leases)        (dollars)
    Pipeline
   affiliates'
  percent of
bonuses paid
     (range)
Columbia Gas Transmission Co	
    Columbia Gas Development Corp.1
    Forest Oil Corp.
    Energy Ventures, Inc.
Consolidated Gas Supply Corp	
    CNG Producing Co.'
    Amoco Production Co.
    The NW Mutual Life Ins. Co.
Cities Service Gas Co	
    Cities Service Oil Co.'
    Getty Oil Co.
    Continental Oil Co.
    Atlantic Richfield Co.
Southern Natural Gas Co	
    Sonat—Exploration Co.'
    The Offshore Co.
    Midwest Oil Co.
    Newmont Oil Co.
    Southland Royalty Co.
    Samedan Offshore Co.
    Champlin Petroleum Co.
Trans Continental Gas Pipe Line Corp	
    Trans-Continental Prod.  Co.'
    Shell Oil Co.
Texas Eastern Transmission Corp	
    Texas  Eastern Exploration Co.'
    Louisiana Land and Explor. Co.
    Signal Oil & Gas Co.
    Marathon Oil Co.
United Gas Pipe Line Co	
    Pennzoll Offshore Gas Operators'
    Pennzoil L. & T. Offshore, Inc.'
    Mobil Oil Corp.
    Chevron Oil Co.
    Texas  Production Co.
United Gas Pipe Line Co	
    Pennzoil ONshore Gas Operators'
    Pennzoil L. & T. Offshore, Inc.'
    Mesa Petroleum Co.
    Burmah Oil Dev., Inc.
    Texaa  Production Co.
Tennessee Gas Pipeline Co	
    Tenneco Exploration, Inc.'
    Texaco, Inc.

     Total—pipeline affiliates' successful bids.

     Percent of total successful bids	
         7      80,015,311



         7      24, 321,180



         16      47, 453, 678




         1      7, 038, 899







         13      S3, 418, 570


         6      20, 582, 750




         3      15, 501,506





         1      20,903,880





         6      55,147,808
        60    324,383.582
       51.7
                     19.5
                                                                                           40
     25-34
      25-50
        28
      19-25


      14-33
       7-27
      7-27
        50
  ' Corporate affiliate of interstate pipeline company.
  Source' Bid recap sheets, Bureau of Land Management, Department of the Interior, Oil and Gas Lease Sale—Offshore
Louisiana—December 19, 1972.

cited  in  Market  Performance  and  Competition in  the

Petroleum  Industry,  p.   1171,  Committee   on  Interior

and  Insular  Affairs,  U.S.   Senate,   1974
                                           H-29

-------
II.3.  OIL AND GAS PRICING




3.1.  Crude Oil Pricing




     The Role of Crude Prices in the Economic Impact Analysis




     The price of crude oil and the factors and processes which determine




its price have undergone dramatic changes in the last few years.   While




oil from different fields has distinct physical and chemical properties,




it can be characterized by and large as a world commodity product.  As




such, its price should be subject to the movements of world supply and




demand.  However, the political implications of crude prices and crude




sources have strongly distorted prices even before the recent embargo.




    The price which operators of domestic oil wells can receive for their




crude is a critical element in determining the impact of the proposed




effluent limitation guidelines.  At sufficiently high prices, there would




simply be no potential for the pollution control costs making an exist-




ing well unprofitable.  Yet the uncertainty about U.S. crude prices over




the period when the guidelines will become effective, 1977-1983, is an




unresolvable unknown.




    At present (January 1975), prices for U.S. "old" crude are frozen at




$5.25 per barrel while "new", released, and stripper well crude prices




are uncontrolled.  However, there is a major public policy debate in pro-




gress concerning the pricing of domestic crude.  The argument is being




made that all price controls should be removed in order to accelerate the




development of domestic oil resources.  Since new oil is already deregulated,




the removal of controls from old oil would have the effect of providing




additional capital to the oil companies to undertake new exploration and
                                   11-30

-------
production.  The argument on the other side is that there are already




ample incentives for new exploration and development, that oil companies




could not effectively spend the added funds, and that the only effect of




deregulation would be to raise the price of petroleum products to consumers.




This debate is further complicated by serious proposals to impose excess




profits taxes, and break off the marketing segments of the producing com-




panies .




    Most offshore and onshore production to which the effluent guidelines




would apply are now price controlled.  Deregulation would increase these




prices to the level of imported crude.  This impact analysis cannot even




speculate whether deregulation will occur.  The limit of the analysis is




a statement about the impact of the proposed standards on production if




they occur after crude oil prices have been deregulated.  Recent tax




legislation has effectively ended the depletion allowance for large pro-




ducers.  This change in tax policy has been included in the impact analysis,




but other possible changes in tax policies or industry structure are beyond




the scope of this analysis, though they could have an important influence on




the industry.




     Current Crude Oil Pricing Patterns




     Domestic crude oil prices have fluctuated very little for 18 of the past




20 years.  The years 1973 and 1974 broke this pattern.  In 1955, a barrel of




crude oil sold for $2.77.  By 1971, the price for the same barrel had risen




to $3.10.  However, in 1973 most domestic crude prices had risen to $5.25 per




barrel and would probably have been higher except for a formula worked out by




the Federal Energy Agency (FEA) which imposed regulations on crude prices.




Table 11-15 lists crude prices for various sources for the last five years.







                                 11-31

-------
            TABLE 11-15
HISTORICAL POSTED CRUDE OIL PRICES
CRUDE
Arab light
Iran light
Kuwait
Abu Dhabi Murban
Iraq Basrah
Qatar Dukhan
Iraq Kirkuk
Libya
Nigeria
Sumatra light**
Venezuela Tia Juana (31°)**
Venezuela Oficina**
Louisiana
East Texas
West Texas sour
*Year's highest price given
1970
1.80
1.79
1.59
1.88
1.72
1.93
2.41
2.53
2.42
1.70
2.193
2.339
3.69
3 60
3.23
1971
2.285
2.274
2.187
2.341
2.259
2.387
3.211
3.447
3.212
2.21
2.722
2.782
3.69
3.60
3.29
1972
2.479
2.467
2.373
2.540
2.451
2.590
3.402
3.673
3.446
2.260
2.722
2.782
3,69
3.60
3.29
1973
5.036
5.254
4.82
5.944
4.978
5.737
7.10
9.061
8.339
6.00
7.762
8.004
5.29
5.20
5.29
1974*
11.651
11.875
11.545
12.636
11.672
12.414
15.768
14.691
10.80
14.356
14.876
5.29
5.20
5.29
, 1974 price effective Jan. 1.
"^Official selling price for Sumatra, reference
all others are posted prices. Kirkuk priced
prices are representative postings for crude
SOURCE: Oil and Gas Journal


price for Venezuela,
at Mediterranean; U.S.
oil.



                     11-32

-------
     FEA price regulations are directed at each of the four levels of the




domestic petroleum marketing chain.  As a result of current FEA regulations,




there exists a two-tiered wellhead pricing system for domestic crude.




"Old" oil is price controlled at $5.25 per barrel; however, the price of




new, released and stripper well crude is free to rise and fall with market




fluctuations.




     Domestically produced oil which is not price controlled is the amount




of oil produced per well per producing property in excess of the crude pro-




duced in the corresponding month of 1972 (the excess is termed "new" oil),




an amount of oil equal to "new" oil (this equivalent amount is termed




"released" oil), and all oil produced from any lease whose average daily




production for the preceding calendar year didn't exceed 10 barrels per well.




     For an example of new and released oil, assume that in March of 1972 a




property with 12 wells was producing 240 barrels of oil per day, or a daily




average of 20 barrels per well.  If in March of 1974 the same property produced




a daily average of 264 barrels  from the  same 12 wells, or  22 barrels per




well, each well would be producing 2 barrels of new crude, 2 barrels of re-




leased crude and 18 barrels of old crude.  If,  because of some occurrence such




as water flooding on-nearby properties, the daily production per well on the




example property rose to 45 barrels per day in March of 1974,  each well would




be producing 25 barrels of new crude and 20 barrels of released crude per day




and no old crude.
                                     11-33

-------
     By the end of 1974 the composition of total domestic crude was ap-




proximately 60% old and 40% new, released and stripper well crude.   Actual




prices for domestic crude oil under the FEA categories are now $5.25 per




barrel for "old" oil and are over $11.00 per barrel for "new" oil.   The




weighted average of old and new prices is about $7.50.  If price controls




remain in effect, the average will rise as unregulated oil becomes a larger




proportion of total production.




     Current U.S. concern with foreign, particularly Middle Eastern, oil




prices is that the prices are very high.  Until  1973, the reverse was  true.




As the cost of exploration, development, and production rose in the U.S.,




American oil companies developed fields abroad where the production costs




were much lower than in the U.S.




     By the latter half of the 1960's, the Middle Eastern countries had




become more sophisticated in dealings with the large companies.  An organi-




zation called the Organization of Petroleum Exporting Countries (OPEC) was




formed to specifically negotiate better deals for the member countries.  A




double price system was effectively set up when the members of OPEC announced




they were going to guarantee their income by posting a price per barrel




that would be used to figure their royalty no matter what the real price




of crude oil was.  That announcement was the beginning of political pricing.




The posted price became effective in the latter half of the 1960 "s with each




country posting separate prices.  The other price of the double price system,




the real price, has historically been below posted price.  Table 11-16  lists




representative posted and actual prices.
                                 11-34

-------
                             TABLE II-16
          REPRESENTATIVE POSTED PRICES AND ACTUAL COSTS

       'PER BARREL OF FOREIGN EQUITY CRUDES AND  U.S.  CRUDE
                                 Posted  Price     Aclual Cost*
          Algeria                    $16.21          $11.25
          Canada                     6.68           11.08
          Iran                        11.87            9.35
          Iraq                        11.67            9.23
          Kuwait                      11.54            9.12
          Libya                       15.76           10.95
          Nigeria                     14.69           10.26
          Qatar                       12.01            9.70
          Saudi Arabia                 11.65            9.20
          U.A. Emirates               12.63            9.82
          Venezuela                   14.87           10 95
          U.S. Old Oil                 	            5.25
          U.S. New Oil                 ...           10.20
          U.S. Composite**            ...            7^5
          Imported Composite          - - -           10.42
          Total Composite             - - -            8.01
           *Includes transportation  **Domestic only
SOURCE:   Platts Price News, June 26, 1974
                                       11-35

-------
       The movement upwards of the posted price of crude oil forced the




real price of crude oil up in order to pay the royalty and still produce




a profit.  In the world market, oil is traded almost as a commodity, and




the price moves up and down according to demand.  The effect of the rise




in price of foreign crude oil on the price of domestic crude oil has been




considerable.  Early in the 1950's, the United States Government set up




an allowable policy on crude oil imports.  The purpose was partly to protect




the domestic industry from competition from cheap foreign imports (parti-




cularly independents and non-foreign oil-producing companies, as this seg-




ment of the industry was in an over-production situation), partly to pre-




vent long-range dependence on foreign oil, and partly to use as a lever




against the oil industry to prevent price increases.  The whole allowable




system was predicated upon foreign oil being cheaper than domestic oil.




     The situation has now reversed itself.  Foreign oil is now more ex-




pensive  than domestic oil.  However, even though the production costs of




most domestic oil is far below the price of imported oil, production cannot




meet demand.



     The cost of crude includes a wellhead price plus tarrifs, plus cost




of delivery to a refinery.  Tables 11-17 and 11-18 list crude price and trans-




portation costs to U.S. refining areas from several producing areas.  Table




11-17 lists the costs for the average mix of new and old U.S. oil and typical




foreign oil.  The U.S. oil has a strong competitive advantage in both the crude




price and the transportation costs.  This advantage has actually grown in




recent months as foreign prices have increased  faster than the average U.S.




price because of price controls.  Table 11-18 compares U.S. new oil with
                                    11-36

-------
                                    TABLE 11-17
                         DELIVERED  PRICES  OF FOREIGN  AND
                          AVERAGES.   MIX DOMESTIC CRUDE
        F.o.b.  Price
        License Fee
        Sub-total

        Transportation
        Delivered  Price

        Transportation
        Delivered Price

        Transportation
        Delivered  Price
West Texas
Sour 3 2°
*$7.38
$7.38
0.95
$8.33
0.25
$7.63
0.41
$7.79
	 u.s.
Arabian TiaJuana
Light 34° Light 31°
$10.46 $11.10
0.18 0.18
$10.64 $11.28
I'HILADELPHIA
1.40 0.34
$12.04 $11.62
U.S GULF COAST
1.39 0.32
$12.03 $11.60
CHICAGO
1.58 0.51
$12.22 $11.79
WEST COAST (LOS ANGI
S. Louisiana
Light 37°
*$7.63
$7.63
0.85
$8.48
0.25
$7.88
0.32
$7.95
;LbS)
Canadian
Sweet 39°
t$12.15
0.18
$12.33


0.50
$12.83

Nigerian
Light 34°
$11.75
0.18
$11.93
0.72
$12.65
0.83
$12.76
1.02
$12.95

        Transportation
        Delivered  Price
Sour Ventura 28°
    0.20       1.16
   J$7.33     $11.80
                                       0.73
                                      $12.01
•Average of price-controlled and free market prices. tAllows  for currency exchange differ-
entials and includes $5.20 Canadian export tax. {Average f.o.b. price $7.13.
a.
  Average  mix  of 60-40 price controlled and  de-controlled
  domestic crudes.

Note:   Transportation is  computed on AFRA basis,  with  Arabian
        light trans-shipped  via  Curacao.
SOURCE:   Petroleum Intelligence  Weekly, December  9, 1974
                                           11-37

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                                         TABLE 11-18
                          DELIVERED PRICE OF  FOREIGN AND
                           DECONTROLLED DOMESTIC  CRUDES
              F.o.b. Price
              License  Fee
              Sub-total

              Transportation
              Delivered Price

              Transportation
              Delivered Price

              Transportation
              Delivered Price
              Transportation
              Delivered Price
              *For price  control
              and includes $5.20
West Texas
Sour 32'
•$10.89
$10.89
0.95
$11.84
0.25
$11.14
0.41
$11.30
Arabian Tia Juana
Light 34" Light 31°
$10.46 $11.10
0.18 0.18
$10.64 $11.28
0.97 0.31
$11.61 $11.59
U.S. GULF COAST
0.96 0.29
$11.60 $11.57
S. Louisiana
Light 37'
*$11.14
$11.14
0.85
$11.99
0.25
$11.39
CHICAGO
1.15 0.48 0.32
$11.79 $11.76 $11.46
Canadian
Sweet 39°
t$12.15
0.18
J12.33


0.50
$12.83
Nigerian
Light 34'
$11.75
0.18
$11.93
064
$12.57
073
$12.65
0.92
$12.85
  Sour Ventura 28°
       0.20       0.54      0.68
     $10.83     $11.18     $11.96
-exempt,  free market crude. tAllows  for currency
Canadian export tax. JFree market f.o.b. price $10.
exchange
63.
differentials
Note:   Transportation  costs  are  on  a spot basis.
SOURCE:   Petroleum Intelligence Weekly,  December 9,  1974
                                            11-38

-------
minimum foreign oil prices.  One sees in the table that the price of the

new oil has risen to just about the same price as the foreign oil when trans-

portation costs are taken into consideration.

     While this impact analysis will not attempt to specify crude prices

over the period of interest, the subject has been considered by reputable

analysts.  The Project Independence study considered crude prices ranging

fr.om     $4 to $11 per barrel.  Since Arab prices are now established

for political reasons as well as economic, their prices could be reduced

conceivably to the $4 level again,though it is unlikely.  However, if crude

prices  were allowed to seek a level reflecting world supply and demand,

the Blueprint Report estimated that the long-term price would be about

$7 per barrel in 1973 dollars (almost $8 per barrel in 1974 dollars).

Former Secretary of the Treasury Schultz testified in February 1974:

     It is reasonable to assume that after about 3 to 5 years,
     and allowing for some inflation, if the price of oil
     increases by about 50% from mid-1973 levels, to around
     $7 per barrel, sufficient domestic oil supplies should
     flow to satisfy about 85-90% of our demands.

     Accordingly, we have for planning purposes  estimated that
     the "long-term supply price" is about $7 per barrel.
     But the $7 per barrel figure is an estimate and the
     ultimate figure may be somewhat more or somewhat less.

     While the $7 per barrel may be approximately the supply/demand equilibrium

price, the prices at the two ends of the spectrum are probably more relevant

as prices which may actually be seen.  As was noted above, about 60% of

current production is frozen at $5.25 per barrel.  The President has

proposed to remove these price controls, subject to

Congressional approval as provided by the Emergency Petroleum Allocation
 "Windfall" or Excess Profits Tax, Committee on Ways and Means,
 U.S. House of Representatives, pp. 135, 1974.


                                    11-39

-------
Act.  On the other hand,there is a strong move in Congress to reimpose price




controls more generally on the economy rather than relaxing them.




     If old crude prices are decontrolled, the resultant change in per barrel




revenues to the oil companies may not be equal to the increase in crude




prices.  The combination 'of excise taxes on imports and the excess profits tax




as proposed by the President could result in  ah  a'dded net  income of  only $0.89




per barrel in pre-tax (corporate tax) revenues to the companies , based  on




an  analysis of  the  total  tax and deregulation package which was  reported In  Plat't




News of Jan.  20•,  1975.  This analysis  showed  that the weighted average U.S.




domestic price  less  severance  tax  Was $6.97  based on prlce-less-tax levels  of




$10.23 for new  oil  and  $4.88 for old  oil  (39% to 61% ratio),  tf  deregulated;  U.S.




crude prices will rise  to $14 per barrel,slightly less than the  landed  price  of




foreign crude (including the proposed $3 excise  tax).   The taxes oh  the




domestic crude would include:  $2 excise tax; 7% severance tax oh the




$12; arid $3;30 windfall profits tax.  The net feveilde to the  firm would  then




be  $7.86 per barrel, an increase of $0.89 over present reverfies.   There is




of  course no way  to know at this point whether all, part;  or  nOrie of the package




will be eriacted.




    The following analysis of potential oil production losses as A result




of  the proposed effluent guidelines has used  $5.25  arid $ll.OO etude prices




to  test the range of potential impacts.  They are intended to be represen-




tative of the pricfe fatige p'rodticers could hav£ experienced at th£ end of 1974.
                                   II-40

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3.2.  Pricing of Offshore Natural Gas at the Wellhead




     Introduction




     The price of natural gas is set at the time of production according




to its entry into either the intra- or interstate markets.  Intrastate




prices are not regulated and respond freely to the fluctuation of supply




and demand.  Interstate prices are controlled by the Federal Power Com-




mission which has jurisdiction over gas produced in federal offshore




areas, gas produced and sold across state lines and gas moving through




any segment of an interstate pipeline system.




     Prior to 1973, the new, long-term contract prices received by




natural gas producers for intra- and interstate sales were not signifi-




cantly different.  However, in late 1973, prices for intrastate gas began




to rise to levels occasionally tripling the fixed prices of interstate




gas, and in 1974 intrastate prices were in the range of $1.95 per thousand




cubic feet (MCF), roughly four times greater than the interstate price




of $0.51 per MCF (see Table 11-19).  A consequence of the price disparity




has been the extreme shift to intrastate markets of the commitments of




natural gas reserve additions as early as 1969.




     If it is assumed that all of the new reserves reported by AGA not




committed to the interstate pipelines are being committed to the intra-




state gas market, it appears that the intrastate market may well have





captured 99% of the 1970 net U.S. reserve additions, 30% of the 1971 net




reserve additions,  100% of the 1972 net additions, and 82% of the 1973




net reserve additions (see Table 11-20).
                                   11-41

-------
                       TABLE  11-19
               Prices Received by Producers f m
            Natural Gas Sales. 1966-1975
           (v-cnts per thousand cubic feet)


                                             s.«.
                             New             (,u!f
             Average      Long-Term         Cu.ii
             Wellhead     Interstate       lntr..-ute
              Prices       Contracts       C6"           16.0           18.S           15M:>.6
!<>i'f,           16.4           19.6           16.1 20 2
t'*<•••           16.7           19.9           14.-I-:i 5
I97,'i           17.1           22.3           18i-25!l
'\-)T,           18.2           24.8           20.t-2«2
               18.6           35.1           23.i-1ii.ll
               21.6           40.3             25 125
ITj           26.7          43-51           125-195
li'S           35.0                          17; no

S>i>iii.k:>  i O-KT Associates: I'.S. IHircau of Mines. .\,i:>,ral
         (.a* Annual. l')73. l-cdcral Power Comtni^i'in;
         IjiiM-n As<.vciate<: and Arthur D. Little, In...
                             11-42

-------
                               TABLE 11-20
                               LOWER 48 STATE
                           NET RESERVE ADDITIONS
                         INTERSTATE VS. INTRASTATE
Year
  Total Net AGA
Reserve Acidjlions
       Tcf
  Net Interstate
Reserve Additions
    (Form  15)
Tcf       Percent
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
20.1
21.2
19.2
21.1
12.0
8.3
11.1
9.4
9.4
6.5
10.7
13.3
14.1
14.8
9.5
6.0
0.1
1.9
(0.2)
1.2
53
63
73
70
79
72
1
20
0
18
Inferred Intrastate
Reserve Additions
Tcf       Percent
9.4
7.9
5.1
6.3
2.5
2.3
11.0
7.5
9.6
5.3
47
37
27
30
21
28
99
80
100
82
  Derived by assuming that  intrastate reserve additions are equal to the
  difference  between total AGA  reserve additions  and the  reserve  additions
  committed  to the interstate market.
SOURCE:   "The Oil and Gas Compact Bulletin",  December  1974
                                   11-43

-------
     Prior to 1970, there were sufficient domestic supplies of gas; how-




ever, beginning in 1970, onshore gas procurement became difficult for the




interstate market.  In 1970, the interstate pipelines procured 75% of




their long-term new gas from onshore sources; in 1971, the percentage




dropped to 54%; in 1972, it dropped to 41%; and in 1973, it dropped to




33%  (Table 11-21 ) .




     The increased dependence of interstate pipelines on offshore pur-




chases, or the inability of the interstate pipelines to buy gas onshore,




appears to be attributable to the FPC rate structure which makes it dif-




ficult for the interstate pipelines to compete for new supplies.




     Because offshore areas are the most expensive to develop, offshore




gas  exploratory footage has declined since 1970 (see Table 11-22 ).  Since




1970 the percentage of footage of offshore development drilling relative




to total U.S. gas development footage has also declined  (see Table 11-23).




     While all natural gas produced in Federal waters is by definition




interstate gas, the gas produced in state waters can be either inter- or




intrastate depending on its transmission pipeline and the location of its




purchaser.  Gas from Federal waters is 85% of the total natural gas pro-




duced in the Gulf of Mexico.  Fourteen percent of the Gulf production is




from Louisiana state waters and the majority of this production also is




from older wells under interstate contracts.  The Texas state waters pro-




duction is primarily dedicated to plants in Texas and is intrastate gas,




but  it is only 0.3% of total offshore natural gas production.




     Because natural gas from the Gulf of Mexico is primarily interstate




gas, the economic impact analysis has focused on interstate gas prices




as controlled by  the FPC.



                                   11-44

-------
                               TABLE 11-21
                     ESTIMATED NEW LONG-TERM CON TRACT
                      SALES HY LARGE PRODUCERS  1970-1973
                    OFFSHORE FEDERAL DOMAIN vs. ALL AREAS
                                  (Million McO*

              All Area*           Sales      Offshore         Sales        Onshore
  Year           Sales	       Offshore?    Percent 2      Onshrce       Percent

  1970           302.6            73.3        24.2         229.3           75.8
  1971           453.7           207.7        45.8         246.0           54.2
  1972           47-1.3           279.4        58.9         194.9           41.1
  1973           330.3           221.1        66.9         109.2           33.1
  * Figures  derived  from applications  filed  with  the Commission for new long-term
    sales certificates.
    FPC pricing areas and California (Federal domain)
    Federal  domain r.rens offshore Louisiana,  Texas and California.
SOURCE:   "The Oil  and Gas Compact Bulletin",  December  1974
                                       11-45

-------
                                       TABLE 11-22
      1970
      1971
      1972
      1973
      1974 (1st half)
    Total U. S. Gas
  Exploratory Footage
     (million feet)

          3.7
          3.3
          4.6
          6.2
          3.8
     Offshore Gas
  Exploratory Footage
     (million feet)

          .26
          .41
          .14
          ,17
          .08
    Offshore
  as Percentage
     of total

       7.0
      12.4
       3.0
       2.7
       2.1
      * All figures taken from the latest publication of "Gas Supply Indicators''  by the FPC
        Office of Economics,  issued October 25, 1974.
      Gas development footage shows the same pattern.  In 1971, offshore development footage was
8.8 percent of the national total. This dropped to 7.8 percent in 1973, and declined to 6.1 percent
for the first six months of 1974.
                                      TABLE 11-23
    1970
    1971
    1972
    1973
    1974 (1st half)
  Total  U. S. Gas
Development  Footage
   (million feet)	

        19.2
        19.3
        22.2
        29.4
        16.a
   Offshore Gas
Development Footage
   (million feet)

        1.6
        1.7
        1.5
        2.3
        0.97
  Offshore
as Percentage
   of total

     8.3
     8.8
     6.8
     7.8
     6.1
    * All  figures taken from  the       publication of "Gas Supply  Indicators" by the FPC
      Office of Economics,  issued October  25,  1974.
SOURCE:    "The Oil  and Gas  Compact Bulletin," December  1974.
                                        11-46

-------
     Regulation of Natural Gas Producers

     In 1954 the U.S. Supreme Court held in Phillips Petroleum Co. versus

Wisconsin that the Federal Power Commission was responsible not only for the

regulation of the interstate pipeline companies but also for the regulation

of sales to those pipeline companies by natural gas producers in the field.

There had been up to this point a major controversy concerning the language

and intent of the Natural Gas Act of 1938 with respect to sales by producers.

When this Supreme Court decision was followed by an unsuccessful attempt to

exempt producers from regulation through Congressional legislation,

the  Federal Power Commission began to grapple with the problem of how to

actually carry out its charge.

     The first efforts involved attempts to determine for each producer his

costs of production, capital, etc. in order to apply the rather traditional

formula of rate of return regulation.  In this framework, the producer would

be allowed to charge a price for his gas which would cover his costs of pro-

duction (including depreciation) and grant a return on his capital which would

be sufficient for him to cover his "cost of capital."
 This summary is based on the history of FPC natural gas producer regulations
 as detailed in Breyer and MacAvoy, Energy Regulation by the Federal Power
 Commission, The Brookings Institution, Washington, B.C., 1974.
                                  11-47

-------
     There were several very difficult problems in implementing this regu-




latory scheme.  For one, gas and oil are found together about 25% of the time,




but oil is not regulated.  Thus, there are joint costs of exploration and pro-




duction which can by no existent economic theory be unambiguously assigned to




gas as opposed to oil.  The same problem exists with allocating capital to gas




and oil.  Besides this, to determine an appropriate cost of capital, one might




look at the rates of return in comparable companies in comparable industries.




Unfortunately for the FPC, such comparable companies were not to be found.  The




final problem, however, was simply the enormity of the process.  From 1954 to




1960 the FPC completed only ten out of nearly 3,000 cases before them.  In 1960,




therefore, a new approach was decided upon — the area rate concept.  The FPC




divided the Southwest into five regions and determined to set prices on a 2 tier




system — one price for gas on old contracts and a higher price for gas on new




contracts.  The intent was to minimize windfall profits on already committed




gas while not unduly restricting future investment in gas exploration and




development.  Because the decisions in the area rate proceedings were still




years away, the FPC decided to control prices during the interim through a two-




sided policy:   (1) the producers would be compelled to refund  to the pipeline




companies  (and ultimately the consumers) any revenues made in  excess of  those




which would have been made at the price yet to be determined by the Commission;




and  (2)  new  contracts had to be approved by the FPC.  The effectiveness  of




these deterrents to price increases is exemplified by the essentially constant




price of gas  through  the 1960's while the area rate proceedings were going on.
                                   11-48

-------
The first area rate proceeding to be completed was the one for the Permian


Basin of West Texas and Southeast New Mexico.  Prices were set at 16.5C/MCF,


only slightly higher than the 1960 rate.  The initial decision of the Commission


in Southeast Louisiana was also issued in late 1968, but revisions, court cases,


and so forth dragged the "final" decision out to 1971.   This decision was note-


worthy in thab the procedures of the FPC were again dropped and in their place


the FPC substituted its acceptance of a "settlement" between the producers,


distributors, and other customers at about 26^/MCF  (new gas).

                        2
     MacAvoy and Breyer , as well as many other economists/critics of the FPC,


have detailed the flaws in the FPC price setting schemes.  For one thing, there


was an inherent bias in the cost estimates determined during the proceedings


because of the interim price ceilings.  Producers would not attempt to produce


gas which would cost more than they could charge for  it.  The more risky ven-


tures were not attempted.  Thus, the interim prices  (at 1960 level) determined


producers' costs which determined final ceiling prices at little more than  the


1960 level.  The additional unexpected result was that the relative price of gas


to final consumers stayed so low during the.  '60's that a great deal of demand


was generated which would have gone to oil or coal  had gas prices been allowed


to rise.  At the same time, the low price discouraged investment in exploration


and development so that well drilling and subsequent  discoveries fell well  below


production until^in the early 1970'syproduction could not keep up with demand.
 46 FPC 86  Opinion 598.
2
 MacAvoy,  P. and S. Breyer, ibid.
                                  11-49

-------
The clamor over curtailments and other elements of the energy crisis brought


pressure on the FPC to reviev? again its ceiling price decisions.


     The FPC this time went one step  further in simplifying its procedures:


it adopted in June 1974 a uniform national rate for wellhead prices on new


gas  (produced after January 1, 1973).   The new prices set were 42^/MCF  (plus


taxes, royalties, etc. as applicable).  In addition, in a notice of proposed

           2
rulemaking , the FPC proposed that "small producers" would be allowed to


charge a price 50% higher than the larger producers, in order to  allow  them


to stay competitive with the larger producers.
     Then  in December  1974,  the uniform national rate was  increased  to  50C/

                                                                     3
MCF retroactive  to June  21,  1974,  subject  to  1C/MCF annual increases .   This


increase   was,  primarily  the  result of  the  FPC's decision to use  the  discounted


cash flow  (DCF)  methodology  for calculating producers'  return  on investment,


a method they  had previously declined  to use.


     Before discussing the cost determinations which resulted  in the 42c/MCF


and then the 50C/MCF price ceiling,  one comment is  in order.   If it  appears


that there is  a  certain  amount of  arbitrariness and instability  in these


decisions, it  is because there is.  The FPC has been charged by  the  courts to


set "just  and  reasonable rates", but it has also been allowed  to use whatever
1 FPC  Opinion 699,  21 June 1974.

o
  FPC  Notice of Proposed Rulemaking,  9 September 1974.


3 FPC  Opinion 699H,  4 December 1974.
                                  11-50

-------
methods it deems reasonable to do so.  No unambiguous "formula" has




been determined for this purpose.  The methods chosen, then, attempt




to determine actual costs within a "zone of reasonableness"  and to




base ceiling prices on this estimated range.  But because both the




costs to the producers and the methodology for combining these costs




have repeatedly changed, the rate structure has undergone several




major changes in the last ten years.






     Nationwide Costs of Finding and Producing Non-Associated Gas




     In Table 11-24 are displayed eight different estimates used by




the FPC in June 1974 for the costs of various factors involved in the




production of natural gas.  The only difference between the pairs




(c) and (d) and (e) and (f) is the assumed investment life  (9 and 10.5




years respectively).  Columns (g) and (h) are based on different




estimates of the expected productivity (in MCF/ft drilled) of future




drilling.  As will be seen below, this is by far the most important




variable in these cost determinations.
 FPC Opinion 699.
                                  11-51

-------
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-------
     Successful Wells Cost

     The successful wells cost was determined by taking the average cost of

drilling (in this case, the 1972 Joint Association Survey ; and dividing it

by the expected productivity of successful wells in MCF/ft drilled.  A great

deal of controversy was involved in determining the productivity, as it is

the single most important factor in determining total costs. Figure  II-2  presents

a history of the productivity from 1947 to 1972.  As can be seen, there is a

tremendous variance in this curve, though since the mid-60's the trend has

been steadily downward.  In the face of a great deal of conflicting evidence

presented by industry analysts, public utility associations, etc., the FPC

decided that a "zone of reasonableness" was between 485 and 559 MCF/ft drilled

for the productivity.  From this and the JAS figures, a successful wells  cost

between 4.93 and 5.68C/MCF was decided upon.(See columns  (e) and (f) of  Table

 11-24.)  Pew differing opinions were expressed to the FPC

concerning  other costs involved in setting up production  in successful wells

 (items 2, 3, and 4).  Line 5 is a total of these costs  (1-4).


     Dry Holes


     An allowance was made for exploration and drilling costs associated with un-

successful wells or "dry holes". Factors which account for differences in the costs

of successful and unsuccessful wells, their relative numbers, etc.  were included in

the determination of lines 6,  7, 8, and their total (line 9) in Table 11-24.
 Joint Association Survey of the U.S. Oil and Gas Producing  Industry; API,
 IPAA, MCOGA; 1972.
                                  H-53

-------
                        FIGURE II-2
      WON-ASSOCIATED GAS RESERVES  ADDITIONS PER FOOT  DRILLED
             IN WELLS PRODUCTIVE  OF GAS AND CONDENSATE
           UNITED STATES EXCLUDING ALASKA, 1947 -  1972
Mcf/f
  800
  700
  600
   500
   400
   300
   200
          47 48  50   52   54   56   58  60   62   64
70  72
    SOURCE:  Federal Power Commission, Opinion 699
                                 11-54

-------
     Operating Expense





     Operating expense, an item not argued about by the respondents, was




determined to be 3.1C/MCF.







     Return on Investment





     Historically, several points of controversy have surrounded this item.




First, what is the base on which it is determined?  Producers have argued that




their investment in exploration which results in dry holes should be counted




equally with their successful well costs in the determination of their rate




base.  The FPC in June 1974 disagreed, citing the "value to the public of the




services they perform is measured by the quantity and character of the




natural gas they produce, and not by the resources they have expended in its




search ..."   In December 1974, however, the FPC decided to include a dry




hole cost in their new discounted cash flow (DCF) approach.




     The rate of return was set by the FPC as 15%, the upper end of the




"zone of reasonableness" of 12% to 15% they determined to be applicable for




natural gas producers.  The investment life was set to be 9 years based on an




18 year depletion time.  In addition, a lag period of 1.5 years was added to




account for the time between lease acquisition and the commencement of actual




production.




     The total return in the June 1974 decision was then calculated by multi-




plying the production costs (line 5, Table 11-24) by the rate of return  (15/0
  FPC versus Hope Natural Gas Co., 320 US 591, 649.
                                  11-55

-------
and the investment life (10.5 years) to get a range of 14.9 and 17.15C/MCF




(line lla).




     In addition to the factors discussed above, the unargued items in lines




12, 13, 14, and 16   were added to come up with a total (line 17) which ranged




between 37.05C and 42.74C/MCF.  The FPC, in order to encourage exploration




and development investment, decided to set the price ceiling at the upper




edge of this range with a small (lc/year) escalation to account for future




cost increases.




     The one remaining point of contention concerned whether Federal income




taxes were an acceptable cost item.  The FPC took the stance that a blanket




nationwide figure would not be adequate for this item because "the complex




nature of the Federal tax laws negate any simple calculation of a Federal tax




liability and require consideration of the producer's tax returns in order to




consider the timing relationships between investment expenditure, the ex-




pensing  of intangible drilling costs, and jurisdictional sales."    The FPC




decided, therefore, not to include this item at all in its cost computations.




     In December 1974 the FPC revised its earlier methodology by using a dis-




counted cash flow approach.  This approach led to a range of between 48c and




52C/MCF for the "economic cost" of natural gas, including a 15% DCF rate of




return to the producer.  Thus, the value of 50C/MCF was decided upon with




IC/MCF increments to be added yearly.
  FPC Opinion 699
                                   11-56

-------
     Some Conclusions


     The FPC is under considerable continuing pressure from economists,


industry spokesmen, and Congressional critics to revamp its price setting


policies to effect further deregulation of natural gas producers in order


to cope with the growing demand and slackening production of natural gas.


It well recognizes the decline in the late 60's and early 70's of explora-


tion and development activities brought about by an abnormally low relative


price for gas and is attempting to rectify the situation while yet carrying


out its Congressional and judicially affirmed mandate to keep price at a


"just and reasonable rate."  The trend in FPC regulation has definitely been


in the direction, however, of a  phased deregulation  over a number of years.


     In the cost determinations the FPC has made in the past, there has been a

concerted effort to account fairly for the costs that are actually incurred in


producing natural gas.  On the basis of previous FPC opinions in this regard,


it appears that additional costs due to equipment required by law would be


included by the FPC in line 4 (other production facilities), and would,


therefore, be passed on to the pipeline company (and to the ultimate consumer)


in the form of higher prices.  This opinion is supported by a conversation


with Lundy Wright, Chief of Producer and Pipeline Rights Division of the FPC  ,


who made it clear, however, that it was the Commissioners and not himself who


made such decisions.  Assistant General Counsel Robert W. Purdue of the FPC

            2
agreed also  , pointing out that under FPC Order No. 481 (18 CFR 2.76),
 1
  Personal conversation, 8 November 1974.

 2
  Personal conversation, 15 November 1974.
                                  11-57

-------
producers tnay file for relief from special costs such as this.  He gave




as a current example the case of the Sun Oil Company in the Hugoton field




in Oklahoma which has been granted price increases to account for the




added costs of reinjection wells drilled in compliance with Oklahoma




standards on salt water disposal.  He suggested that in many cases the




state regulations may be more stringent than what the EPA will propose.




Thus, he expressed confidence that the FPC would grant special allowances




on legitimate additional required equipment costs.




     The one question which remains is whether the FPC would continue




to grant relief to individual producers according to Order No. 481 or




whether they would adjust the nationwide ceiling prices to account for




these added costs.  In addition to these special allowances, the FPC has




recognized that the costs of small producers are often both higher and




more difficult to bear than those of the larger producers.  As stated




earlier, the FPC's intention is to allow small producers to charge a




50% higher rate for new contract gas.  It is true, therefore, that the




small producers are more protected against increasing costs due to new




required equipment than if they were limited by the 50£ ceiling.  Whether




this will be sufficient without special relief via Order 481 will depend




on the individual case, though from a superficial view, it appears that




they would certainly be protected by both these factors.
                                  11-58

-------
     Figures  II-3A, B, & C  show the histories of new contract production, new

field wildcat drillings, and new contract price for offshore Louisiana gas.

One can clearly see that the price of gas remained essentially at or below

the 1960 level throughout the entire decade of the 60's.  During that time,

new field wildcats (and the resulting discoveries) peaked out and then fell

to two-thirds of their highest (1966) point.  New contract production rose

steadily until it peaked in 1968 and fell sharply in 1970 as reserves con-

tinued to decline and producers were forced to curtail previously contracted

sales to interstate pipeline companies.  As new contract price rose sharply

during the first years of the 70's, new contract production and new field

wildcats rose dramatically as well.    These graphs indicate that the price

level is an important factor in investment in exploration and production of

natural gas in the 1970's.
  Unfortunately, these production increases on new contracts have not been
  sufficient to keep curtailments of production on older contracts from
  occurring.  According to FPC News Release No. 20849, these curtailments
  amounted to over 218 billion cubic feet from September 73 to September 74
  and are expected to rise to 266 billion cubic feet between September 74
  and September 75.

-------
   230
   260
   240
   220
   200
   180
   160
   140
   120
   100
    80
    60
    40
    20
  TOLLS
   New  Contract
     Production
                                          FIGURE 11-3 A
   360
   330
   300
   270
   240
   210
   180
   150
   120
   90
   60
   30
1/MCF
   40
   38
   36
   34
   32
   30
   28
   26
   24
   22
   20
   18
 New Field Wildcats Drilled
                                             FIGURE II-3B
New Contract Gas Price
  1960  61    62    63    64     65   66
SOURCE:  Foster Associates, Washington,
                 67
                                                         68    69     70     71     72     73
                                                        MIT  Energy Lab, Cambridge, Mass.
                                                           74

-------
II.4.  FINANCIAL CHARACTERISTICS









4.1.  The Role of Financial Characteristics in the Economic Impact Analysis




     The oil and gas production industry has many unusual financial




characteristics reflective of the risks of the business, its special tax




status, and its special cash flow patterns.  In examining the financial




characteristics as part of this economic impact analysis, three issues




are important:







     •  Are firms in the industry constrained in their access to the




        required capital for pollution control so they may be forced




        to close by the proposed effluent guidelines?





     •  What are the profitability levels and patterns in the industry




        and will they be changed by the pollution control requirements?





     •  What is the cost of capital for the industry?






     These issues are addressed in the following section.  In the earlier




characterization of firms in the industry, the predominance of the major




oil companies in offshore operations was noted.  The examination of the




financial characteristics of offshore operations thus primarily concerns




the impact of the capital costs of pollution control on capital budgets




of the major oil companies and the proper definition of the cost of




capital for these investments.
                                  11-61

-------
_4_.2.   Income  Statements and Profitability




     The profitability of the oil and gas industry is a subject of heated




debate between  the  industry and its critics and within the Congress.




High profitability  is argued by the industry to be necessary to




compensate for  low  profitability in earlier  ears and to generate funds




for finding and developing new reserves and building new processing facilities.




Price  controls, proposed "windfall profits" taxes, and tb" recent end of




depletion allowances are expressions of widespread belief ihat the industry's




profits are or  will be excessive.




     The Chase Manhattan Bank publishes a compilation of the financial reports




of 30 major oil and gas companies, including four foreign companies called the




Chase Group.  These firms account for 71% of total U.S. crude oil production




and 83% of Gulf OCS production.  Table 11-25 displays the total income state-




ments for the Chase Group from their worldwide operations for 1971, 1972, and




1973.  The Group's  net income on revenues was 8.7%-in 1973, 6.5% in 1972, and




7.4% in 1971.   The  portion of net earnings attributed to operations in the U.S.




were 35.4% in 1973, 53.4% in 1972, and 48% in 1971.






     The  interpretation  of oil  industry profitability  has been particularly




controversial because  of  several  important  tax  privileges.   Provisions  such




as the percentage depletion allowance, foreign  tax credits,  and  the expensing




of intangible drilling costs  are  argued to  have led  in the past  to an under-




stating  of  true industry profitability. The magnitude  of  these allowances are




discussed  later.   But  in understanding the  industry  and  the  impact of added




costs  of  operations such as pollution  control  costs,  one  must appreciate the




industry's very unusual  situation,  particularly regarding U.S. operations.  At




present,  the per  barrel  revenues  which a  company receives for oil  is largely
                                    11-62

-------
                                      TABLE  11-21.
            INCOME STATEMENT OF CHASE GROUP FOR 1971, 1972, AND 1973

                                               1973          1972          1971
                                              ($ million)    ($ million)   ($ million)

Gross Operating Revenue                        130,948       104,159       95,104
Non-Operating Revenue                   •         2,961         2,119         2,756
  Total Revenue                                133,909       106,278       97,860
Operating Costs & Expenses                      90,298        74,413       68,805
Taxes - Other than Income Taxes                  6,241         5,138         4,413
Write-Offs (incl. depreciation & depletion)      8,345         7,514         7,079
Interest Expenses                                2,008         1,774         1,597
Other Charges                           ''      	3_7_      	22_      	23_
  Total Deductions                             106,929        88,861       81,917
Net Income before Income Taxes                  26,980        17,417       15,943
Estimated Income Taxes                          14,889        10,301         8,409
Income Applicable to Minority Interests       	413      	256      	265
  Net Income (a)                                11,678  (b)     6,860         7,269
(a)  Includes earnings from operations outside U.S.: 1973-$7,544 million;
     1972-$3,20'4 million; 1971-$3,779 million.
(b)  Excludes $84 million of extraordinary gains primarily from the sale
     of assets. -  -*
SOURCE:  "Financial Analysis'of a Group of Petroleum Companies, 1972 and  1973,"
         The Chase Manhattan Bank
                                       11-63

-------
unrelated to either the cost of producing the oil or the demand for oil.




"Old" U.S. oil is price controlled at $5.25 per barrel and "new", uncon-




trolled oil is floating above the OPEC established world price because




of U.S. tariffs on imported oil.  If old oil were decontrolled, as has




been proposed, its price would rise to the world level or above as well.




While there is a wide variation in the cost of producing oil, in fact




most current U.S. production has been operating at cost levels low enough




to make $5.25 prices profitable.  Further price rises will make produc-




tion economical in higher cost wells, but it will also mean substantial




increases in profits for most wells now producing at $5.25 prices, about




60% of U.S. production.  The level of profitability actually experienced




by the industry will be determined to a significant degree by Federal tax




policies.  The issue with which the Congress, FEA, the Treasury Department




and the industry have been contending is what profit level is needed to




provide a fair return on the industry's investment and thereby provide a




necessary incentive for expanding domestic production.  After that pro-




fitability level is determined, if it can be, profits will probably be




fixed by controlling prices and/or the additional profits will be taxed




away.  The central point is that profitability for the industry, parti-




cularly the larger companies, will be determined more by Federal tax and




pricing policies than the economics of production.  Until the specific




policies and regulations are established,  there will be a considerable




uncertainty (perceived risk) on the part of the companies and investors




as to the industry's future.
                                 11-64

-------
     The curreritly existing tax laws have encouraged the oil companies  to




spend funds generated by current operations on exploration and development of




new wells.  Most of these expenditures can be charged against revenues  rather




than capitalized.  The level of spending is such that U.S. tax liabilities




will be very small or zero.  In addition, the after tax profit on net worth




has been kept generally in line with other  industries,  so the industry




will continue to have access to equity markets.  Figure  II-4  shows  the  return




on net worth of the petroleum  industry and other manufacturing industries over




the last 13 years.




     Table  11-26  lists a  compilation of  net income after  tax and  the  rate of




return on equity for 22 U.S. oil companies for the years 1963 through 1973.




Table  11-27  lists  the  rates of return by various measures  for the Chase Group  for




1971, 1972, and 1973.




     A survey was conducted of the net incomes and cash flow of the signifi-




cant offshore producers.  Table 11-28 displays these values  for 1973.




     The concept of oil industry profitability being set by  government  tax




policy is reflected in the windfall profits tax proposals by  former President




Nixon and President Ford. In testimony by former Secretary of the Treasury,




George Shultz, on February 4,  1974, before the House Ways and Means Committee,




the rationale advanced for a windfall profits  tax was  that the $9.50 per barrel




price of U.S. new oil  (at that time) was substantially in excess of the  price




necessary to satisfactorily increase U.S. oil production.
                                   11-65

-------
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                                       TABLE 11-27
                  RATES OF RETURN FOR  CHASE GROUP; 1971, 1972, 1973

                                                  1973          1972         1971
                                                 ($ million)    ($ million)   ($ millioi

1) Average Borrowed &  Invested Capital (a)       101,010       94,912        89,912
   Earnings  (b)                                   14,099        8,889         9,086
     Return                                        14.0%         9.4%         10.1%
2) Average Invested Capital  (c)                   75,546       71,730        67,849
   Earnings  (d)                                   11,678        6,860         7,269
     Return                                        15.8%         9.7%         10.7%
3) Average Total Assets                          141,297       128,552        119,962
   Earnings  (e)                                   12,091        7,116         7,534
     Return                                         8.6%         5.5%           6.3%
4) Average Gross Fixed Assets                    139,649       132,545        126,109
   Gross Operating Profit  (f)                     34,409       24,608        21,885
     Return                                        24.6%        18.6%         17.4%
   (a)  Includes long-term debt, preferred  stock, common  stock,  surplus  and  equity  of
       minority interests.
   (b)  Represents net income plus  interest charges and income applicable  to minority
       interests.
   (c)  Includes preferred stock, common  stock and surplus.
   (d)  Represents net income.
   (e)  Represents net income plus  income applicable  to minority interests.
   (f)  Represents gross operating  revenue  less operating costs  and expenses and
       taxes - other than income taxes.
   SOURCE;  "Financial Analysis of a Group of Petroleum Companies,  1972,  1973,"
            Chase Manhattan Bank
                                           11-68

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11-69

-------
      Secretary  Shultz's  reasoning was  that $7 per barrel of oil provides

 sufficient  profits  to  oil  companies both to return an adequate profit on

 current  investments and  to encourage and allow investments in new pro-

 duction  sufficient  to  substantially reduce U.S. dependence on imported

 oil.

      An  analysis  of President Ford's proposed windfall tax on crude

 prices by Plants  Oilgram (January 20,  1975) concluded that the tax com-

 bined with  deregulation  of old oil prices would increase the average

 price of domestic oil  from $6.97 to $7.86 per barrel.  The rationale

 behind this price level  was that "original government calculations

 reportedly  showed a real oil price of  between $7-8/bbl which provides

 all the  incentives  needed  at this time for production and development

 activities,  including  enhanced recovery projects."

      The conclusion one  should draw from this is that the U.S. Government

 is attempting to  decide  what is the "correct" level of profits for the

 oil industry and  attempting to write its tax laws so as to bring about

 this  level  of profits.   The objective  seems to be to keep profits high,

 perhaps  higher  than in 1973 but not let them get "too high."

      For  the major  companies and for the industry as a whole, profita-

 bility should continue to  be strong for the next few years.  It is possible

 that market  conditions or  government actions could change the picture,

 but changes  in  these areas will probably not affect profitability in the

 short run sufficiently for pollution control costs to be of significance

 to overall production.   The greatest potential danger from changes in the

current tax  structure and the pollution control requirements is that

investments  in future production will be curtailed.
 "Windfall" or Excess Profits Tax, U.S. House Committee on Ways and Means,
 1974, p.  135.

                                 11-70

-------
4.3.   Capital Requirements





     The oil and gas industry  will  have  to make  investments  in new  exploration,




development, and production well in excess of historic yearly levels in order




to accelerate domestic production.  These higher levels of capital expenditures




raise the question of whether  the industry will have access to the financing




necessary to achieve the goals of increased domestic production.   This issue




was examined by the FEA and Arthur D. Little, Inc., in the Project Indepen-




dence Report.  As part of an analysis of the economic impact on the industry




of the proposed effluent limitation guidelines, one must consider whether the




added capital required for pollution control is of sufficient magnitude to




approach     capital availability limitations for the industry as a whole or




for individual firms.




     The FEA's analysis of the financial availability issue for the energy




industries covered two main points, among others. Since World War II, 20 to




25 percent of total yearly business fixed investments have gone to the energy




sectors.  If the same percentage continued over the 11 year period 1975 to 1985,




between $379 and $474 billion  (in 1973 dollars) would be available for invest-




ment in the energy industries.  FEA's estimate of the total investment required




under an "Accelerated Supply"  scenario was $454 billion , including investments




in projects to come on line after 1985.  The breakdown of investments by




industry is shown in Table  11-29- This estimate did not include  outlays in the




petroleum industry which are expensed for tax purposes such as intangible




drilling and exploratory overhead costs nor did it  include  lease bonuses.




 They would amount  to  about $107.4 billion,  according to  FEA.   For an energy
                                  11-71

-------
                                 TABLE 11-29
       Comparison of Capital Requirements Estimates :   Total  Dollars
                           Cumulative 1975 - 1985
                         (Billions of 1973 Dollars)
                                                   FEA
                                               Accelerated
                                             Supply(Without
                      NPC     NAE    ADL    Work in Progress)
                              M    M          (d)
Oil and Gas
(including refining)
Coal
Synthetic Fuels
Nuclear
Electric Power Plants
(excluding nuclear)
Electric Transmission
Transportation
Other (f)
     Total
133

  8
 10
  7
137

 42
 43

380
149

 18
 19
 93
 53

125
 -

457
122

  6
  6
 84
 43

 90
 43
  8
396
 80.3

 10.6
   .6
105.3
 50.5

 92.1
 25.5(e)
  2.2
367
    FEA
Accelerated
  Supply

    98.4

    11.9
      .6
   138.5
    60.3

   116.2
    25.5(e)
     2.2
   454
TaT)U.S. Energy Outlook, a summary report of the National Petroleum Council,
Washington, D.C., December 1972 (Average of four supply cases)
(b)  U.S. Energy Prospects, An Engineering Viewpoint, National Academy of
Engineering, Washington, D.C., 1974
(c)  Arthur D. Little estimates based upon an energy conservation scenario
(d)  Assumes that imported oil price is $ll/8_.  This column is considered
roughly comparable to the NPC, NAE, and ADL estimates with the exception of
oil and gas capital.  The FEA estimates for oil, gas and refining do not
include lease bonus payments, and outlays that are expensed for tax purposes
(dry hole, intangible  drilling and exploratory overhead costs); in order
to make the FEA oil and gas figures comparable to the other estimates,
$107.4 billion should be added to the FEA oil and gas estimates.  Work in
progress consists of investment spending made prior to 1985 for new plant
and equipment which will not come on line until after 1985
(e)  Does not include investments required for tanker fleets, but does include
$5.5 billion targeted for Trans-Alaska oil pipeline
(f)  Solar, Geothermal, Municipal Waste Treatment Plants, and Shale Oil
SOURCE:   Project Independence  Report, p. 282, FEA,  November 1974
                                  II-72

-------
analysis are presented as a range of possible values rather than as point




estimates.




         It was not attempted to present future trends in costs and prices




for the period considered.  However, the results of the analysis do




allow one to deduce how the estimated impact will change when costs




and prices will change relative to the levels assumed for the analysis




using _ "  c^st levels and a range of prices.
                                   IV-2

-------
IV.	IMPACT ASSESSMENT METHODOLOGY




IV.1.    INTRODUCTION





         This chapter describes the methodology whereby the economic impact




of requiring added offshore water treatment equipment and reinjection




facilities is assessed.  As discussed in Chapter III, these




facilities are expected to be required to meet the EPA treatment standards




for 1977 and 1983 on offshore oil and gas producing installations.




         Given the estimates of investment and operating costs for these




treatment and reinjection facilities discussed in the previous chapter,




and the estimates of the production economics prepared by ADL for the




offshore areas under analysis, the potential impact of these proposed




standards was evaluated in terms of:




         4  the loss of potential production due to premature abandon-




            ment of production units in 1977 and 1983.




         •  the loss of potential production due to a decrease in




            producing life of wells because of increased operating




            costs.




         •  the total capital required for investment in treatment




            and reinjection facilities.




         •  the average increase in costs per Bbl or MCF produced




            resulting from additional investment and operating costs.




         In order to cope with the uncertainty associated with various




factors in the analysis, "best estimates" of average values were made




and then tested to determine the effects on results of possible values around




this average by varying one parameter at a time.  The results of the
                                   IV-1

-------
                                TABLE III-5

             Distribution of Different Treatment Technologies

                  Currently Being Used Offshore Louisiana

                        in Federal and State Waters
Treatment
Technology
Pits and Sumps

Tanks

Plate

Flotation*

Filters
              (2)
                            Volume of
                          Formation Water
                           As % of Total
              % of Treated
% Needing    Formation Water
New Units   Needing New Units
32%
27%
9%
24%
8%
95%
90%
100%
0%
100%
30.4%
24.3%
9.0%
.0%
8.0%
                                  100%
                                                               71.7%
 (1)
    )

 (2)'
 Source:   by communication with the EPA.
)
 Onshore  treatment of offshore produced formation water.
   Considered to be Best practicable technology.
                                     111-15

-------
estimate of which types of technology are currently being used for treat-




ment of formation water produced in Louisiana Federal and state waters




(see Table III-5 ).  According to their estimates, 24% of all the forma-




tion water produced in that offshore area is presently treated by flota-




tion systems, considered to be the "best practicable".  It can also be




expected that not all of the other systems will have to be replaced by




flotation systems.  Some of these systems, given favorable conditions,




will be able to meet the standards without any additional treatment




equipment.  Other systems will require modification at a lesser cost




than the investment costs used in the impact analysis.  It was not pos-




sible, however, to allow for all these factors in the analysis.




    Therefore, the results of the analysis of the possible impact by the




new treatment standards in 1977 should be considered to present a high




cost estimate.
                                    111-14

-------
    The EPA's estimates of the cost of drilling and equipping a 3,000


foot injection well in 1973 in the Gulf of Mexico were based on the


average cost of $200,000 for drilling and equipping an oil well in that


depth range.


    These costs increased from 1973 to 1974 by 35.6% according to a


report by the Independent Petroleum Association of America's (IPAA) Cost

                2
Study Committee.   Using the IPAA index, the average cost of drilling and


equipping a 3,000 foot well was escalated to be $270,000 by ADL.  The


maximum reinjection capacity of these wells was assumed to be 10,000


bbls/day based on the Brown & Root report.  A 40,000 bbls/day reinjection


plant then would require four wells.


    Estimates of the cost of the platform deck area required for addi-


tional treatment and injection facilities in the EPA report were also


based on Brown & Root's estimates.  These estimates are applicable if an


additional deck is required because of a lack of space on the existing


platform and for situations where a new platform would be needed.  Extra


space requirements exceeding 1,000 square feet were assumed by Brown &


Root to require a separate additional platform.


    The economic impact analysis has assumed that all offshore production


units would need to install the additional  treatment systems discussed


above.  In reality, some production units will have treatment systems


capable of meeting the 1977 treatment standards.  The EPA has made an
 Joint Association Survey of the U.S. Oil and Gas Producing Industry,

 Section I, Drilling Costs, 1973, American Petroleum Association, Feb. 1975.


2World Oil. Feb. 15, 1975.
                                   111-13

-------




































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111-12

-------
    The treatment systems considered to be the Best Practicable Control

Technology Currently Available (BPCTCA) were the following:


    •  Separation by coalescence, using flow equalization (surge

       tanks), desanders and flotation, then discharge to surface water.


    •  Separation using flow equalization (surge tank), desanders and

       filters with disposal by shallow well injection.


    The EPA Draft Development Document presented energy requirements in

terms of annual costs only.  To present these requirements in terms of

annual natural gas requirements, ADL calculated the horsepower require-

ments for the treatment equipment using Brown & Root's estimates and

expressed these horsepower requirements in terms of MCF natural gas

equivalent.  Horsepower requirements and resulting natural gas require-

ments for reinjection were calculated  as well, using EPA's assumed average

depth for injection wells of 3,000 feet.

    The derivation of these horsepower requirements are discussed in

Section 8, "Direct Energy Effectiveness of Treatment Equipment", of

Chapter VI.  The energy costs were calculated for diesel oil at $10

per barrel and for gas at $0.50 per MCF.  Comparing these costs shows

that energy costs will be about 3.5 times higher if diesel oil is used.

Throughout the analysis, the natural gas-based energy costs were used.

Table III- 4   summarizes the abatement costs.
  In  terms  of  BTU  equivalents:   1  bbl  of  diesel  oil  =  6 MCF natural  gas,
  which  @ $0.50/MCF would  cost  $3  or about  3.5 times less  than  1 barrel
  diesel oil of  $10, when  using end-1974  prices.
                                III-ll

-------
III.3.  COST OF POLLUTION ABATEMENT SYSTEMS


    The investment and operating costs which are used in the economic

impact analysis were prepared by the EPA based upon the previously

referenced Brown & Root report.  The EPA estimates, as presented in

their Draft Development^ Document , added to the Brown & Root costs the

additional costs of desanders and filters based on manufacturers-' quotes

with an allowance for installation costs for system capacities of:

    •  200 bbls/day of processed water

    •  1,000 bbls/day of processed water

    •  5,000 bbls/day of processed water

    •  10,000 bbls/day of processed water

    •  40,000 bbls/day of processed water

The cost estimates were reviewed by ADL for consistency with the Brown

& Root estimates.  Further, to allow for inflation between 1973 and 1974,

ADL multiplied the costs of all the treatment equipment by 1.24 using a

Nelson inflation index indicating an inflation of 24% for Miscellaneous

Equipment during that period.  Estimates of operating costs had been made

as a percentage of the capital costs based on percentages specified in

the Brown & Root report.  Consequently, operating costs were inflated by

24% as well.
 EPA, October 1974:   Draft Development Document for Effluent Limitations
 Guidelines and New Source Performance Standards for the Oil and Gas
 Extraction Point Source Category.
                                    111-10

-------
     California State Waters




     The California regulations applicable to offshore water disposal




from offshore oil and gas production are water quality regulations,  as




opposed to uniform effluent quality regulations.   The Regional Water




Quality Control Boards have the responsibility to establish rules to




protect underground and surface waters suitable for irrigation and domestic




purposes and the "best interests of the neighboring property owners and




the public"  (California Laws for Conservation of Petroleum and Gas,  1973,




Resources Agency of California, Sacramento, Calif., 1973, p. 15).




     Since many of the offshore producing areas are near public beaches




and recreation areas, the effluent standards which have been issued for




the platforms required treatment to 20 ppm long-term average of oil and




grease before discharge.  Rather than treat to this level, most producers




are reinjecting their formation water.







     Alaska  State Waters




     Specific information has not been obtained on the Alaska state




requirements for offshore formation water disposal.







     Louisiana State Waters




     Louisiana regulations of the offshore oil and gas platforms require




effluent to  be treated to a long-term average of 30 ppm of  oil and grease.







     Texas State Waters




     The Texas regulations of offshore oil and gas platforms call for  the




issuance of  permits for each platform based on the potential impact  of




the effluent on the local water quality.  Many of  the permits which  have




been issued  have set the long-term average of oil  and grease content in




the effluent stream as 25 ppm.



                                  III-9

-------
III.2.  CURRENT REGULATIONS

     Offshore oil and gas operations are currently regulated by the con-
tiguous state in state waters and by the USGS in Federal waters.
     The applicable USGS regulations for the Federal waters in the Gulf
of Mexico are the following:

          Wastewater disposal systems shall be designed and main-
     tained to reduce the oil content of the disposed water to an
     average of not more than 50 ppm... On one day each month, four
     effluent samples shall be taken within a 24 hour period and
     determination shall be made on the temperature, suspended
     solids, settleable solids, pH, total oil content, and volumes
     of sample obtained... No effluent containing an excess of oil
     of 100 ppm of total oil content shall be discharged into the
     Gulf of Mexico.
                    (PCS Orders 1 and 2, U.S. Dept. of the Interior,
                     USGS, 1969, pp. 8-6)

     The applicable USGS regulations for the Pacific region are slightly
different:

          (a)  Water discharged shall not create conditions which
     will adversely affect the public health or the use of the waters
     for the propagation of aquatic life, recreation, navigation,  or
     other legitimate uses.

          (b)  Wastewater disposal systems shall be designed and
     maintained to reduce the oil content of the disposed water to
     not more than 50 ppm...  On one day each month, the effluent
     shall be sampled hourly for 8 hours and the following deter-
     minations shall be made on the composite sample:  suspended
     solids, settleable solids,  pH, total oil and grease content,
     and volume of sample obtained.  Also,  the temperature of  each
     hourly sample shall be recorded.

-------
    This exemplary system was identified in the EPA's Draft Development




Document, but the guideline specifies the effluent quality the system




can achieve, not the system itself.  If an offshore operator can achieve




the effluent standard with a less expensive treatment system, he is free




to do so.




    The treatment system costs presented by EPA and updated by ADL are




the costs of installing and operating the exemplary system.  Based upon




their analysis, the EPA has concluded that the exemplary treatment tech-




nology, separation by coalescence using flow equalization and dissolved




gas flotation, should be both the 1977 BPCTCA treatment system and the




1983 BATEA  treatment system.  The effluent limitations are specified




differently under the assumption that between 1977 and 1983  the operators




will be able to increase the performance of their facilities.  This




assumption  implies that the costs of complying with the 1977 and 1983




treatment requirements are identical.  The operator in Federal waters




who installs the equipment in compliance with the 1977 standard has no




further capital cost as a result of the 1983 requirement.  In state




waters,  the operators will have to go to reinjection  in 1983.
                                  III-7

-------
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platforms in state waters to end all discharge of produced formation




water.  The water can be piped ashore or reinjected into a subsea forma-




tion.  In Federal waters, the BATEA requires that for any consecutive




30 days  the averages of daily effluent samples not exceed 30 ppm 95% of




the time.  The guidelines also require daily maximums, as shown on




Table III-?..




    In addition to the BPCTCA and the BATEA guidelines, the EPA is pro-




posing a New Source Performance Standard (NSPS) guideline applicable to




all new wells in both state and Federal waters which  is identical in its




requirements to the BATEA guidelines except that its  applicability begins




in 1977.




    New wells beginning  production  in state and Federal waters between




1977  and 1983 will have  to comply with the NSPS guidelines.   By 1983, all




wells in state waters, new and existing, will have  to go  to reinjection




of formation water.  The new wells  in Federal waters  will continue to




have  to meet the BATEA and NSPS requirements.




     The EPA used the survey from the Brown & Root report  of effluent




quality for different treatment systems now operating in  the  Gulf of




Mexico and  similar data  from other  sources to identify an "exemplary"




abatement system.  From  the effluent samples  the EPA  structured a dis-




tribution of sample results from the exemplary  treatment  systems, as




shown in Table  III-3  .   While  the Agency believes treatment systems will




produce effluent streams with  a long-term average of  27 ppin of oil and




grease,  the guideline is written in terms of  the maximum  value that 95%




of the averages of daily samples can have in  any 30 days  (48  ppm  in 1977




and  30 ppm  in  1983) and  the maximum of  95% of the sample  values during




any  one day (72 ppm in 1977 and 52  ppm  in 1983).







                                  III-5

-------
                            TABLE III-2
                    PROPOSED EFFLUENT GUIDELINES
Guideline
Oil and Grease Limitations
             Average of daily
             values for 30
             consecutive days
             shall not exceed^
 Maximum
for one day
  ppnP
                                                 ppm
Residual
Chlorine
 ppm
BPCTCA
  state waters

    produced water
    deck drainage
    sanitary waste

  federal waters
    produced water
    deck drainage
    sanitary waste
 72
 72
 NA
 72
 72
 NA
                     48
                     48
                     NA
                     48
                     48
                     NA
  NA
  NA
   1
  NA
  NA
   1
BATEA

  state waters

    produced water
    deck drainage
    sanitary waste

  federal waters

    produced water
    deck drainage
    sanitary waste
 52
 NA
 52
 52
 NA
      no discharge
                     30
                     NA
                     30
                     30
                     NA
  NA
  NA
   1
  NA
  NA
   1
NSPS
  state waters
    produced water
    deck drainage
    sanitary waste
  federal waters
    produced water
    deck drainage
    sanitary waste
 52
 NA
 52
 52
 NA
      no discharge
                     30
                     NA
                     30
                     30
                     NA
  NA
  NA
   1
  NA
  NA
   1
NOTE;
1.  There shall be no discharge of free oil to the surface waters.
2.  There shall be no discharge of floating solids as a result of sanitary
      waste discharge.
3.  ppm  (parts per million) is equivalent to a. milligrams per liter
       (mg/1) concentration.
4.  During the 30 days,  95%  of the daily averages must not exceed the
      ppm standard.
SOURCE;  U.S. Environmental Protection Agency
                                  111-4

-------




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-------
      Based upon a preliminary economic impact assessment among other




 factors,  the  initial  guidelines were modified to  the form reported here.




 Table III-l lists the applicability of the guidelines  to "new" and




 "existing" sources  of effluent discharge.  Over 30 wells may produce  to




 one  offshore  platform.   In most producing areas,  the produced formation




 water from the wells  is  now  separated from the oil and  gas, treated and




 discharged to the ocean.  Several producing platforms  can pipe their




 production to one processing platform which discharges  the formation




 water after treatment.   Each of the discharges from a  platform is a




 point source  under  the guidelines.  In addition to the  discharge of




 produced  formation  water, the rain water runoff and sanitary waste must




 be collected  and treated on  each platform.  For these  discharges, each




 platform  is a point source.




      Table III-2  lists  the  proposed guideline requirements.  The guide-




 lines separate the  offshore  producing areas into  what are called the




 state and Federal waters.  This is the jurisdictional distinction between




 those oil and gas fields whose development and operations are the respon-




 sibility  of the contiguous states, as opposed to  the U.S. Geological




 Survey.   The  EPA has  adopted the state and USGS jurisdiction boundary to




 sub-categorize the  offshore  producing areas.  The state and Federal waters




 boundary  is approximately three miles from the shoreline.




      In 1977, the BPCTCA guidelines will require  the formation water pro-




 duced from offshore wells in both state and Federal waters to be treated




 such  that for any consecutive 30 days the averages of daily effluent




 samples (four per day) will not exceed 48 parts per million (ppm)  of oil




and grease 95% of the time.   In 1983,  the BATEA guideline requires
                                  III-2

-------
III.  PROPOSED EFFLUENT LIMITATION GUIDELINES



III.l.  PROPOSED EPA REGULATIONS


     The U.S. Environmental Protection Agency is proposing a set of

effluent limitation guidelines for the offshore oil and gas production

industry.  There are three sets of proposed effluent guidelines:


     1.  The Best Practicable Control Technology Currently

         Available (BPCTCA) (1977 implementation)


     2.  The Best Available Technology Economically Achievable

         (BATEA) (1983 implementation)


     3.  The New Source Performance Standard (NSPS)

         (1977 implementation)


     In November 1974, the EPA issued the Draft Development Document for

Effluent Limitations Guidelines and New Source Performance Standards for

the Oil and Gas Extraction Point Source Category.  This report presented

an initial recommended set of guidelines based largely on a report  by

Brown and Root, Inc., for the Offshore Operators Committee, an association

of companies operating offshore oil and gas wells.
 Determination of Beat Practicable Control Technology Currently Available
 To Remove Oil from Water Produced with Oil and Gas, March 1974.
                                  III-l

-------
the industry is moving beyond the "optimal" capital structure, the cost of




capital will rise.  furthermore, given the fact that interest rates have




been unusually high in 1973 and 1974, one might expect a decline in the cost




of debt in the near future and a rise later.








     The cost of  capital has been used in this report to help evaluate whether




firms will make the required investment to come into compliance with the




proposed produced water treatment and reinjection requirements.  The revenue




stream resulting  from making the investment and keeping the well in production




has been discounted at the rate of the cost of capital.  If the net present value




of the investment in the treatment equipment is positive, the assumption has




been made that the firm will make the investment rather than close in the well.




If the industry cost of capital lies in the 10.4% to 12.0% range, theoretically,




more firms will be able to make the investment.  If the industry cost of capital




lies in the 12.0% to 14.6% range, fewer firms can be expected to make the




investment.




     While 12% seems to be a realistic cost of capital value, the impact




analysis has used .12%, 15%, and 20% to test the sensitivity of the results to




different assumed or actual cost of capital values.  The high end of the range




has been chosen so that any possible errors in the analysis will be on the




conservative side.  A high cost of capital places the greatest burden on




justification of  investments which have a long time horizon.
                                   11-97

-------
 are  to buy  a  stock.




     One method  is  to  calculate  the actual rates of return achieved by  share-




 holders in  the past, on  the assumption  that past rates of return are an accurate




 indication  of shareholder  expectations.  The principal weakness of this approach




 lies in this  very assumption.  Given the increased uncertainties about  oil




 prices, taxation, and  regulation, the risk factors of the petroleum industry may




 seem to be  changing, causing a corresponding change in expected rates of return.




 Thus, this  method did  not  seem appropriate for  this analysis.




     A second method involves deriving  the cost of equity from expectations




 about future  dividends.  This method is similar to the first one, but it




 involves a  much  longer time horizon.  The principal difficulty in this  approach




 is estimating future dividends.  For a number of oil companies, the dividend




 payout ratio  has decreased from  54% in 1969 to about 40% in 1973 and about 30%




 in 1974.  Recent financial data  show that for the first quarter of the  years 1968-1975.




 profits as  a  percent of  gross operating revenue have been steadily decreasing,




with the exception of  1973 and 1974.  In 1975, this percent was a record low.




Thus, due to  the difficulty of estimating future dividends, this method was




not used.




     A third method, which seemed most appropriate, involves calculation of a




risk-adjusted rate of  return.  By owning a portfolio of stocks, an investor




can partially eliminate  the risk involved in owning one stock.  That risk which




cannot be diversified  away is the covariance of the stock with the total market.




This covariance is known as the firm's "beta" (@).   For example, if a firm's




stock has a beta of 1.0, when the total market moves up or down by 10%, this




stock also moves up or down by 10%.   If the beta were 0.5, the stock would move




up or down by 5%.  The beta of a stock is a substantially complete measurement
                                     11-92

-------
Thus, for the purposes of this analysis, the weighted average cost of capital

will consist of a factor for the cost of debt and a factor for the cost of

equity.

     The mathematical expression generally used to calculate the weighted

average cost of capital is as follows:

                  c = Hr (ke) + Hr (kd> t1-^

where:     C  = weighted average cost of capital

           S  = market value of the firm's stock

           B  = market value of the firm's debt

           V  = market value of the firm

           k  = cost of equity

           k, = cost of debt

           t  = marginal tax rate of the firm.

     Estimate of the Cost of Debt

     Approximating a firm's cost of debt is a fairly straightforward matter.

Assuming that recent bond issues are representative of the firm's normal

current and expected future debt costs, the cost of this recently acquired

debt can satisfactorily be used as a surrogate for k, in the cost of capital

calculations.  Recent petroleum bond issues (rated AAA to A) have had yields

ranging from 9.0% to 9.5%.  In this analysis, 9.5% is used as the cost of
debt financing.
     Because the range in bond yields is so small, a separate cost of debt has
not been calculated for each firm in this sample of the petroleum industry.

     Estimate of the Cost of Equity

     Calculation of the cost of equity is the controversial element in a cost

of capital analysis.  There are several methods which one can use.  The cost

of equity is the rate of return which investors require on their money if they
                                    11-91

-------
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-------
TABLE 11-40
Oil Stock Prices
Atlantic Richfield
Cities Service
Continental Oil
Exxon Corp.
Forest Oil Corp.
Gulf Oil Corp.
Kerr-McGee Corp.
Mobil Oil Corp.
ODECO (private?)
Pennzoil
Phillips Petroleum
Placid Oil Co. (private?)
Shell Oil Co.
Signal
Shelly Oil Co.
Southern Natural Gas — merged
into Southern Natural
Resources, Inc.
Standard Oil (Calif.)
Standard Oil (Ind.)
Sun Oil Co.
Superior Oil Co.
Texaco, Inc.
Union Oil (Calif.)
Tenneco
High
113 3/4
62 1/4
58 1/2
99 3/4
11 1/8
25 1/4
92 1/2
56 1/2

30 1/2
71 3/8

72 7/8
22 3/4
73
5/73
55 1/2
36 5/8
45 7/8
61 3/4
304
32 7/8
56 3/4
24 3/4
Low
73
32 3/4
29
54 7/8
(Bid)
16
47 1/8
30 5/8

12 3/4
31 5/8

30 1/4
12 3/4
44 1/4
27 1/8
20 1/8
39 7/8
33 3/4
134
20
27 1/4
16 3/4

12/31/74
P/E Ratio Closing
11
5
5
5
11
3
16
3

5
7

6
2
7
7
3
6
4
15
3
4
6
90
42 1/4
44
63 Iff
If 2 (Asked)
17 1/4
71
36 1/4

16 7/8
41 1/2

46
13 1/4
55 1/2
41 7/8
21 3/4
42 1/2
35 3/8
172
20 7/8
38 1/2
23 1/4
      11-96

-------
     Several words of caution about the cost of capital for an industry should




be added at this point.  Although 12% may be an appropriate general measure of




the cost of capital of the petroleum industry, each company has a different




capital structure and amount of risk associated with it.  The cost of capital




for the individual firms ranges from 8.3% to 16.0%.  Rather than saying that




the cost of capital of the industry is about 12.0%, it may be more appropriate




to state that the cost of capital in the industry ranges from 8.3% to 16.0%.




     Furthermore, interest rates and stock prices have fluctuated widely in the




past 24 months.  As shown in Table 11-40, common shares of many of the off-




shore producers had a price three to seven times earnings on December 31, 1974;




however, this P/E ratio fluctuated greatly during the year.




     In addition, the gap between internally generated funds and needed capital




investments has widened considerably.  Although gross revenues grew at an




average rate of 19.2% between 1969 and 1974, available cash flow grew by only




14.7%.  In 1974, while revenues increased nearly 75% from 1973, cash flow rose




by only 31%.  As a result, the petroleum industry must increasingly resort to




outside financing.  This trend is already evident.  Between 1967 and 1972, the




industry's ratio of long-term debt to total invested capital (long-term debt,




preferred stock, and common stock) has risen from 0.18 to 0.28.  It is




expected to rise to 0.30 in the near future.  Thus, one might also expect a




rise in the cost of equity and the cost of capital for the industry.  Traditional




financial theory implies that the cost of capital is not independent of such




changes in the capital structure.  If the industry has not yet reached the debt




limit, the increase in the cost of equity will be offset by the use of cheaper




debt funds, resulting in a lower over-all cost of capital.  However,
                                    11-95

-------
 4.5.   Cost of Capital




      Introduction




      One  objective  of a  business organization  is  to maximize the market value




 of  the  firm's equity.  When  evaluating  investments with  this objective one can




 use the firm's cost of capital  as  a means  of ranking  investment alternatives.




 The cost  of capital is the rate of return  on investment  projects which leaves




 unchanged the market price of the  firm's stock.   The  cost  of capital  can be




 employed  in a number of  ways: 1) an investment project is  accepted  if its




 net-present value is positive when cash flows  are discounted at the cost-of-




 capital rate;  or 2)  a project is accepted  if its  internal  rate of return is




 greater than the cost of capital.  Thus, the cost of  capital represents a




 cut-off rate for the allocation of capital to  investment projects.




      The  cost of capital is  one of the  most difficult and  controversial topics




 in  finance.   There  is  wide disagreement, both  in  practice  and in the  financial




 literature,  about how to calculate a firm's cost  of capital.




      Weighted  Average  Cost of Capital




      There  are a number  of alternative  sources of financing available to a




 firm; they  include  long-term debt, preferred stock, common stock, and retained




 earnings.    If  more  than  one  type is present in the capital structure  of the




 firm, the weighted average cost of capital reflects the  interdependencies among




 the individual costs.  For example, an  increase in the proportion of  debt




 financing will cause an  increase in the risk borne by the common shareholder.




 The shareholder will then require  a higher rate of return, implying a higher




 cost of equity.




     As indicated in Table 11-38,  preferred stock does not represent a very




high proportion of the capital structure of the leading offshore producers.
                                       11-90

-------
      The oil industry now is in relatively strong financial condition.




It anticipates making capital investments between now and 1983 far in




excess of the investments required for compliance with the effluent




guidelines.  Thus, the investments in offshore water treatment and




reinjection equipment cannot be regarded by themselves as being of




importance to the financial strength or the required capital investment




burden of the industry between 1975 and 1983.




      Statements about the relative importance of a proposed regulation




on one activity of an industry neglect the cumulative effects of other




regulations, inflation rates, materials and labor costs, etc.  When




judging the impact of the effluent guidelines, one is at best making




qualitative judgments about their importance relative to the total




capital demands on the industry at the same time.
                                   11-89

-------
 payments  he is  owed  are covered  by  earnings.   In  1972, which was the




 lowest recent profit year,  the  interest  coverage  ratio was  10.7.   In




 1973,  the ratio was  14.5.   If long-term  lease  arrangements  and produc-




 tion payments are regarded  as debt,  the  '  ase  Group's debt  in relation




 to  capital employed  would have been 33%  in 1973.  While  the precise




 figures are not reported by Chase,  the interest cover, ge would fall to




 9.3 in 1973 if  the lease payments and production  paymen,,« are regarded




 as  yearly payment obligations similar to interest with an equal claim




 on  revenues.




       On  the  basis of  their capital  structure, the larger oil companies




 must be regarded as  financially  strong.  Though hard to  quantify,  the




 companies seem  to have the  capacity  for undertaking additional debt in




 the coming years.  Whether  this  capacity will  be  sufficient along with




 other  capital sources  to meet the industry's needs or national energy




 goals  is  open to  some  question and beyond  the  intent of  this brief




 discussion.




       The  role of  the  industry financial analysis in this economic impact




 study  is  to characterize the financial condition  of the industry and report




 reputable  estimates of  the  capital burden which the industry is likely




 to experience in the absence of the pollution abatement requirements.




Given  the financial condition and the other capital demands, this report




 should indicate  whether the magnitude of capital expenditures required




by the effluent  guidelines will significantly distort the total industry




capital demands  or its financial condition.
                                 11-88

-------
the debt and equity percentages for 41 petroleum companies for 1972.




On the average, equity accounts for 66.8% of total capitalization. One




also sees in Table 11-37 the predominance of retained earnings in net




worth.  About  75% of  shareholders' equity is retained earnings.  In




1964, the retained earnings were 62% of equity.




      Although the ratio of long-term debt to equity has been rising




to its present level  of about  28%, it is below what one would reasonably




expect to be an upper limit of debt capacity for a profitable industry.



Each year Dun's Review publishes financial ratios for 71 categories of




manufacturing  firms.  For 1973, the average of the ratios of total debt




to net tangible worth for these firms was 103%.  For the Chase Group of




petroleum companies,  the comparable ratio was about 78%.  The concept of




an "upper limit" is an abstraction referring to a range which is viewed




as meeting some set of criteria by the banking and investment community




and applicable to a particular industry.  A firm which takes on signifi-




cantly more debt than other firms in its industry exposes its debtors to




higher risks than other firms  in the industry.  With such a high debt




portion of its capital structure, a company may face higher interest rates,




lower bond ratings, problems of raising equity or possibly the non-availa-




bility of funds.




      In 1973,  the Chase Group had long-term debt of $22.7 billion.  In




comparison, the Group's working capital was $19.6 billion and their net




fixed assets were $79.6 billion.   Total net assets were $79.1 billion.




The ratio of debt to  total capitalization is  .47 as compared with about




.6  as characteristic of manufacturing industries.   One can also look




at the interest coverage by before tax income.   The calculation is before




tax income plus interest payments divided by the interest payments.




From the creditor's viewpoint,  this ratio indicates how much the interest





                                  11-87

-------
                                11-
              PETROLEUM INDUSTRY CAPITALIZATION, 1972

                                        CAPITAL STRUCTURE
                                    Debt    Equity  Other1

 •      Pennzoil. Co.                55.6%    35.7%    8.7%
        Apco Oil Corp.              44.0     54.9     1.1
        Amerada-Hess Corp.          44.1     55.2      .7
        Ashland Oil, Inc.           36.1     53.4    10.5
 •      Atlantic Richfield  Co.      21.4     77.3     1.3
        Belco Petroleum Corp.       40.3     59.7
       - British Petroleum Co.       37.1     59.8     3.1
 •      Cities Service              27.9     09.3     2.8
        Clark Oil and Refining      34.7     61.0     4.3
        Commonwealth Oil            44.2     46.8     9.0
 •      Continental Oil             28.6     66.7     4.7
 •      Exxon Corp.                 17.0     79.6     3.4
        Gen. Am. Oil of Texas         .5     99.5
        Getty Oil Co.                6.3     80.5    13.2
 •      Gulf Oil Corp.              25.5     71.2     3.3
        Gulf Oil Canada             18.7     70.8    10.5
        Helmerich and Payne        48.0     52.0
        Imperial Oil, Ltd.          14.6     74.1    11.3
 •      Kerr-McGee Corp.            18.5     71.5    10.0
        Louisiana Land and  Expl.    30.5     69.5
        Marathon Oil Co.            28.8     71.2
        Mesa Petroleum              58.5     41.1      .4
 •      Mobil Oil Corp.             16.8     79.9     3.3
        Murphy Oil Corp.            35.0     42.1    22.9
        Occidental Petroleum       54.0     44.7     1.3
        Pacific Petroleums  Ltd.     32.4     67.6
 •      Phillips Petroleum  Co.      29.6     68.0     2.4
        Quaker State Oil            25.4     68.4     6.2
        Royal Dutch Petroleum       20.4     68.6    11.0
 •      Shell Oil Co.               26.0     74.0
        Shell Transport and Trad.  21.8     66.4    11.8
 •      Skelly Oil Co.              11.1     88.9
 •      Standard Oil  (Calif.)       16.5     83.5
 •      Standard Oil  (Ind.)        20.7     73.9     5.4
        Standard Oil  (Ohio)        26.9     68.8     4.3
 •      Sun Oil Co.                 22.8     69.8     7.4
 •      Superior Oil Co.            22.3     77.7
        Tesoro Petroleum            24.8     71.7     3.5
 •      Texaco, Inc.                13.9     73.2    12.9
 •      Union Oil of Calif.        26.3     68.2     5.5
        United Refining Co.        36.9     63.1      -
        Average                     28.4     66.8     6.5
1. Includes: Preferred Stock, Deferred Taxes,  and Minority Interest.
•  Leading offshore producers (representing 92.2% of total offshore production)
SOURCE;   "Value Line", cited in Opinion  699, Appendix E, Federal Power
        Commission, 1974
                             11-86

-------
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-------
        far more important to the overall profitability and access to




        capital of the industry than the proposed pollution control




        standards.






     •  While FEA has said that the industry can reasonably be expected




        to finance itself, knowledgeable people have questioned the




        conclusion, and it should be used here with caution.






     •  Over the period 1977-1983, the oil and gas industry will make




        capital investments of approximately $6-$7 billion per year on




        the exploration, development, and production of offshore oil




        and gas.  Total industry capital investment during the period




        will be about $14-$18 billion per year.






4.4.  Capital Structure




     The petroleum industry has historically depended primarily on




internally generated funds rather than borrowed capital.  Table 11-37




is the balance sheet for the Chase Group for 1971, 1972, and 1973.




Long-term debt plus deferred credits and minority interests makes up




22%-23% of total capitalization for the three years and is about 40% of




the value of equity.  The portion of total capitalization which is longer-




term debt has been gradually rising since 1964, when it was about 13%.




Although long-term  lease arrangements and production payments do not




appear on the balance sheet, they are sources of additional capital.




If they were regarded as debt, the Group's debt in relation to capital




employed would have been 33% in 1973 and 22% in 1964.  Table 11-38 lists
                                  11-84

-------
                      TABLE 11-36

          TYPICAL YEARLY CAPITAL EXPENDITURES

      OF SEGMENTS OF THE OIL INDUSTRY IN THE U.S.
Offshore Oil and Gas Production       $6-$7 billion per year


Onshore Oil and Gas Production        $3-$4 billion per year
Other Capital Expenditures            $6-$7 billion per year
(refineries, pipelines,
marketing, etc.)
     Total                           $14-$18 billion per year
SOURCE;  Arthur D. Little, Inc., estimates
                            11-83

-------
                          TABLE 11-35

          EXPLORATION AND DEVELOPMENT EXPENDITURES

                 IN THE U.S.: 1972 AND 1973
                             1973              1972
                           ($ million)        ($ million)


Expenditure

Lease acquisition

   Onshore                   500               200
   Offshore                3,100              2,275

Producing wells            2,705              2,330

Dry holes                    985               935

Geological and geophysical
   expense                   675               575

Lease rentals                175               165


   Total                   8,140              6,480
SOURCE:  "Capital Investments in the World Petroleum
         Industry, 1973", Chase Manhattan Bank
                            11-82

-------
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     As a comparison, Chase publishes a survey entitled "Capital




Investments of the World Petroleum Industry" each year.  The most




recent year covered is 1973.  Table 11-34 lists the capital expen-




ditures for the U.S. and for the world for 1962 through 1973.




Table II-35 is a breakdown of exploration and development expen-




ditures in the U.S. for 1972 and 1973.




     Chase lists in Table 11-34  the sum from Table 11-35 of expen-




ditures for lease acquisition, producing wells, and dry holes.  The




remaining items were not counted as being capitalized.  This pattern




may not always hold true, particularly for dry holes and geological




and geophysical expenses.




     The estimates of expenditures by the Journal and by Chase are




significantly different for the exploration and production categories.




However, they give general guidance as to the level of expenditures




one should use as a point of comparison with the pollution control




capital expenditures.  Table 11-36 lists the general comparison values




which can be used in the impact analysis.




     There are three points one should conclude from this discussion




of oil industry financial resources:






     •  The profitability of the oil industry, its tax liability, and




        its ability to finance itself are critically dependent on




        government policy and actions.  Powerful political groups




        are keenly interested in changing government policies to make




        the industry more or less profitable.  These influences are
                                11-80

-------
                                   TABLE 11-33
ESTIMATED CAPITAL AND
EXPLORATION
EXPENDITURES
OF U.S. OIL
INDUSTRY
(1972-1975)

Exploration and Production
Drilling and Exploration
Production
OCS lease bonus
Total
Other Expenditures
Refining
Petrochemicals
Marketing
Natural Gas Pipelines
Crude Products Pipelines
Other Transportation
Miscellaneous
Total
1975
(budgeted)
($ million)
8,034.0
2,104.1
5,500.0
15,138.1
3,127.8
1,643.1
1,106.0
988.0
2,318.0
240.4
1,684.0
11,106.9
1974
(estimated)
($ million)
7,657.0
2,005.5
5,024.0
14,686.5
1,974.7
816.3
780.7
541.0
1,096.0
148.7
1,073.3
6,430.7
1973
($ million)
6,660.8
1,734.8
3,082.0
11,477.6
1,103.8
269.1
914.5
600.0
150.0
152.9
646.9
3,837.2
1972
($ million)
5,717.6
942.4
2,258.8
8,918.8
946.6
300.6
1,148.9
578.0
94.0
175.0
570.0
3,813.1
Total Expenditures
26,245.4
21,117.2    15,314.8
12,731.9
SOURCE;  Oil and Gas Journal, Feb. 3, 1975
                                       11-79

-------
     Looking ahead to the next ten years, one sees conflicting currents.




Higher crude and natural gas prices have allowed large increases in




profits per barrel.  On the other hand, the high prices will dampen




demand and also raise public concern about excess oil company profits.




One must also consider that 1973 and 1974 saw foreign operations gene-




rating the largest earnings.  This, combined with price controls and




excess profits taxes in the U.S., may discourage investment in U.S.




operations rather than even a continuation of historic patterns.




     As has now been said several times, it is very difficult to project




profitability or capital expenditures patterns for the industry over an




extended period of time, given the economic and political uncertainties




of the next few years.  While it is probably inaccurate to simply pro-




ject trends from the last ten years into the next ten, it is equally




wrong to extrapolate the trends of the last year or two which saw the




devaluation of -the dollar and large inventory profits.  The Oil and Gas




Journal collects capital expenditure statistics each year from 150 firms




which are then proportionately projected to the whole industry pn the




basis of the companies' portion of total industry crude production.




Table 11-33 lists the results for 1972, 1973, and 1974 plus a projection




for 1975.  The Journal does not make a clear distinction between




expenditures which companies capitalize and those they do not.  The




drilling and exploration expenditures probably include significant funds




which are normally expensed by the companies.
                                  11-78

-------
                              TABLE 11-32

           SOURCE AND USE OF CAPITAL FOR CHASE GROUP IN 1973

                                             $ million        (%)
Funds Available From:
  Cash flow                                   21,230         (73.4)
  Long-term debt issued                        4,381         (15.2)
  Preferred and common stock issued              432          (1.5)
  Sales of assets and other transactions       2,867          (9.9)
    Total                                     28,910        (100.0)

Funds Used For:
  Capital expenditures                        14,637         (50.6)
  Investments and advances                       382          (1.3)
  Dividends to company shareholders            3,965         (13.7)
  Dividends to minority interests                157          (0.6)
  Long-term debt repaid                        3,698         (12.8)
  Preferred and common stock retired         	570          (2.0)
    Total                                     23,409         (81.0)

Change in Working Capital                      5,501         (19.0)
SOURCE:  "Financial Analysis of a Group of Petroleum Companies, 1973",
         The Chase Manhattan Bank
                                 11-77

-------
                              TABLE II- 3.1


                 CASH FLOW OF CHASE GRO.iF FOR 1973



                                             $ millions


Net income                                    11,678      (55%)

Write-offs (incl.  depreciation                 8,345      (39%)
            and depletion;

Other non-cash charges  (net)                   1,207       (6%)


   Total Cash  Flow                           21,230     (100%)
SOURCE:   "Financial Analysis of a Group of Petroleum Companies,  1973",
         The Chase Manhattan Bank
                                    11-76

-------
     If the $34.1 billion lease bonus payments of Table 11-30 are added




into the total capital requirements in Table 11-29,  the FEA Accelerated




Supply estimate rises to $488.1 billion.  Geological and geophysical




expenses can add another $5 to $8 billion in capital requirements over




the period.  The $493-496 billion is beyond the range of $379-474 billion




which FEA estimated would be available from traditional financing patterns




for the energy industries.




     A definitive analysis of capital requirements or capital availability




for the oil and gas industry is beyond the scope of this study.   For the




purposes of this analysis, one should note FEA's conclusion, but it




should be used with caution.




     The Chase analysis of 30 major oil companies cited earlier compiled




the sources and uses of funds by the companies.  Table 11-31 lists the




sources of cash earnings for 1973.  Thirty-nine percent of the cash flow




is from various capital recovery mechanisms such as depreciation and




depletion.  Table 11-32 lists all of the sources of capital and their




disposition for the year.  The effective end of depletion allowances




for the large oil and gas companies has reportedly had a major impact on




cash generation for the companies.  Industry-wide data, such as for the




Chase Group, is not yet available for the first quarter of 1975; however,




reports by individual firms have identified the end of the depletion




allowance as having a major effect on cash generation.
                                  11-75

-------
                                TABLE 11-30
            Estimates of Petroleum Industry Capital Requirements
                         (Billions of 1973 Dollars)
                                1975 to 1985

                                                                    FEA
                                        FEA                     Accelerated
                                     Accelerated                Supply
                                     Supply                     Adjusted
                                     Without Work-              for Work-
                                     in-Progress                in-Progress

Oil & Gas   (1)                           80.3                       98.4
Oil & Gas Capital
  Outlays That
  Are Expensed   (2)                      73.3                       73.3
Transportation:
  Oil & Product
  Pipelines                             11.9                       11.9
Gas Transmission                          5.5                        5.5
Lease Bonus Payments                     34.1                       34.1

     TOTAL                             $205.1                     $223.2
IDIncludes:  Oil, Natural Gas, and Refinery Output Numbers.
(2)   Includes:  Dry hole, intangible drilling, and exploratory overhead costs.
SOURCE:  Project  Independence Report,  p.  290, FEA, November 1974
                                    11-74

-------
conservation scenario, the total capital requirements were estimated to




be $396 billion, including expensable outlays.  The conclusion was




drawn by the report that, as a whole, the energy industries would have




access to adequate capital, assuming a simple continuation of their




past share of investment funds.




     For the oil and gas industry, including refining, FEA estimated




that $98 billion would be required over the 11 year period for the




Accelerated Supply case.  Table 11-30 shows these estimates plus the




expensed items.  FEA believes this level of investment can be entirely




financed from internal funds with additional funds available for pro-




jects outside the oil and gas industry.




     This conclusion is disputed by many inside and outside the oil




industry.  One of the major exceptions that is made to the FEA analysis




is the treatment of lease bonuses.  In Table 11-29, FEA has not included




$34.1 billion that FEA expected to be paid for lease bonuses from 1975




to 1985.  Moreover, this value is probably too low since payments in




1974 were $5.0 billion and are projected by the Oil and Gas Journal to




be $5.5 billion in 1975  (February 1975).
                                   11-73

-------
        •  Investment in treatment systems  in  1977 and  in  reinjection




           system in 1983  (Strategy 1)




        •  Investment in treatment system in 1977  and abandonment in




           1983  (Strategy  2)




        •  Investment in reinjection  in 1977  (Strategy 3).







        Having calculated the investment requirements and present values of net




after tax cash flows for these three different  strategies,  the strategy with the




highest net present value is selected.  For that strategy the loss in potential




production is calculated and stored together with the investment for 1977




and 1983.




        When all leaseblocks have been evaluated in this manner, the following




information is printed out:




        •  Total annual loss in potential production of oil and associated




           gas and condensate by either early abandonments in 1977 and 1983




           or by the decrease in producing life of production units.




        •  Cumulative total of potential production lost.




        •  Annual potential production and cumulative total potential




           production.




        •  Maximum annual water production and cumulative total water




           production.




        •  Total investment in 1977 and 1983.




        •  Percentage of total investment in 1977 in reinjection facilities.




        •  Average annual operating costs per barrel or per MCF produced




           and average addition to operating costs per unit produced due to




           treatment and/or reinjection.




        The period covered in the analysis  extended  up  to  the year 2000.





                                        IV-31

-------
       Adding the annual treatment cost to existing operating cost levels




the economic life of the leaseblock is ag-^in calculated and the decrease in




that economic life by the added operating costs is established.




       To determine whether the investment will be paid for by the remaining




production the annual after tax cashflow is calculated for each of the




remaining years post 1977.  If the present value of that after tax cash




flow happens to be smaller than the investment required in 1977, then the




loss in potential production due to early abandonment of the leaseblocks'




production units is calculated.  Otherwise the loss in potential production




due to a decrease in the leaseblocks' producing life is calculated and is




stored together with the information on the required investment.  When all




leaseblocks have been analyzed, output tables are printed out which show the




total annual production foregone for all leaseblocks by either early




abandonments in 1977 or by decreases in the producing life, plus information




on the total investment required in 1977.




       For state waters the analysis performed by the program is




more complicated because of the reinjection requirement in 1983.  Using




the same criteria as in federal waters, three possible investment strategies




are evaluated and compared.




       First, however, it is determined whether the producing life of the




leaseblock extends beyond 1983.  If this turns out not to be the case, then




the investment in treatment in 1977 is evaluated in exactly the same manner




as described above for federal waters.




       If the producing life of the leaseblock extends beyond 1983, then




the after tax cashflows of the following three strategies are calculated




(See Figure IV-8):
                                         IV-30

-------
    I   STM-T
         JL
 r «UU) IM'UT D'TA I



          1
                                                        FIGURE  IV-7
                                              Computer  Flow  Diagram
                                                     State  Waters
   NLXT U-ACL ItlXJC'C
      1»T4 DATA
          L
CXLC.
WITHOUT
ECCVJO-IC LI-E
ADD. OPERATING
T L
CC5TS
         TRAH « TRS'
                                       INVEST IN
                                        EQUIPMENT  IN 1977
            IN 1977
            IN 1983
                                       CALC. rOR  1977:
                                    HPVO • PV (AT  CASHFLOW)'
                                          PV (INVESTMENT)
   CALC. FOR  1977-
  ri • PV CAT  CASHFLOW t-
      PV (1WESTMEVTJ
STRATEGY
THEAT^ENT IS
2
19-7
.191)
£ALC.
•FV2 -

PV
PV
FOH 1977;
(AT CASHFLOWI-
(ISIVESTMENT)
      STRATTCY  3

  •EUOXCTION IK 19T7
    CALC. FOR 1977:
   3 - PV (AT CASHFLOW)-
       PV (rNVESTr-X'/TI
SELECT THE STF^.TCCy WITH
   THE 3ICIIEST ».rv
   , IWESTKTVT HE P*J2> FOR?
         HPV/07
                                         CALC. rOfi THIS
                                          LEASr, BLOCK:

                                     LOSS TN  POT. PROP-  DUE
                                     TO AfiAMJONHENT IH 1977
                                            CALCULATE:
                                       1. LOSS in POT. PROD.
                                          CLE TO DECPEASE IN
                                          PROD. LIFE.
                                       2. LOSS IN AT*CASHFLOW
                                          DUE TO ADO.  OPERATING
                                          COSTS.
                                       3. IKVrSTKEMT IN  1977

                                          STORE 1. 2,  and 3
    I   STRATEGY
                                             CALCULATE:
                                       1. LOSS IK POT.  gROD.
                                          011 TO INCREASE  IM

                                       2. LObS IK AT CASHFLOW
                                          DUE TO *DO. OPERATING
                                          COSTS.
                                       1. INVESTMENT IN 1977

                                          STORE 1. 2. *n
-------
READ
INPUT
DATA
                                                                     FIGURE IV-6
                                                              Computer  Flow  Diagram
                                                                   Federal Waters
                      NEXT LEASE BLOCK 1974 DATA
                     CALC. NUMBER OF PROD. UNITS
                     CALC. ECONOMIC LIFE WITHOUT
                         ADD. OPERATING COSTS
                      OIL AND GAS PROD. IN 1977
                     CALC. CAPACITY REQUIRED FOR
                        WATER TREATMENT SYSTEM
CALC. CAPITAL
OPERATING COSTS FOR
AND ANNUAL
TREATMENT SYSTEM
                       CALC. ECONOMIC LIFE WITH
                         ADD. OPERATING COSTS
                            KOR THIS YEAR:
                   CALC. PROD., AFTER TAX CASHFLOW
                   WITH AND WITHOUT TREATMENT COSTS
                       CALC. LOSS IN AFTER TAX
                CASHFLOW DUE TO ADDED OPERATING COSTS
                    FOR YEAR OF INVESTMENT (1977)
                        CALC. PV (AT* CASHFLOW)
 CALC. LOSS IN
 POT. PROD. DUE
 TO ABANDONMENT
    IN 1977
NO
 STORE INFO. ON
LOSS IN POT. PROD
NUMBER OF COMPLE-
TIONS ABANDONED
                        END OF PRODUCING LIFE?
                                          YES
          PV (AT CASHFLOW)
       LARGER THAN INVESTMENT?
                                              |R THIS YEAR CALC.
                                               OIL, GAS, WATER PROD.
                                               GROSS REVENUE FROM SALES
                                               ROYALTY PAYMENTS
                                               WORKING INTEREST (=2 - 3)
                                               OPERATING COSTS
                                               DEPRECIATION ALLOWANCE
                                               TAXABLE INCOME  (=4-5-6)
                                               FEDERAL INCOME TAXES (FIT)
                                               AFTER TAX INCOME (=7-8)
                                            0. AFTER TAX CASHFLOW (=4-5-8)
                                    YES
CALC. LOSS IN POT. PROD.
DUE TO DECREASE IN PROD.
          LIFE
                                                 STORE INFO. ON INVESTMENT,
                                                    LOSS IN POT.  PROD.,
                                                   LOSS IN AT CASHFLOW.
                                                                 *AT= After Tax
                                              IV-28

-------
IV.6.   COMPUTER PROGRAM




       A computer program was developed to facilitate the calculations for




the numerous cases which needed to be evaluated.




       The same program could be used for the impact analysis in state




waters and federal waters, in spite of a considerable difference in the




complexity' of the analysis required for those areas.




       The general flow diagram presenting the different steps in the




calculations required for the federal waters and state waters are shown in




Figure  IV-6  and Figure  IV- 7  respectively.  The program first reads the




data for a leaseblock, which consist of information on:




       •  the number of producing completions




       •  the number of platforms




       e  the total daily production of (1) oil, associated gas  and  water




          or  (2) gas, condensate and water.




Then the economic life is calculated for that leaseblock, using a parameter




value for the annual decline rate and the  future crude oil  or gas price.




       The operating cost function, described in the previous pages,  is




used to calculate the average annual per-barrel  (or per-MCF) operating




cost, which then is used to determine the  number of years over which  the produc-




tion will decline until  these per-barrel operating  costs equate the going




"price" per barrel of crude or per MCF of  gas.




       Annual production volumes of oil and gas  in  1977 are projected and




the  average capacity for water treatment facilities on the  production units




in the leaseblock are calculated.  Based on that capacity estimate,   invest-




ment costs and  annual operating costs are  estimated for these treatment




systems.
                                   IV-27

-------
 Since most pipelinesusually transport  the production of more than one production




 unit.




       The wellhead price used in the analysis therefore should be considered




as representing the price which the operator would get at the point of sale




decreased by the transportation costs between the production unit and that




point of sale.




       The results of the impact analysis have been tested for their sensi-




tivity to changes in this "wellhead" price.  Given the range — from $5.25 to




$11.00 — over which this "wellhead" price was changed in these sensitivity




tests,  it can be assumed that any error by not allowing for a transportation




charge in the base case price of $7.50 lays well within the range of results




obtained by these sensitivity tests.
                                    IV-26

-------
      •   Taxable Income= Gross Revenues - Royalties - Operating Costs -




                          Depreciation




      •   Annual depreciation charges were calculated using the unit of




                          production method  (1)









IV.5   NO ALLOWANCE FOR COSTS OF TRANSPORTING OIL AND GAS ONSHORE



       The impact analysis was performed,  assuming a wellhead  price for oil as




well as for gas.  This assumption  can be criticized as  being artificial in the




case of oil, where the producing company usually co-owns and co-operates the




pipeline to the point of sale onshore, thus incurring additional costs.




       It was not possible to find a cost formula which would  reflect the




considerable differences in transportation charges for  the different production




units.  These differences are the  result of differences in distances, different




volumes transported and use of one pipeline for several production units.  Also,




it was felt that the pipeline costs would not play an important role in the




decision of an operator to continue to produce a certain production unit or not.
(1)  The unit of production method requires estimates of  the  total  cumulative




     production, QCUM, over the life of  the production  unit and  calculates an




     annual depreciation  factor, DEPF, by  dividing  total  investment,  TI,  by this




     cumulative production:




                           DEPF = TI/QCUM




     Annual depreciation  charges,  DCHARGE, are then calculated by multiplication




     of  the annual  production, Q  , by  this factor:




                          DCI1ARGE
                                     IV- 2 5

-------
IV.4.   AFTER TAX CASH FLOWS FOR EACH PRODUCTION UNIT



        The annual after-tax cash flows, which were needed for the present




value analysis of the investments required for the new water treatment




and/or injection facilities, were calculated in the following manner:




        In the case that taxable income was positive:




        Annual after-tax cash flows  = gross revenue - royalty payments -




                                       operating costs - taxes
      In the case that taxable income was zero or negative:




      Annual after tax cash flows = gross revenue - royalty payments -




                                    operating costs.




      •   Gross Revenue = Annual Production of Oil x Wellhead Price +




                          Annual Production of Gas x FPC Gas Ceiling




                          Price (50C/MCF)




      •   Royalties     = 16.7% of Gross Revenues




      •   Operating costs were calculated as described in the previous




                          section




      •   Taxes         «48%  of Taxable Income
                                      IV-24

-------
    PrcduETEicrrtTnH
-t
                                         SPUR
                                                           rmatTti:
                                         ulaF"
                                                     rstioiT
                            -Petrt
                    twites
                                             K )QUCTI()H CAP
                            tnrr
              itilliort bar
els 01
                                                                          ~±
            10
20
30
                                   IV-23

-------
                                                        o
                                                        M

                                                        O
                                                        C/3
IV-2 2

-------
3.3.  Investment Costs




          Estimates of investment costs, which were required for the calculation




of depreciation charges, were again derive^ from the BOM model.  In this case




the costs were not updated to allow for inflationary trends between 1969 and




1974 because most (about 75%) of existing platforms in the Louisiana OCS area




(See Figure IV-4) are more than five years old and because we want to know what




the past actual costs were for depreciation purposes.




          Figure IV-5 shows what estimates were used for investment costs for




production units which consisted respectively of 1 platform, 2 platforms or




3 platforms.  Allowance was made in these estimates for an increase in costs




with an increasing maximum capacity of  the processing equipment.




          In the calculation of depreciation charges corrections were made to




allow for the fact that the production,  units considered in the analysis




differed in size from the model production unit and that part of the investment




had already been depreciated over the past life of these units.
                                             IV- 21

-------
                                         FIGURE   iy-3
                              Operating Costs  (in $/B)  Versus
                              Average  Completion Productivity
10.
 9.
 8.
 7.
 6.

 5.
 3.

2.5.
                          Nk
                                               _}_
                                                                             - 1
                                                                             _i—
l.C
.If
                             «X
                             1	f-

                          -I—1-+-4-
                                ill
                                                       -X
                                                                        -1—r—
                                      t	
                                .4.
                                —I-
                                                4-
                                              j  _j.     __
                                                       _L	L.
                                                                               -t
                                                                               •.r
                                                                               4-
                                                                            1  "!  .
                                                                            !  .  !
                                                                                           .-U
                                                                    -f-
  10
20
40
60   80   100
200
400
600
1000
                          Average Completion Productivity  (B/D)
                                               IV-20

-------
                                 TABLE IV-4
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
Calculation of Operating Costs in $/B and
B/D per Completion
B/Yr $/Yr
thousand bis thousand US$ $/B
499.3 367.6 .74
1495.8 898.5 .60
2196.6 1225.2 .56
2595.2 1470.2 .57
2745.1 1633.6 .59
2631.6 1756.1 .67
2430.3 1837.8 .76
2117.2 18
1825.8
1563.2
1328.7
1129.4
960.0
816.0
693.6
589.5
501.1
426.0
362.1
307.7
261.6
222.3
189.0
160.6
37.8 .87
1.01
1.17
1.38
1.63
1.91
2.25
2.65
3.12
3.67
4.31
5.07
5.97
7.02
8.27
9.72
11.44
136.5 T 13.46
B/Comp.(1)
152
186
200
237
209
180
155
129
111
95
81
69
58
50
42
36
30
26
22
19
16
13
11
10
8
     Bis/completion
                                        IV-19

-------
                              TABLE IV-3
Calculation of Annual Production
for the BOM Model
Assuming a
No. of Compl.
Initial B/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
9
152
13
210
Production Unit,/1N
15% Annual Decline Rate
8
240
6
182
4
154
Annual Production Thousand
499.3
499.3
499.3
499.3
424.4
360.7
306.6
260.6
221.5
188.3
160.0
136.0
115.6
98.3
83.6
71.0
60.4
51.3
43.6
37.1
31.5
26.8
22.8
19.3
16.4
14.0

996.4
996.4
996.4
996.4
847.0
720.0
612.0
520.1
442.1
375.8
319.4
271.5
230.8
196.2
166.7
141.7
120.5
102.4
87.0
74.0
62.9
53.5
45.4
38.6
32.8


700.8
700.8
700.8
700.8
595.7
506.3
430.4
365.8
310.9
264.3
224.7
190.9
162.3
138.0
117.3
99.7
84.7
72.0
61.2
52.0
44.2
37.5
32.0
27.2



398.6
398.6
398.6
398.6
338.8
288.0
245.0
208.1
176.8
150.3
127.8
108.6
92.3
78.5
66.7
56.7
48.2
40.9
34.8
29.6
25.2
21.4
18.2




224.8
224.8
224.8
224.8
191.1
162.4
138.1
117.4
99.8
84.8
72.1
61.3
52.1
44.3
37.6
32.0
27.2
23.1
19.6
16.7
14.2
12.1
3
91
bls/yr





99.6
99.6
99.6
99.6
84.7
72.0
61.2
52.0
44.2
37.6
31.9
27.1
23.1
19.6
16.7
14.2
12.0
10.2
8.7
7.4
6.3
2
102







75.0
75.0
75.0
75.0
63.7
54.2
46.1
39.2
33.3
28.3
24.0
20.4
17.4
14.8
12.6
10.7
9.1
7.7
6.6
5.6
Total

499.3
1495.8
2196.6
2595.2
2745.1
2631.6
2430.3
2117.2
1825.8
1563.2
1328.7
1129.4
960.0
816.0
693.6
589.5
501.1
426.0
362.1
307.7
261.6
222.3
189.0
160.6
136.5
116.2
(1)  Number of completions and their initial productivity were
    obtained from the BOM Model production unit discussed in
    1C 8557/W72.

-------
         For these calculations it was assumed that the production  profile




of each completion had a plateau of level production during  the  first  four




years of the completion's life and declined at 15% per year  during   the




remaining life.  This differed considerably from  the production  assumption




made in the BOM information ciruclar  in  1972 wherein it was  assumed that the




annual decline rate was close to 6% a year.  This difference in  decline  rate




can be explained by the fact that  since  1972 allowables have increased to the




extent that completions in  federal waters  in 1975 are  produced at their




Maximum Efficient Rates.






          The annual production resulting from these  calculations is shown in




Table IV-3.  Given the number of producing completions,  total annual




production and total annual operating costs,  the operating cost per  barrel




produced and average completion productivity was calculated as shown in




Table IV-4.  The relationship between cost per  barrel produced and average




completion productivity is shown in Figure IV-3.   The functional  relationship




as shown in Figure IV-3 between operating costs per barrel produced  and




average completion productivity was used throughout  the analysis.




          Levels of operating costs per completion for  gas producing units




were assumed to be the same.  Operating costs per completion within  state




waters were estimated to be 10% lower on the average  then  operating  costs with-




in federal waters, reflecting lower transportation costs  for personnel  and




materials.
                                         IV-17

-------
         Total operating costs in a given yet.r for a production unit with the




same number of completions as the r.odel u -.it but with twice uhe average daily




productivity per completion will not be much different from the total operating




costs of the model unit.  The only item which might be somewhat higher is




surface equipment maintenance (See Table IV-2).




         If production unit has twice the number of completions, however,




operating costs can be expected to be much higher.  Insurance and workover




expense, which (Table IV-2)   together make up 56? of the  .Derating costs,




would be twice as high and more labor will be required to operate the larger




number of wells.




         Therefore in the analysis a linear relationship was used between the




number of completions and total operating costs for a production unit implying




that with twice the number of completion on a production unit operating costs




would be twice as high regardless the average completion productivity.  As a




result operating costs per unit produced were assumed to be inversely related




with completion productivity, implying that a production units' per barrel or MCF




production costs would be twice as high, if average completion productivity




would be half and that per barrel or MCF production costs would be half as high




if completion productivity would be twice that of another production unit.




         In order to establish the functional relationship between operating




costs per unit produced and completion productivity over time, a production




profile was calculated for the BOM model unit.
                                          IV-16

-------
                                   TABLE IV-2 - Continued


INDIRECT COSTS

11.  ADMINISTRATION & GENERAL OVERHEAD

          .40 x (Co. Plant Operators + Line  2  and 7)

          .40 x (33,846 + 21,154 + 24,198)
          .40 x 79,360 =                                                       $ 31,744


FIXED COSTS

12   INSURANCE

          283,500 (footage) x $1.41/ft + $221,665 (all risk)                   $621.400

TOTAL OPERATING COSTS, ANNUAL
(Excluding Depreciation)                                                      $1,837,855
     Source:  ADL estimates based on information  from industry sources.
                                                IV-15

-------
                                TABLE IV-2 - Continued
Helicopter — To assure availability and reduce cost, helicopters are contracted
            on a monthly basis.

     Schedule:  6 hrs/wk for crew changes x 52 = 312 hr/yr
                4 hrs/day for transportation of special crews x 1.5 days/wk
                  x 52 = 312 hr/yr

     Special Crews:  Contract personnel, wireline, machinery maintenance,
                     equipment modifications, painting, etc.  Also flights
                     for hauling small equipment and parts for repair.
     Monthly Avg. = 312
          Base Rental  1/2 x 8,500 $/mo x 12 =
                       52 hr/mo x $60 x 12 =

     Sub-Total Helicopter

     TOTAL TRANSPORTATION

 6.  SURFACE EQUIPMENT MAINTENANCE

     0.05 x $2,419,800 (Production equipment cost)

 7.  OPERATING SUPPLIES

     0.20 x $120,990

 8.  WORKOVER EXPENSE

     Over life of field:

          15 Major Workovers @ 500,000  =   $7,500,000
          20 Minor Workovers @ 10,000          200,000
          $25,000/yr wireline work x 20 yr     500,000
                                            $8,200,000


                     =$410,000/yr
                                                           $51,000
                                                            37,440

                                                           $88,440
                                                                           $257,252



                                                                           $120,990



                                                                           $ 24,198

                                                                           $410,000
 9.  RADIO & TELEPHONE

10.  TOTAL DIRECT COSTS
                                                                           $ 10,335

                                                                         $1,184,711
Source:  ADL estimates based on information from industry sources.
                                      IV-14

-------
                                      TABLE IV-2


                                SAMPLE OPERATIN'G COSTS
                         3 Platforms, 28 Wells, 45 Completions

                      Assuming  shifts of  7 days on and 7 days off
DIRECT COSTS

1.   LABOR

    Contract Labor

         1 Cook, 6.50 $/hr. x 12 h/d x 365                     $28,470
         1 Cook's Helper  6.00 x 12 x 365                       26,280
         1 Gang Leaderman  8.00 x 12 x 365                      35,040
         2 Roustabouts  6.50 x 12 x 365                         56,940
         1 Pumper  8.00 x 12 x 365                              35,040
         1 Electrician-Mechanic  12.50 x 12 x 365               54,750
    Sub-Total Contract (Overhead Included)                    $236,520

    Company Labor

         2 Plant Operators @ $16,000/yr                        $32,000
         Vacation Relief  3 wk/man x 6 x 16,000                  1,846
                                           52
    Sub-Total Plant Operators                                  $33,846

    TOTAL LABOR                                                                $270,366

2.   SUPERVISION

         1  Foreman @ $20,000/yr                               $20,000
         Vacation Relief  3 wk x 20.000                          1,154
                                   52
    TOTAL SUPERVISION                                                          $ 21,154

3.   PAYROLL OVERHEAD

         $33,846 + $21,154 x .25                                               $ 13,750

4.   FOOD EXPENSE

         15 $/d x 9 x 1.15 (15% for special labor crews) x 365                 $ 56,666

5.   TRANSPORTATION—Labor, Equipment & Supplies
    Assumes company has no adjacent or close-by field operations

    Boats

         1/2 Shore to Field, combination personnel & supply
             475 $/d x 365                             '       $86,687
         1/2 Standby and Field transportation boat
             450 $/d x 365                                      82,125

    Sub-Total Boats                                           $168,812
    Source:  ADL estimates based on information from industry sources.
                                             IV-13

-------
         The estimates of these cost elements, expressed in 1974 dollars,  are




shown in Table  IV-2.    They differ considerably from BOM estimated costs  due




to changes in operating procedures and inflation.




Operating Costs Per Unit Produced Per Completion




         The estimates of annual operating costs had to be put on a common




basis before they could be applied to the production units considered in the




analysis.




         For analytical purposes, the average daily productivity per producing




completion at each stage of the producing life of the production unit was




chosen because the data base specified productivity by completion and not  by




well.
                                          IV-12

-------
         Most of the wells have more than one completion and as a result,  a




total of 45 completions are producing oil and gas in the years of peak




production.  The processing equipment on the platforms is sized to handle  oil




and condensate production of 10,000 B/D and a peak gas production of 48 million




cubic feet/day.




         Processing on the main platform consists of:  three-phase separation




of natural gas, condensate and water; dehydration of the gas to sales




specification; water treatment and disposal; storage and transfer of oil




(See Figure  IV-2).   Note that the treatment technologies, which are considered




in this analysis have to be added to this processing equipment.




3.2.  Operating Costs




         Annual operating costs calculated in the BOM model consisted of the




following items:




         Direct Costs




         •  labor costs,




         •  supervision,




         •  payroll overhead,




         e  food expense,




         •  labor transport costs,




         o  surface equipment maintenance,




         •  workover expense,




         •  radio and  telephone costs.




         Interest and  Fixed Costs




         •  administration and general overhead,




         •  insurance.






                                           IV-11

-------

















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IV-10

-------
  LEGEND
• Oil weii.tingl*
^ Oil wtll, dual
•4- Dry hol»
•fr Got wtll
^ 6o» and oil «til
(5] Platform
                    4*~f-
                               iPloiform C
                                   ea
                              *\f>:
                               x'sVj,
                                     /PlotfcrmA
V'/;'';I'N;"    z
 9*/ * k
                              10
                               *  "
Plfltform C
    a—
                                                                   Platform B
                                                               8  oil pipeline
        H
        j
        *
                                                                                                   r
                                                                                         I
                                                                               fgot pipeline  I
                                                                                         1
                                                                         To »OI«t
FIGURE IV-1       Lease Plat Showing Platforms, Wells, and Flow Lines in Model.
SOURCE:  Bureau  of Mines Circular  1C 8557/1972
                                            IV-9

-------
 IV.3.  PRODUCTION ECONOMICS






         The operating costs and investment costs used in the analysis were




derived from the estimates made for a model unit described in the Bureau of




Mines (BOM) Information Circular IC-8557.  This model, as mentioned  in the BOM




report, was intended to show "... the costs involved in exploring, acquiring,




developing, producing and abandoning a typical production unit in the Gulf of




Mexico."  As such it presented a basis for estimating the investment and




operating costs of such a typical unit, which then was tested with the industry




and adjusted to allow for differences between the BOM model production unit  and




the actual production units which were considered in this analysis.





3.1.  The Bureau of Mines Model Production Unit




          The model production unit consisted of three  platforms,  one main




 platform with 12 wells, where most of the processing of  oil, water and gas  is




 done and two satellite platforms each with 8 wells,  where the  processing is




 limited to two-stage separation (See Figure IV-2).
                                       IV-8

-------
               The analysis, using the decision rules  described  above,  represents




      a simplification of what may happen in reality.   In the  first  place, many




      individual operators have economic criteria different from the criteria




      described above.  In the second place, the decision to shut down  a produc-




      tion unit in a field will also have to consider  the effect that the shut-




      down may have on production from other units in  the field, since  shutdown




      of a unit    can be expected to change the field's production  character-




      istics.




      2.2.  Producers Pass On All Costs




               It might well be that producers in federal waters will be able to




      pass on some of the additional costs for treatment and reinjection facilities




      by increasing their prices for oil and gas.   Therefore a likely range




      of the increase in average cost per Bbl or MCF produced, was calculated




      assuming the following:






         •  Producers would like to recover their  investment  in facilities,




            including a return on that  investment  within  15 years.




         •  The cost increase should reflect  the  increase in  average after




            tax cost levels over a period of  fifteen years, allowing for




            increases in depreciation  charges.




         The calculations used projections of aggregated  oil  and gas production




for the period of 15 years following 1977 and 1983 plus  estimates of total




investment required in treatment and reinjection  facilities,  thus disregarding




differences between individual operators  and  individual  production  units.
                                         IV-7

-------
         He will choose that alternative  which produces the highest net present




value of after-tax cash flow  less the net present values of investments required.




         If the expected producing life of the production unit falls short of




.1C)83, the operator will simply decide whether to invest in facilities, which




are required to comply with the 1977 standards.  He can be expected to shut




down his production unit in 1977 if he concludes that the investment in the




least expensive type of equipment, which will meet the EPA standards, will not




be paid for by the present value of after-tax revenues from the unit's




expected remaining production.




         He will have to shut down in 1983 thereby foregoing some potential




production if his analysis shows that the producing life will indeed extend




beyond 1983, but that only the less expensive investment in treatment facilities,




required for compliance with 1977 standards, will be paid for.




         The analysis which is presented on the following pages is based on




the assumption that all operators of production .units in state waters will appply




the above rationale in 1977 when deciding how to comply with the new standards.




The analysis then evaluates the loss of potential oil production, which can be




expected from:




         •  Immediate platform shut-downs in 1977 in state and federal




            waters,




         •  Platform shut-downs in 1983 in state waters and




         •  A decrease in the producing life of those platforms in




            state and federal waters which will not be shut down in 1977 or




            1983, but whose ultimate productive lifetime will be foreshortened




            by increased operating costs.
                                         IV-6

-------
         To determine which alternative he should choose, the operator




will first have to establish whether and to what extent the remaining




producing life of the production unit will extend beyond 1983.




         If the producing life does indeed extend beyond 1983, the operator




will then have to compare the net present values of the following cash




flows:




         •  First, the cash flow resulting from an investment in 1977




            followed by another investment in 1983 and extending




            over the producing life, where the producing life has




            been estimated allowing for additional operating costs,




            first for the new treatment facilities and later in 1983




            for the injection facilities;




         •  Second, the cash flow resulting from an investment in




            1977 in reinjection facilities and extending over the




            estimated remaining producing life, which will be




            shorter because of the additional operating costs for




            the injection facilities.
                                   IV-5

-------
                                  TABLE  IV-1

            Possible Alternative Outcomes of an Investment Analysis

                in New Treatment Facilities  in 1977  for a

                       Production Unit in State Waters
Possible Outcome Of
Investment Analysis
         Action In
      Year Of Required Investment

   1977                        1983
Remaining production
will not pay for any
additional investment.

Remaining producing
life falls short of
1983.

Remaining production
will pay out invest-
ment in treatment
facilities only.

It is cheaper to
invest first in
treatment facil-
ities and then
in additional
injection facil-
ities.

It is cheaper to invest
in reinjection facilities
immediately.
Shut-in
Invest in treatment
Invest in treatment
No investment required
No investment required
     Shut-in
Invest in treatment
Invest in reinjection
Invest in reinjection     No investment required
                                        IV-4

-------
IV.2.   GENERAL APPROACH

2.1.   Producers Absorb All Costs

         If he has to absorb all additional investment and operating costs

in 1977 the operator of a production unit    in Federal waters which

does not conform to the new standard will have to evaluate the following

alternatives:

         •  He can shut the operations of his production unit, or

         •  He can invest in treatment facilities required for

            compliance with the 1977 standards.

         The operator's decision to abandon his production unit or to

invest in these treatment facilities will likely be based on an estimate

as to whether or not production over the unit's remaining life will pay

for the investment.  The estimate of the remaining producing life of the

unit will be based on a comparison of operating costs per unit produced

with revenue per unit produced.

         The operator of a production unit in  state waters in 1977 will

be faced with a larger number  of possible decisions.  He will have to

evaluate the following alternatives:   (Table IV-1)

         •  He can shut down the operations of his production unit, or

         •  He can invest in facilities  required  for  compliance with

            1977  standards and delay until 1983 his decision  whether

            to invest  in  reinjection   facilities, or

         •  He can invest in reinjection facilities immediately.
     A production  unit  consists  of  one  or  more platforms  each  accommo-
     dating  gas  and/or  oil  production from generally  5-20 wells,  which  is
     treated to  separate  the  oil, water.and gas before oil and/or  gas
     are  transported  to shore by pipeline.
                                    IV-3

-------
V.	ANALYSIS OF THE DATA BASE




V.I.    INTRODUCTION




        In the following sections    the available data are analyzed to




justify certain generalizations which were made for the impact analysis




applying the methodology described in the previous chapter.




V.2..    GEOGRAPHICAL SEGMENTATION OF OFFSHORE OIL AND GAS PRODUCTION




        Offshore oil and gas production  is located in three




geographical areas:  California, Alaska's Cook Inlet and the Gulf of




Mexico.  (See Table V-l.)




        The potential impact on California offshore oil and gas production




has not been analyzed in this study since an estimated 95% of the brine




produced offshore is thought to be reinjected as required by the 1983




standard.  The potential impact for bringing the remaining 5% in compliance




is considered to be small.




        Cook Inlet crude/condensate production was 11.5% of total U.S.




offshore crude and condensate production and 1.7% of total U.S. onshore and




offshore production in 1974.  Gas production in Cook Inlet was only 1.7%




of total offshore and 0.3% of total U.S. production.  None of the




approximately 13.6 million barrels of water produced annually in Cook




Inlet is reinjected at present.  At present most of the water from 14




oil producing platforms is piped ashore for processing and discharge




into the Inlet.
                                   V-l

-------
                                  TABLE V-l
                        Average Daily U.S. Offshore
                     Oil and Lease Condeasate Production

                     	in 1974 (1)
                      Federal
State
Total
                     Oil   Gas     Oil   Gas     Oil   Gas
                    MB/D  MMCF/D  MB/D  MMCF/D  MB/D  MMCF/D
% of U.S. % or U.S.
Offshore  Total (2)
Oil  Gas  Oil   Gas
California
Alaska
Louisiana
Texas
Total
47
0
938
4
989
15
0
9122
439
9576
177
153
13
1
344
68
200
1485
258
2011
224
153
951
5
1333
83
200
10607
697
11587
                                                              16.8  0.7  2.5   0.1

                                                              11.5  1.7  1.7   0.3

                                                              71.3 91.5 10.7  17.7

                                                               0.4  6.1  0.06  1.2

                                                              100. 300. 14.96 19.3
(1)  Source:  "Outer Continental Shelf Statistics, 1953-1974",
              U.S. Department of the Interior, Geological Survey-
              Conservation Division, June  1975.

(2)  Total average daily production in the U.S. in 1974 was 8849 MB/D oil and
     lease condensate and 60,000 MMCF/D gas.
                                     V-2

-------
         The Gulf of Mexico is the area of greatest offshore oil and gas




production.  Offshore Louisiana and Texas produced 72% of the U.S. offshore




total oil and condensate and 11% of total U.S. onshore and offshore oil and




condensate production in 1974.   Total gas production was 92% of U.S. offshore




and 18% of total U.S. onshore and offshore production.  Gulf waters are




further divided into the operations conducted in state waters (out to the




three mile limit) and those conducted in Federal waters.  Texas state and




Federal waters account for.0.7% of total Gulf crude oil and condensate




production and 4.2% of gas production with about half of the oil and all




of the gas coming from the Federal domain.  Louisiana state and Federal




waters account for more  than 99% of total Gulf crude/condensate production




and about 94% of total Gulf gas.  Eighty-seven percent of the Louisiana oil




and 85% of the gas is from Federal waters.




         The division between Gulf state and Federal waters is germane to the




impact analysis because  E.P.A.'s proposed regulations discern between




production from state and Federal waters.
                                     V-3

-------
 V.3	SOURCE OF DATA AND GENERALIZATIONS USED IN THE ANALYSIS





 3.1.   Introduction



         ADL does not have access to proprietary production  and cost data




 for all production units in offshore areas.  Thus it became  necessary to




 make several generalizations before the available data could be used for the




 analysis.





         The data sources available for the purpose of the analysis were the




following:




         •  "Approved Maximum Efficient Rates for Reservoirs and Maximum




            Production Rates for Well Completions," October 1974; the




            United S'tates Department of the Interior, Geological Sruvey,




            Conservation Division, Gulf of Mexico Area O.C.S.




         •  "Summary Production Report of Oil, Gas, Water by O.C.S. Leases




            and State Leases with U.S.G.S. Participation in Units from




            Monthly Report of Operations  (9-152) for Producing Leases,




            June 1974;" United States Department of the Interior, Geological




            Survey, Conservation Division, Gulf of Mexico Area - O.C.S.




         •  "Offshore Petroleum Studies.  Composition of the Offshore United




            States Petroleum Industry and Estimation of Costs of Producing




            Petroleum in the Gulf of Mexico;" Bureau of Mines Information




            Circular IC-8557, 1972.




         •  "Draft Development Document for Effluent Limitations, Guidelines




            and New Source Performance Standards for the Oil and Gas




            Extraction Point Source Category;" United States Environmental




            Protection Agency, October 1974.
                                      V-4

-------
         •  A list with multi-well platforms  in the OCS  area  of  the  Gulf  of




            Mexico obtained  from  the Offshore Oil  Scouts Association,




            New Orleans,  Louisiana.





         •  "Statistical Report for the Year 1973,"  State of Alaska Department




            of Natural Resources, Division of Oil and Gas, Anchorage, Alaska.




         •  "Production and Proration Order;" State of Louisiana, Department of




            Conservation, New Orleans, Louisiana, December 20, 1974.




         o  Personal Communication with EPA and oil industry sources.




Based on this information, estimates were made of:




         •  The size and number of production units present in offshore areas,




         •  The annual volumes of oil, gas and water produced from each of




            these production units and the decline rates of the annual




            production,




  3.2	The Size and Number of Production Units Present  in Offshore Areas




         Table V-2 shows the numbers  of platforms which were considered in




the analysis as compared with the actual number of  platforms present in 1974




in the federal and state waters of the Gulf of Mexico and in the state waters




of Alaska.  The sample of platforms used to estimate the  possible impact in




the federal waters of the Gulf of Mexico was so large  (>90%) that it can




safely be assumed that the results of the impact analysis based on that sample




apply to the total population of platforms in the  federal waters.





          In leaseblocks with more than one platform,  it was necessary to make an




 assumption of how these platforms were divided over various production units.




 Some  production units consist of more than one platform and in such cases one




 platform will be the main processing platform where all the oil, water and




 gas produced  by the  other platforms  will be separated and treated.   It is
                                      V-5

-------
                                  TABLE V-2
            Number of Oil and Gas Platforms Considered and Total

              Number of Platforms Present in Offshore Areas
                                               State and Federal Waters
Louisiana
Texas
Gulf of Mexico
California
Alaska

Actual
Considered
Actual
Considered
Actual
Considered
Actual
Considered
Actual
Considered
Multi Well
644
581
23
20
667
601
22
none
14
14
Single Well
1858
1216
115
none
1973
1216
none
none
none
none
^  Based on 1973 data for Alaska and 1974 data for California and the
   Gulf of Mexico.
                                      V-6

-------
assumed that for such multi-platform production units the additional water




treatment facilities required in 1977 will be located on these main processing




platforms as well.




         The number of applications for discharge permits filed by offshore




operators with the EPA provides an indication of the actual number of treatment




facilities in the Gulf of Mexico federal waters.  By October, 1974 there had




been 327 applications for the Louisiana O.C.S. area. Based









on the distribution shown in Table V-3 and since there is no reason to assume




that operators in different lease blocks will or even can combine platforms




for water treatment or reinjection purposes, it was assumed that typical




production units consist of one platform.  The effect of assuming that a




production unit consisted of three platforms was also evaluated.
                                        V-7

-------
                                    TABLE V-3
                                                    .CD
                      Gulf of Mexico, Federal Waters

        Distribution of Multi-Well Oil and Gas Producing Platforms

                              Over Leaseblocks
              (2)
                                                     Type of Platform
                                                    Oil             Gas
Number of Platforms
   per Leaseblock
         1

         2

         3

         4

         5

         6

         7

         8

         9



Total Platforms
Number of Platforms
in Each Category:
111
44
25
14
7
6
2
2
1
112
18
3
1
none
none
none
none
none
440
601
(1)
   Including Louisiana and Texas federal waters.
(2)
   Platforms considered in the analysis - Refer to Table III-3.
                                        V-8

-------
 3.3    Estimates of the Annual  Volumes of Oil, Gas and Water Produced and

        Estimates of the Annual  Production Decline Rates



         For the Gulf of Mexico area information was available on total volumes



of oil, gas, condensate and water produced in each leaseblock    for the month



of June 1974.  Tables   V-4  and V-5   were developed from this information to obtain



an idea of the distribution of different water/oil and water/gas ratios for



existing platforms in the Gulf of Mexico federal waters.  The tables show



how the number of platforms with daily oil or gas production in a given range



are distributed over various ranges of water produced with that oil or gas.  The



ranges for gas and oil production respectively have been chosen to be the same


                                (2)
on a thermal equivalence basis,    so as to allow comparison of the distribution



of water oil ratios for oil producing platforms with the water gas ratios of



gas producing platforms.



         Figure V-l, which   shows the cumulative distributions of oil, gas,



and water production from oil and gas producing platforms, suggests



the following conclusions:



         •  Total gas production per platform is consistently higher than



            total oil production per platform, if measured on a Btu



            equivalent  basis.  Of the total of 199 gas producing platforms



            in a sample, 99 or 49.8% had a production of more than



            12,000 MCF/D (= 2000 B/d) .
   Source:  USGS, Summary Report of Oil, Gas, Water by OCS Leases and

            State Leases for Producing Leases, June 1974.



 (2)
   1 Bbl crude oil - 5850 cu. ft. natural gas in terms of Btu equivalents.
                                       V-9

-------
                                           TABLE V-4
                                Louisiana Federal Waters
                       Number of Oil Producing Platforms  Ranked  by
               Total Average Daily Oil and Total Daily Water Production
(1)
Average
Daily Oil
Production
per Plat-
form (B/D)
0- 20
20- 50
50- 100
100- 200
200- 500
500- 1,000
1,000- 2,000
2,000- 5,000
5,000-10,000
10,000-15,000
15,000-20,000
TOTAL
% of Total
Average
0- 20-
20 50
2

7 1
9 3
16 7
9 5
10 13
10 6
3
1

67 35
15.2 7.9
Daily Water Production per Platform (B/D)

50- 100- 200- 500- 1,000- 2,000- 5,000- 10,000-
100 200 500 1,000 2,000 5,000 10,000 15,000 Total
1 1
1 1
2 2
2112 2
1 7 11 4 2 1
4 15 18 6 11
5 39 26 31 16 5 2
1 13 9 23 16 23 5
4 2 12 9 4
1
5
18 84 68 68 48 40 8 4
4.1 19.1 15.5 15.5 10.9 9.1 1.8 0.9
4
2
12
20
49
59
147
106
34
2
5
440

Cum.
% of
Total
0.9
1.4
4.1
8.6
19.7
33.1
66-6
90.7
9S-4
98-9


100%
Cumulative       23.1 27.2  46.3  61.8  77.3   88.2   97.3    99.1

(1)  Sources:   U.S.G.S. Conservation Division, Gulf of Mexico Area, O.C.S.:

               1.  Approved Maximum Production Rates for Well Completions, October 1, 1974

               2.  Summary Production Report of Oil, Gas, Water by O.C.S. Leases, June 1974

               Oil Scouts Association:

                   Platforms in O.C.S. Leases, June 1974


                                               V-10

-------
                                            TABLE V-5
Louisiana Federal Waters
Number of Gas Producing Platforms Ranked by ,n N
Total Average
Average
Daily Gas
Production
per Platform
(MCF/day)
0-120
120-300
300-600
600-1200
1200-3000
3000-6000
6000-12,000
12,000-30,000
30,000-60,000
60,000-90,000
90,000-120,000
120,000-180,000
180,000-240,000
> 240, 000
TOTAL
% of Total
Cumulative



0-
20
3
4
1
1
17
24
20
24
9
5
1
2
1

112
56.4

Average


20- 50-
50 100
1

1
1
1 2
4 1
3 3
4 4
5 3
1

1


20 15
10.1 7.5
66.5 74
Daily Gas and Daily Water Production ^""'
Daily Water Production per Platform (B/D)


100- 200- 500- 1000- 2000-
200 500 1000 2000 5000


2 1

2
1 1
1311
3 10 3 1
34 111
2122

1 1
1 1
1
12 23 863
6.0 11.5 4.0 3.0 1.5
80 91.5 95.5 98



Total
4
4
5
2
22
31
32
49
27
13
1
5
3
1
199




Cum.
% of
Total
2
4
6.5
7.5
18.5
34.1
50.2
74.9
38.5
95.
95.5
98.
99.5


100%

(1)   Sources:   U.S.G.S.  Conservation Division,  Gulf  of  Mexico Area,  O.C.S.:




               1.   Approved  Maximum Production  Rates for  Well Completions,  October  1,  1974




               2.   Summary Production Report  of Oil, Gas,  Water by O.C.S. Leases, June 1974




               Oil  Scouts Association:




                   Platforms in  O.C.S.  Leases,  June  1974






                                               V-ll

-------
•  Of a total of 440 oil producing platforms,  only 147 or 33.4%




   had a hydrocarbon production of more than 2000 B/D.  About 4.5%




   of the gas producing platforms had a production larger than




   120,000 MCF/D equivalent to 20,000 B/D which was the upper limit




   for the size of oil producing platforms in the sample.




t  Total water production on gas producing platforms is significantly




   smaller than total water production on oil producing platforms.




   About 75% of the gas producing platforms in the sample had less




   than 100 B/D of water production, compared, on the same basis,




   with not more than 28% of the oil producing platforms.  Not more




   than 4.5% of gas producing platforms have water production higher




   than 1000 B/D compared with approximately 22.5% of the oil producing




   platforms.




•  Maximum water/oil or water/gas ratios are significantly higher




   for oil producing platforms than for gas producing platforms.






   Not more than 12 (6%) of a total of 199 gas producing platforms




   have water/gas ratios greater than or equal to one when measured




   on a barrel equivalent basis  (6000 cu. ft. gas + 1 bbl equivalent




   oil) compared with 97 (22%) of the oil producing platforms.
                               V-12

-------
111-21

-------
         For the analyses it was necessary to estimate what     size

treatment and reinjection capacities would be required on different sized

production units.  This required an estimate    of  the amount of water which

could be expected to be produced together with  the oil and gas of a given

field.  For this purpose it was assumed that reservoirs included in the  data

base for the Gulf of Mexico area are without exception water drive reservoirs.

The formation pressure in a field with a water  drive stays approximately level during

the life of the field  (except where permeability is low and producing rates high)

while the formation pressure of other types of  drive mechanisms  (e.g. solution

gas drive, gas cap drive), decrease with relative uniformity over the life of a

field.

         Given the fact that the reservoir pressure has to overcome the  pressure

differentials resulting from the weight of the fluid column in the production

tubing plus the resistance to flow in the reservoir, production  tubing and

surface linesp the amount of formation water produced during any time

interval on the field's life can be assumed never to exceed the amount

of oil, corrected for  the difference in gravity between oil and water.

Therefore, for the analysis it was assumed that for a given production unit

the capacity of treatment and reinjection facilities would be sufficient to

accommodate volumes of water equal to the "total  volume of  oil and water processed

in 1974, corrected for the difference in gravity between oil and water.
   Most fields in the Gulf of Mexico have a combination of  gas  cap  and water
   drive.  As a result end of life water production for production units can be
   expected to be lower than implied by the assumption of a uniform water drive.
                                        V-14

-------
         In the case of gas fields, based on the statistics shown in Table III-6,




it was assumed that the water/gas ratio of barrels of water per MCF of gas




produced would never exceed 0.16 and that the maximum capacity for a given




water treatment facility on a platform would not exceed 5000 bbls/day of water.




         In the absence of information on actual decline curves experienced on




production units in the Gulf of Mexico or Alaska offshore a uniform exponential




decline rate was assumed, implying that the annual oil or gas production would




decrease by the same percentage in each consecutive period.  The results of the




impact were tested to changes in the value of these decline rates, which were




assumed to be  15% per year for oil producing facilities and 12% per year for




gas producing facilities.




         The approximate volume of annual production in 1974 for each completion




for oil wells and gas wells was obtained from the allowable schedules for the




Gulf of Mexico federal and state waters.  For various reasons, such as well




shut-ins for workover purposes or for observation, the allowed production can




be less than the actual production during a given year.




         Actual oil production and gas production for the Gulf of Mexico area




during 1974 and 1973, respectively, was therefore compared with the implied




production used in the analysis.  Table  V-6  shows that the use  of allowables




in the case of oil resulted in a production estimate about 25% higher than the




actual production in 1974.  In the case of gas  the use of allowables resulted




in an estimated production not more than 0.5% different from the  actual




production.  A possible explanation for the much larger difference between




actual and implied production for oil in 1974 may lie in the fact that implied




production in federal waters was based on the use of Maximum Efficient Rates
                                      V-15

-------
                            m
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-------
while 1974 production was still based on Maximum Production Rates.


	3.4    Production Units in State Waters


         For the Gulf of Mexico state waters, information was available only


on the number of producing completions by company for each individual pool or


field.  A considerable number of these fields produce oil, water and gas into


onshore facilities, where these fluids are separated and treated.   It was assumed


that the additional treatment equipment would be sized to process the water


produced from these clusters of completions operated by one company.  Most of


these clusters were relatively small (Table V-7).  The size range for treat-


ment systems assumed to be required in state waters can therefore be expected


not to be much different from the actual range of required sizes.



3.5 Production Units in Cook Inlet, Alaska	t	


         For Alaska, data was available on oil, gas and water production for


each completion on the fourteen oil producing platforms in Cook Inlet. This


data is discussed in Section VI.4 where the impact analysis for Alaska is


discussed.
1 rateMwhiT EffiCient Rate/or  a  completion is defined to be that production
  rate which can be sustained  during  at  least six months without causinc
  lasting damage in the production  characteristics of a reservoir.


  The Maximum Production Rate  is  set  for  resource conservation purposes and
  as such usually lower than the  Maximum  Efficient Rate.
                                      V-17

-------
                                  TABLE  V-7

               Size Distribution of Production Units in

                Gulf of Mexico Federal Waters    and in

               	Louisiana State Waters	


.,  ,     ,.           Federal Waters                     State Waters
Number of          	'	
                                     (2)                                (2)
Completions        Oil           Gas                 Oil            Gas/  '

   0-2              96           40                  17             12
   2-4             104           42                    67
   4-6             103           28                  21              7
   6-8              66           13                    24
   8-10             44           14                    21
  10-12             12            7                    02
  12-14             12            5                    30
  14-16             15            2                    01
  16-18              64                    01
  18-20              72                    22
  20-25             11            6                    32
  25-30              0                                 02
  30-35              1                                 02
  35-40              0                                 11
  40-50              0                                 3
  50-60              0                                 1
  60-70              0                                 0
  70-80              0                                 1
     80                                                1
   Including Louisiana and  Texas  federal waters

(2)
   Nonassociated gas

 Source:  Production and Proration  Order,  Louisiana Dept. of Conservation,
         and U.S.G.S.  Conservation Div.
                                       V-18

-------
VI.    ECONOMIC  IMPACT ANALYSIS







VI.1.  SUMMARY







        The following chapter presents the results of the impact analysis




obtained using the methodology as explained in the previous chapter.  The




analysis was first done for what will be called "base cases" developed




separately for the Louisiana state waters and the Gulf of Mexico federal




waters using best estimates for important parameters such as prices for oil




and gas, annual production decline rates, the cost of capital and using




assumptions of the most likely configuration of production units in terms




of number of platforms per unit and       space availability for




additional treatment and reinjection equipment.




        This analysis measured the impact by investment and operating costs




for additional water treatment equipment expected to be required on oil and




gas production units in state and federal waters in 1977 to comply with new




water pollution standards and the impact of costs for additional water




reinjection facilities expected to be required in 1983 in state waters.  The




impact was measured in terms of:




        •  The loss in potential production if oil and gas producers




           have to absorb the investment and operating costs for the treat-




           ment and reinjection facilities.




        •  The total investment required for treatment and reinjection




           facilities in 1977 and 1983 respectively.
                                     VI -1

-------
         «  The total number of completions which would be abandoned in




            1977 and 1983 because some production units will not be able to




            pay for the additional investment with the remaining




            production.  Price increases are assumed not to occur.




         •  The average increase in the costs per unit produced.




The analysis considered, oil and gas production in Louisiana state waters




and the Gulf of Mexico federal waters using 1974 data for existing production




units.




         The results of these analyses are summarized in Tables VT-i and VI-2.




If operators of oil and gas producing units existing in 1974, will have to




absorb all of the treatment costs and operating costs required for treatment




and reinjection facilities, then it can be expected that for units producing




in 1974:




         •  In the Gulf of Mexico, 14.0 to 27.8 million barrels of potential




            remaining production of oil and lease condensate will be lost




            or 0.6 to 1.2% of total potential production in 1977 and 81.4




            to 249.4 million MCF nonassociated and associated gas representing




            0.3 to 1.0% of total potential remaining production in 1977



            from oil and gas producing units existing in 1974.
                                     VI-2

-------
                              TABLE VI-1
                       Producers  Absorb All  Costs
             Range of Likely Impact in the Gulf of Mexico
                      Federal and State Waters^ '
                            (1974 dollars)
Federal Waters  (No  Reinjection Required)
Loss in Potential Prod., oil (2)  0.5-1.0%        8.5-17.5 MMB
                         gas (3)  0.3 - 0.85%       60 - 158 MM MCF
Total Invest. Required, 1977                        45 - 125 MM $
                        1983                        N A
Total Completions Aban. 1977      less than 0.3%    2-8

State Waters
Loss in Potential Prod., oil (2)   1.2 - 2.1%        5.5 - 10.3 MMB
                         gas (3)   0.4 - 1.5%       21.4 - 91.4 MM MCF
Total Invest. Required, 1977                       18.8 - 19.7 MM $
                        1983                       49.7 - 56.4 MM $
Total Completions Aban. 1977      < 0.2%            1-2
                        1983      3.5 - 6.2%       42 - 75
Total Federal and State
Loss in Potential Prod., oil (2)  0.6-1.2%        14.0-27.8 MMB
                         gas (3)  0.3 - 1.0%        81.4 - 249.4 MM MCF
Total Investment Req.,  1977                        63.8 - 144.7 MM $
                        1983                        49.7 - 56.4 MM $
Total Completions Aban. 1977      < 0.2%            3-10
                        1983       0.9 - 1.5%        42 - 75
   State waters do not include Texas state waters, which represent less than
   1% of total oil production in state waters and less than 0.25% of total
   oil production in federal waters.
(2)
   Including lease condensate
(3)
   Including associated gas           SOURCE:  Arthur D. Little, Inc., estimates

                                     VI-3

-------
        •  Total investment requirements, in 1974 dollars, will be




           between $63.8 to $144.7 million by 1977 and between $49.7 to




           $56.4 million by 1983.




        •  The number of completions abandoned in 1977 will be less




           than 0.2% of total producing completions in 1976 or 1977 and




           the total number of completions abandoned in state waters in 1983




           will be between 0.9% to 1.5% of the completions producing in 1982.




Operators will not necessarily have to absorb all of these costs.  Therefore




it was calculated what the average increase in costs per barrel or MCF




produced might be, which producers would like to pass on.  The results of




these calculations are shown in Table VI-2:




        •  For oil produced in federal waters, average cost increases in




           1977 will likely be between 9.0 to 31.2c per barrel and




           between 11.6 and 16.3C per barrel for oil produced in state




           waters to allow producers to cover investment and operating




           costs for treatment facilities over a fifteen year period.
                                     VI-4

-------
                                      TABLE VI - 2
             (1)  Range of Average Cost Increases in the Gulf of Mexico
                                Federal and State Waters

                                      (1974 Dollars)
                                                 Oil Wells                Gas Wells
                                             1977        1983         1977         1983
Federal Waters                                  (in C/Bbl)                  (in C/MCF)

Cost Increase                             9.0 - 31.2   N/A          .14 _ Q.92      N/A


State Waters

Cost Increase                            11-6 -16.3  77.3-107.9  0.41 -0.57   2.41 ~3.31


                (2)  Economic Cost per Average Barrel of Oil Recovered


                                                 Oil Wells                Gas Wells
Federal Waters                               1977        1983         1977         1983

EC. Cost per Bbl Recovered ($/Bbl)       94    2382       N/A      42     4511      N/A
   •

State Waters

EC. Cost per Bbl Recovered ($/Bbl)       36  -  1237   371  -  8321  133 -  2984     808 -  17741
SOURCE;  Arthur D. Little, Inc., estimates
                                              VI-5

-------
        •  For oil produced in state waters average cost increases in

           1983 will be about 77.3  to 107.9c per barrel, allowing producers

           to recover investment and operating  costs for reinjection

           facilities over a fifteen-year period.



        •  For gas produced in federal waters,  average cost increases in

           1977 will be about  0.14 to 0.92c per MCF and in state waters

           they will be about 0.41  to 0.57C per MCF, allowing recovery over a

           period of 15 years investment and operating costs for treatment

           facilities installed in 1977.



        •  For gas produced in state waters, average cost increases in 1983 will

           likely be 2.41  to 3.31C  per MCF, allowing recovery of  investment

           and operating costs for reinjection facilities installed in 1983.



As mentioned above, the data base used for the analysis consisted of wells

reported to be producing in 1974 and as such represented only a part of the

wells which will be affected by the new regulations in 1977 and in 1983.


    To give a rough indication of potential impact of the guidelines on new

wells in the Gulf of Mexico, USGS   estimates of reserves
   "Geological Estimates of Undiscovered Recoverable Oil and Gas Resources
    in the United States,"  Geological Survey circular 725.
                                  VI- 6

-------
were used and the results of the analysis were extrapolated on a unit of




reserves basis.




         The same was done with estimates of the category of undiscovered




recoverable resources in the Gulf of Mexico and other offshore areas




as estimated by the U.S.G.S. to obtain at least an indication of the potential




impact on the oil and gas wells and platforms expected to be installed later




than 1977.  The results show that for new sources the loss in potential produc-




tion might be as high as .35 billion bbls of oil and 1.75 billion MCF of gas if  price




increases are  not allowed.  Investment might be  as high as  1.92 billion dollars




(see Table VI-17).  These high  estimates  of losses in potential production  from





recoverable resources are equivalent to about 75% of 197A offshore oil production




and to about 15% of 1974 offshore gas production.  The losses will not occur




during any single year but rather during a period of about 50 years starting




somewhere between 1990 and 2000.  The additional investment required will also




be made over a period of at least 30 years following 1977, rather than




having to be made in any one single year.




       Since                  some oil which otherwise would be discharged will be




recovered through the additional treatment required in 1977,this treatment




can be considered as another way to produce oil.  It is shown in Section VI-10
                                       VI-7

-------
of this chapter that the treatment technology considered to be BPCTCA    on



the average recovers more energy than it consumes.  However, in terms of



economic cost per barrel recovered, it can be considered as, at best, a rather



marginal investment if the objective would only be to produce more barrels of



oil at  an  earlier point in time.


                                                   (2)
         •  For oil wells the average economic cost    per barrel recovered



            in 1977 for treatment facilities will be somewhere between $36



            to $2382 mainly depending on the amount of water treated during



            that period.




         •  For gas wells the economic cost per barrel recovered in 1977



            will be somewhere between $42 and $4511.







         Reinjection systems to be installed in state waters in 1983 are



not part of the treatment systems proper.  If it is assumed, however, that



these systems will have to be paid for by the oil which is recovered through



treatment then, as shown in Table VI-2, the economic cost per barrel recovered



for oil wells will be between $371 and $8321 and for gas wells between $808



and $17741.



         As mentioned earlier, cost data which would allow a rigorous analysis of



the potential impact on offshore oil and gas production in Cook Inlet in Alaska



were not available.  A preliminary estimate of the potential impact has been made



assuming that costs for oil and gas production and required treatment and re-



injection  in Cook Inlet will be from three to six times higher than the ones



used in the impact analysis for the Gulf of Mexico.  The results of this estimate



are discussed in Section VI-12.
   Best Practicable  Control Technology  Currently Available.


 (2)
   The average  cost  per barrel  recovered  over  a 15-year period allowing  for a

   return  on  investment of 12%  to  20% and after tax  operating costs.




                                   VI-8

-------
VI.2.  FEDERAL  WATERS;  BASE  CASE  RESULTS  FOR  OIL WELLS AND  GAS WELLS





          The computer program, discussed in the previous chapter, was used to




estimate the impact of the new treatment regulations on existing oil and gas




producing facilities in the federal waters of the Gulf of Mexico.  Base case




parameter values and assumptions consisted of the following:




          •  Oil and gas wellhead prices of $7.50/Bbl and $0.50/MCF respectively.




          •  Annual decline rates of 15%/yr for oil and 12%/yr for gas.




          •  Production units consist of one platform.




          •  All platforms will require additional treatment equipment in 1977,




             consisting of surge  tank and flotation unit.




          •  All platforms will have enough space to accommodate this additional




             equipment.




The results of the analysis for oil wells are shown in Table VI-3.




          Only'one oil producing platform with one producing completion would




likely be abandoned in 1977 resulting in a loss of potential production not more




than 36.4 MB or less than 0.3% of the total 14.0 MMB of oil production foregone.




The annual volumes of potential production lost through immediate abandonment




in 1977 are shown in the column under the heading "Production Loss By Platform




Shut-ins in 1977."  Most of the potential oil production loss, 13.98 MMB or




99.7% of the total of 14.0 MMB, will be by a decrease in the producing lives of




completions.




          The annual volumes of potential production lost by this decrease in the




producing life of completions is shown in the column under the heading "By




Decrease in Producing Life."  The number of completions abandoned annually shown




in the column under the heading "Abandonments."




          In addition to the loss of potential oil production of 14.0 MMB, 40.3




MM MCF of associated gas has been estimated to be lost as well.  These losses in




                                        VI-9

-------
                                      TABLE VI-3
                                 Federal Waters - Oil
                               Producers Absorb All Costs
         Year
Production  Loss
by Platform Shut-
ins in 1977
  (barrels)	
                                               'Production Loss
                                               by decrease in
                                               Producing life
                                                  (barrels)
                Completion
               Abandonments
         1977
         197"
         1979
         1930
         19 HI
         198?
      1 0 5 4
         1967
         19 HA
         19H9
         199(1
         1991
         199?
         1993
         1991
          1997
          199 A
          1999
          2no n
          2001
          200?
          2003
          2001
          2005
          200*

         TOTAL
        4 7 n .
           0-
           n •
           n .
           n •
           n«
           n .
           n •
           n •
           o ,
           n-
           n.
           n •
           p •
           0 ,
           n «
           n .
           0 •
           n .
           n-
           n ,
           n .
           n •
           n .
       n.
       n,
       n.
   6 4 7 n .
   27 !>
                                                        A a h u fi .
                                                        14/95,
                                                       ma J
2A1U119
 i 9 'J 7 1 A .
 l H y t> » n
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  ?r>i.S7
  1:1.1 u".
  ?R?70
   1.
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   1.
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  1U-
   6.
   4.
  14.
  39.
  94.
  12-
 100.
 20 /.
 26."5,
 243.
 bn9.
 231.
 IbO.
 i3Q.
 110.
  47.
  AJ,
  3U.
   1-
   3.
   D.
   4.
   D.

2690.
Total Equipment  Investment in 1977:   $63.9 million
Fraction of  Investment Made in Reinj.  in 1977: .0000
Total Equipment  Investment in 1983:   0
Platforms Immediately Abandoned:   1
Total Oil Production Foregone:  14.0  million Bbls
Total Associated Gas Foregone:  40.3  million MCF
Completion Lost  before 1977:  4.
Production Lost  before 1977:  .054 million barrels
                                   SOURCE: Arthur D. Little,  Inc.,
                                          estimates
                                          VI-10

-------
potential production of oil and associated gas will amount to about .88% of




estimated recoverable oil reserves in 1977 and 1.12% of associated gas reserves.




Total investment required for additional equipment in 1977 will be 63.9 MM $.










        Table VI-4 shows the base case results for the gas wells in federal waters.




Early abandonments in 1977 will result in a loss of potential gas production of




513.8 M MCF or less than .7% of a total of 75.4 MM MCF of non-associated gas.




          About 74.9 MM MCF of non-associated gas, or 99.3% of the total loss




in potential production, will be through a decrease in the producing lives of well




completions.  It is estimated that together with the loss of a total of 75.4 MM MCF




of non-associated gas about 1.1 MMB of condensate will be foregone.




          Total gas production foregone will be about 0.5% of estimated recoverable




reserves in 1977 and total condensate production foregone will be about 0.67% of




estimated reserves.  Total investment requirements in 1977 will be 23.5 MM$.




Given the small number of early abandonments in 1977 it can be expected that the




new regulations will have no effect on the employment situation related with




oil and gas production in federal waters.
                                        VI-11

-------
                                       TABLE VI-4
                                  Federal Waters - Gas
                               Producers Absorb All Costs
 Year

 1977
 19 7 n
 1970
           Production Loss
           by Platform Shut-
           ins in 1977
              (MCF)	
                1 n 9 4 4 -1 •

                  42377.
                      n,
           Production Loss
           by Platform Shut-
           ins in 1983
              (MCF)	

                   n.
                   •i,
  Production Loss
  by decrease in
  Producing Life
       (MCF)	
                                     n,
                                     n.
                                     n,
                                                                              Completion
                                                                             Abandonments
                                                            i.
19*3
                                                       4 fl f)-
                                                                                  0.
                                                                                  0.
                                                                                  0.
                                                                                 20,
                                                                                  0.
                                                                                 -4-.-
I9d7
 1990
 1991
 199?
 199^
 1994
199*
1997
2000
2noi
 2004
 200*5
 200*

TOTAL
0.
n .
n •
n .
n •
n .
n'

I >
                       0 .
                      n -
                      n
                      n
                      q
                                         r; .
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                   C ,
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                   n,
                   n«
                   n.
                                                       It j?
11P4A/7.
2j.ni/oi.
 49o'H7,
                               ? 4 P 17 ,' ? .

                               4744/11.
                 -'1 3
                                                                                  0.
                                                                                  1.
                                                                                 If.
                                                                                 - 2-.-
                                                                                 16,
                                                                                 3b,
                                                                                  3,
                                                                                 43.
                                                                                  70,
                                                                                  26,
                                                                                  9Q,
                                                                                 133.
                                                                                 110,
                                                                                  ft?,
                                                                                  44,
                                                                                  7b.
                                                                                   (J,

                                                                                tt 5 6 .
Total Equipment Investment in 1977:  $23.5 million
Fraction of Investment Made in Reinj. in 1977:  .0000
Total Equipment Investment in 1983:  0.
Platforms Immediately Abandoned:  1
Total Gas Production Foregone:  74.0 million MCF
Total Oil Production Foregone:
Completions Lost Before  1977:
Production Lost Before 1977:
                                1.1 million barrels
                               10.
                              1.89 million MCF
                                              VI-12
                                                         SOURCE:  Arthur D. Little, Inc.,
                                                                 estimates

-------
        Federal Waters;  Sensitivity  Tests by Changes in Base Case Parameters




           The base  case results were  tested for  their sensitivity to changes in




 the  following parameters and assumptions:




           •  Changes  in the "wellhead" price  for oil, ranging  from  $5.25 to




             $11.00/Bbl, and for  gas, ranging from $0.30  to $0.75 per MCF.




           •  Changes  in the annual  decline rate, ranging  from  12% to 18% for oil




             and  from 9% to 15% for gas.




           •  Changes  in the cost  of capital,  ranging from 12%  to 25% for oil -




             as well  as for gas producers.




           •  Assuming that extra  space would  be  added on  to existing platforms




             either by an extra deck  or by an additional  platform if extra space




             requirements exceeded  1000 square feet.




           •  Assuming that production units consisted of  clusters of 3 platforms




             rather than 1 platform units.




The results of  these sensitivity tests produced the following  conclusions (see




Tables VI-5 and VI-6):




           •  The  estimated impact in  terms of percentage  loss  of total potential




             production is most sensitive to  changes in the price parameter.




             For  oil  this estimate  ranged from a high 1.06% to a low 0.56% of




             potential production lost, assuming "wellhead" prices  of  $5.25  and  $11.00




             per  barrel respectively.




             For  gas  this estimate  ranged from a high 0.98% to a low 0.29%,  assuming




             wellhead prices of $0.30 and $0.75  per MCF respectively.




           •  The  estimated impact in  terms of total investment required  is very




             sensitive to changes in  the assumptions about whether  extra space will




             have to  be provided  by an extra  deck  or extra platform and  whether  typical
                                       VI-13

-------
                                     TABLE VI-5
                  Sensitivity of Results to Changes in Key Variables
Federal
Varied
Parameter
Price


Decline
Rate
Cost of
Capital

Extra Space
Required
3 Platform
Unit
Value
$ 5.25
*$ 7.50
$ 9.00
$11.00
12%
18%
15%
20%
25%



(1974 dollars)
waters; no reinjection required; oil
Producers Absorb All Costs
% Loss of
Potential
Production
1
0
0
0
0
0
0
0
0
0
0

Oil
.06
.88
.73
.56
.66
.94
.88
.88
.88
.89
.80

1
1
0
0
0
1
1
1
1
1
1

Gas
.38
.12
.94
.77
.95
.24
.12
.12
.12
.13
.03

Total Number of
Investment Completions
(in MM$) Abandoned
1977
63.
63.
63.
63.
64.
62.
63.
63.
63.
120.
40.

70
86
86
99
88
78
86
86
86
41
87

1983 Total 1977 1983
NA 3 NA
1
5
3
1
2
1
1
1
3
1

Number of
Producing
Completions
End 1976
2690
2690
2694
2694
2690
2690
2690
2690
2690
2690
2690

*Base Case:  1 Platform Unit
             Equipment Technology C
             Price                   $7.50
             Decline Rate            15%/year
             Cost of Capital         12%/year
 SOURCE:  Arthur  D.  Little,  Inc.,  estimates
                                                VI-14

-------
                                   TABLE VI-6
                  Sensitivity of Results to Changes in Key Variables
Federal
Varied
Parameter
Price


Decline
Rate
Cost of
Capital

Extra Space
Required
3 Platform
Unit
Value
$ 0.30
*$ 0.50
$ 0.75
$ 1.00
9%
15%
15%
20%
25%



(1974 dollars)
waters; no reinj action required; gas
Producers Absorb All Costs
% Loss of
Potential
Production

0
0
0
Gas
.98
.50
.29
Oil
1.
0.
0.
10
67
32
Total Number of
Investment Completions
(in MM$) -Abandoned
1977
23.
23.
23.
31
50
61
1983 Total 1977 1983
NA 1
1
3
Number of
Producing
Completions
End 1976
971
971
971
NA
0
0
0
0
0
0
0

.17
.65
.51
.51
.51
.50
.50

0.
0.
0.
0.
0.
41
75
67
67
67
0.67
0.

67

23.
23.
23.
23.
23.
35.
5.

74
30
51
51
51
60
5

0
1
1
1
1
1
0

971
971
971
971
971
971
971

*Base Case:  1 Platform Unit
             Equipment Technology C
             Price                   $0.50
             Decline Rate            12%/year
             Cost of Capital         12%/year
 SOURCE:  Arthur D.  Little,  Inc.,  estimates
                                             VI-15

-------
production units consist of clus:ers of more than one platform.





 If production units were assumed  to consist of one platform which



will require an extra deck or an extra platform,  when total




space requirements for the treatment facilities exceed 1000 square




feet, then investment costs for oil producing facilities will almost




double to $120 million and investment costs for gas producing




facilities will increase by about 50% to $35 millic.i.









On the other hand, if we assume that tyi.ical production units




consist of three platforms rather than one, then total investment




requirements for oil producing units will be 50% of the base case




value or $40 million and total investment requirements for gas




producing units will be 25% of the base case value or $5.5 million.









The number of early abandonments in 1977 remains very small




despite changes in parameters; less than 0.2% of the total




number of producing completions in 1977 for oil producing units




and less than 0.3% for gas producing units.






The results of the impact analysis are not very sensitive to




changes in the cost of capital.  No significant change in the




results occurred even  when the cost of capital was 25%.
                           VI-16

-------
FIGURE VI-1
      VI-17

-------
        The results of these sensitivity tests are also shown in Figure VI-1-




It is shown in this figure that the percentage loss in potential production




of nonassociated gas is consistently lower than the loss in potential oil




production.  Also, it does appear that the percentage loss of potential gas




production will not become much less than 0.20% when the wellhead price is




increased and not much more than 0.75% when the decline rate is increased.




The fact that present-day intrastate prices are already higher.than $1 per MCF




indicates that it can reasonably be expected that not much gas will be sold




in 1977 at $0.35 per MCF.  The range in which the actual percentage loss in




potential production probably will be is therefore 0.20% to 0.75%.




        Using the same reasoning, but choosing $5.25 as the lower limit for




the expected price in 1974, the probable range for the percentage loss in oil




production was taken to be between 0.50% and 1.00%.




        Summarizing for the federal waters, the results of the impact analysis




amount to the following (See Table VI-7):




        •  Loss in potential gas production from both gas and oil wells




           will be between 8.5 and 17.5 million barrels, (no price increases)




        •  Loss in potential gas production from both gas and oil wells




           will be between 60-158 million MCF. (no price increases)




        •  Total investment required in 1977 in terms of 1974 dollars,




           will amount to between 45 and 125 million dollars.





        •  Between 2-8 completions will have to be abandoned in 1977.
                                      VI-18

-------
                                 TABLE  VI-7
                Range  of  Likely Impact  in  the Gulf  of  Mexico
                              Federal Waters
                               (1974 dollars)
 Oil Wells
 Loss  in Potential  Prod.,     oil
                          ass.  gas
 Completions Abandoned  in    1977
 Investment Required in     1977
0.5 - l.i
less than 0.2%
or     8-16 MMB
       22 - 44 MM MCF
       1-5
       40 - 100 MM $
 Gas Wells
 Loss  in  Potential  Prod.,     gas       0.2 - 0.75%
                        condensate
 Completions  Abandoned in    1977       less than 0.3%
 Investment Required in     1977
 Total  Loss  in Potential      oil
       Prod.
                             gas

 Total  Investment  Req.  in   1977

Total Completions Aban.  in  1977
                            1983
                      38 - 114 MM MCF
                      0.5 - 1.5 MMB
                      1-3
                      5 - 25 MM $

                      8.5 - 17.5 MMB
                      60 - 158 MM MCF

                      45 - 125 MM $

                      2-8
(1)
    Assuming producers absorb all costs.
SOURCE;  Arthur D. Little,  Inc., estimates
                                        VI-19

-------
        Average Cost Increases for Oil and Gas, Federal Waters
     It might well be that producers in federal waters can pass on some of
the additional costs for treatment facilities by increasing the price for oil
and gas in 1977.  Therefore, the range was calculated of these average cost
increases separately for oil and gas produced in the Gulf of Mexico Federal
waters.
                                                                  r
     First, assuming that producers would like to have a return on their
investment within 15 years, cumulative production of oil and gas was calculated
for the 15-year period starting in 1977.  (See Table VI-8.)
     Second, using the low and high estimate of the likely investment requirement
for oil producing facilities and the corresponding annual operating cost
estimates, the average per-barrel capital charge (Item 5), the per-barrel
operating cost  (Item 7), and per-barrel depreciation charge (Item 8) could be
calculated.
     Third, the net after tax increase in per-barrel operating costs was
calculated using a tax rate of 0.5 (Item 9).
     The estimated average cost increase was then found by adding the after
tax capital charge and the increase in after-tax operating costs.
     The capital charge was calculated assuming a 12% and 20% capital cost
to indicate how sensitive the cost estimate was to this particular parameter.
     The results show that a price increase for oil in 1977 would have to be
between 3.7 and 9.6 per barrel and between 0.06 and O.SO^per MCF for gas
if producers are  to recover the treatment facilities operating and invest-
ment costs including a return on that investment.
                                       VI-20

-------
                                    TABLE VI -8
                 Range for Likely Average Cost Increases in 1977
                                 for Producers in
                         Federal Waters, Gulf of Mexico


1.
2.
3.
4..
5.
6.
(1974

Production in 1977^
Production in 1991 '
Cum. Production (15 years)
Investment (MM $)
Cap. Charge per Bbl (MCF)
(4 x 2.80)/ 3
Add Ann. Op. Costs (MM $)
dollars)
Oil Wells
1977
252.6
23.8
1296.5
40 - 100
8.8 -21.5 C/B
3.4 - 8.6

Gas Wells
1977
1850.6
305.8
11328.5
5-25
0.13 - 0.63 C/MCF

 7.  Add Op. Costs per Bbl    (MCF)
     (6 x 15) / 3
 8.  Add Dep. Charge per Bbl  (MCF)
     (4/1)  (C/B)
 9.  Add After Tax per Bbl (MCF)
     Op. Cost
     0.5 x (7-3)
10.  Cost  Increase
     (5 + 9)
     (assuming 12% Capital Cost)

11.  Cost  Increase
     (assuming 20% Capital Cost)
 3.9 - 9.9 c/B    0.06 - 0.28  c/MCF
 3.1 - 7.7 C/B    0.04 - 0.22  C/MCF
 0.2 - 0.5 c/B    0.01 - 0.03  c/MCF
9.0 -22.0
                  0.14 - 0.66  c/MCF
12.7 -31.2 C/B    0.19 ~ 0.92  C/MCF
     (1)
        In MMB or MM MCF
 SOURCE:   Arthur D. Little, Inc., estimates
                                        VI-2]

-------
 VI.3.  STATE WATERS: BASE CASE RESULTS FOR OIL WELLS AND GAS WELLS





         The impact of treatment requirements in 1977 and reinjection




 requirements in 1983 in state waters was estimated for offshore Louisiana




 using the computer program described in the previous chapter.   The base




 case parameters used were the same as for the impact analysis  for federal




 waters.




         In the previous chapter it was explained that no data  were available




 on platforms in Louisiana state waters.   Therefore,  it was  assumed that




 production units consisted of clusters of completions reported to be operated




 by one company in the fields, which were considered.   Also  it  was assumed




 that,  if  treatment of produced oil,  gas  and water took place on a platform,




 adequate  space would be available  to accommodate additional treatment equip-




 ment.  If treatment would have to  be done on land, then space  availability




 would  not be a limiting factor.




        Table V-7 indicates that this assumption may have introduced some




 bias towards  large  treatment  facilities,  if  production  units within




 state waters  are distributed  similarly as  in  federal waters.




        Data  on water,  associated  gas and  condensate production were  not




available on  a lease-by-lease basis as for federal waters.  Therefore, averages




had to be used obtained by using gross production data  for the area.




        Based on these gross production data, an oil/water ratio of  .70,




a gas/oil ratio of  .95 MCF associated gas per Bbl of oil, and a condensate/




gas ratio  or .011 Bbl of condensate per MCF of nonassociated gas was  used in  the




analysis.
                                      VI-22

-------
        Table VI-9 and VI-10 shows the results for oil and gas wells in the




state waters respectively.   For oil, these results show that:






        •  With no price increases, total loss in potential  production will amount




           to 6.87 million barrels of oil and 6.53 million MCF of associated gas;




           less than  0.35% of  this  total will be due  to early abandonments in 1977,




           about  7% due to early  abandonments in 1983, and the rest or 92.65%




           will be due to a shortening of the producing life of completions.





        •  Total equipment investment will be $13.5 million in 1977 and




           $37.7 million in 1983 or a total of $51.2 million.





        •  Early abandonments in 1977 will be 2 completions or less than




           0.3% of total producing completions in 1977 and 53 in 1983 or




           about 6.5% of the 1977 total.







        •  All operators will prefer to wait until 1983 before investing in




           reinjection facilities rather than to invest in reinjection




           facilities in 1977.







Table VI-10  shows the results of  gas wells from which it can be concluded




that:




        •  A total of 60.4 million MCF of gas and 0.68 million barrels of




           condensate will be lost, of which 3.1 million MCF or 5.1% will




           be lost due to early abandonments in 1983 and 57.3 million MCF




           or 94.9% due to a decrease in producing lives of completions




           if no price increases are possible.
                                      VI-23

-------
                                       TABLE VI-9
                                   State Waf-rs - Oil
                               Producers Absorb All Costs
Year

 1977
 l97fl
 1979
 1931
 1981
 1982
 I9b3
 19:34
 1985
 1 9 fl 
-------
                                        TABLE VI-10
                                    State Waters - Gas
                                Producers Absorb All Costs
Year
 199-Q
Production Loss
by Platform Shut-
ins in 1977
   (MCF)..
1977
19 7 H
197Q
19BH
1 9 H 1
19Q?
1 9 
199*
1997
~. n '
n .
ri(
n .
n ,
"1 ,
n .
T.
n ,
r ,
T i
p .
n t
<-1 i
n .
> i
P .
n »
n ',
                        n ,
                        n,
Production Loss
by Platform Shut-
ins in 1983
   (MCF)	
                                          U v
                                          n.
                                     L> ? b 0 o 6 .
                                     Jo / R13 .
                                     3i 4 M o n ,
                                     2//094 .
                                      H J5 r
                                           V ' I.
                                           n •
                                           n'.
                                           n.
                                           j i
                                           n.
Production Loss
by decrease in
producing life
  (MCF)    	
                                                             r .
                                                             r .
                                                          16 /4 .-
                                                      P33921P
                                                       ; 2 n '^ •-> V ^
                                                        n7*v
                                                        ,04Q9
 20U?                  .1,
 2003                  -i,                  1,
 2HU4                  i.
 2TQS                  'i.                  M,
 21U^                  T,      '        ,

TOTAL                  n,           }r/'3'>/?.

Total Equipment Investment in 1977:  $5.87 million
Fraction of Investment made in Reinj.  in 1977:   .0000
Total Equipment Investment in 1983:
Platforms Immediately Abandoned:   0
Total Gas Production Foregone:
Total Oil Production Foregone:
Completion Lost Before 1977:  3.
Production Lost Before 1377:  0.31 million MCF
                     1» ^ n w i;
                     I i4S)3/X.
                     1 *) VW / l ,
                     2273619,
                     1 i 'i 6 H 6 7 ,

                     2 7 r-, i 5 o '< .
                                     $16.4 million
                                60.4 million MCF
                                .682 million barrels
                                                                               Completion
                                                                              Abandonment s
                                                                                     0.
                                                                                     u.
                                                                                     0.
                                                                                     u.
                                                                                     0.
                                                                                     'j .
                                                                                     6,
                                                                                     0.
                                                                                     Q.
                                                                                     0.
                                                                                     0 ,
                                                                                     4 .
                                                                                    10-
                                                                        20.
                                                                        ftl.
                                                                        66 .
                                                                        A3.
                                                                         0 .
                                                                        29,
                                                                         0.
                                                                        11.
                                                                         / .
                                                                         *^
                                                                         U *
                                                                        11.
                                                                        lb-
                                                                         0.
                                                  SOURCE:  -Arthur D. Little,ulnc., estimate
                                             VI-25

-------
        •   Investment  in  treatment equipment in 1977 will be $5.87 million




            and  investment in reinjection  facilities in 1983 will be  $16.39




            million  amounting to  a total investment of $22.26 million.




        •   There will  be  no early abandonments in 1977 and not more  than




            6  in 1983 or 1.4% of  completions producing in 1977.









 It appears  that a substantial number  of oil completions will be producing




 close  to the  economic  limit in 1983,  resulting in early abandonment  of  53




 of a total  of 786 still producing in  1982.  Given the fact that these




 completions otherwise  would have been phased out over a period of ten years,




 it can be expected  that the reassignment  of personnel directly involved




 in the production operations of  these wells might pose a problem.  This




 especially  if  the completions  were    part of one company's operations




 rather than being part of several companies' operations.




        In  the  worst case this might  even lead to lay-offs.  Using one man




 for every two completions as a rough,  direct employment indicator about




27 people could be affected by early abandonments of oil completions in



 1983.
                                      VI-26

-------
                                        FIGURE VI-2
                                     "T
                     p In  ri'rp
          t
           '
              	4—
     %_LpsjS_in Jlotentijalj
     Production
                                    t
                                              Changes ^in -H£
                                                    .oss in  Potential' :
                                                 Production
 9-
Chaniges  iii Cost
                      Loss
                      Prod
                            . Capital
                  ia Pojfeeafiia^
                 action
                                  inai^ivity Tests
                                ljOuTSTLSll3~I
                                -Gulf of Mex
Leo ^ — tedera
                                                           ase  p
                                                        iL  (A)
                                                                 rtate
-^
. watc^-s	
                                                                irameters:
                                                        Gas (i
                                           Pfiee!

                                           JBecli
                                                          le.Rat
                                                         i  121.
                                                                Ltal
CH-
               -o
                                                               12%-
                                                    *Notia
                                                       :ed -gai
                                                 501
                                           RCE:
                                         rtnn
                                                                             inc.
                                                                             Iffi tes
            Cc
     st  of
Capita
                                            VI-27

-------
            State Waters;  Sensitivity  Tests by  Changes  in Base Case Parameters.




         Sensitivity tests for state waters were made by changes in the




 following parameters:




         •  Changes in the "wellhead" price for oil, ranging from $5.25 to




            $11.00/bbl and for gas, ranging from $0.30 to $1.00 per MCF.





         •  Changes in the cost of capital, ranging from 12% to 25% for oil as




            well as for gas producers.





         •  Changes in the annual decline rate ranging from 12% to 18% per




            year for oil and 9% to 15% per year for gas.





 The results of these tests are shown in Table VI-12 and Table VI-13 for oil




,5*uKi-gae respectively and the changes in impact in terms of a percentage loss




 in potential production have been graphed as shown in Figure VI-2.




 Table VI-11 summarizes the results of the impact analysis for Louisiana state




 waters presenting the ranges within which the different impacts measured




 are likely to fall as indicated by the results of the sensitivity tests:





         *  The loss in potential production will be between 1.25 to 2.25%




            or 5.2  to 9.4 million barrels of oil and 5.0-9.0 million MCF




            associated gas from oil wells.   For gas wells  the loss will be




            0.3% to 1.5% or 16.4 to 82.4 million MCF and 0.25-0.93 million




            barrels of condensate if no price increases are assumed for oil or gas.




         •  Completion abandonments in 1977 will amount to  between 1  to 2




            of  a total 1213 producing  oil and gas  completions in 1977  and




            to  between 42  and  75 of a  total of  1211 producing oil and  gas




            completions  producing in 1983.




         •   Total investment requirements will  be  between $18.8  and $19.7




           million in 1977 and  between $49.7 and  $56.4 million  in 1983.
                                      VI-28

-------
                                TABLE VI-11
                       Reinjection Required in 1983

                    Range of Likely Impact in Louisiana
                    	State Waters   ^	
                              (1974 dollars)

Oil Wells
Loss in Potential Prod.,    oil       1.25-2.25%          5.2-9.4 MMB
                         ass. gas                           5.0 - 9.0 MM MCF
Completions Abandoned in   1977       less than 0.3%        1-2
                      in   1983       5.0 - 8.4%            40 - 66
Investment Required in     1977                             13.0 - 13.8 MM $
                           1983                             34.5 - 38.9 MM $

Gas Wells
Loss in Potential Prod.,    gas       0.3 - 1.5%            16.4 - 82.4 MM MCF
                        condensate                          0.25 - 0.93 MMB
Completions Abandoned in   1977                             0
                      in   1983       0.5-2.1%            2-9
Investment Required   in   1977                             5.82 - 5.92 MM  $
                           1983                             15.2 - 17.5 MM  $
Total Loss  in Potential Prod.,  oil                           5.45  - 10.33 MMB
                                gas                           21.4  - 91.4 MM MCF
Total Investment Req.  in    1977                             18.8  - 19.7 MM $
                            1983                             49.7  - 56.4 MM $

Total Completions Aban. in  1977                             1-2
                            1983                             42 -  75
   Assuming  producers  absorb  all costs.
 SOURCE;  Arthur I.. Little, Inc., ccii-^
                                       VI-29

-------
                                TABLE Vl-lla
                      No Reinjection Required in 1983
                    Range of Likely Impact in Louisiana
                    	State Waters   	
                              (1974 dollars)
Oil Wells
Loss in Potential Prod.,    oil      0.6-1.1%
Completions Abandoned in
                      in
Investment Required in
1977
1983
1977
1983
                                     less than 0.3%
                                                            2.7-4.4 MMB
                                                            2.6 - 4.2MMMCF
                                                            1-2
                                                            NA

                                                            13.0 - 13.8 MM $
                                                            NA
Gas Wells
Loss in Potential Prod.,    gas      0.16 - 0.8%
                        condensate
Completions Abandoned in   1977
                      in   1983
Investment Required   in   1977
                           1983
Total Loss in Potential Prod., oil
                               &as
Total Investment Req.  in    1977
                            1983
Total Completions Aban. in  1977
                            1983
                                                            9.1  -  42.2  MM MCF
                                                            0.1  -   0.5  MMB

                                                            NA
                                                            5,82 - 5.92 MM $
                                                            NA
                                                            2.8 - 4.9 MMB
                                                            11.7 - 46.4 MM MCF
                                                            18.82 - 19.72 MM $
                                                            NA
                                                            1_2
                                                            NA
   Assuming producers  absorb  all  costs.
SOURCE;  Arthur D. Little,  Inc.,  estimates
                                        VI-30

-------
         To show what difference it would make in terms of potential




loss in production, investment requirements and early abandonments, an




impact analysis for state waters was also done assuming that no reinjec-




tion would be required as of 1983.  The results in Table Vl-lla show




that:




         •  The loss in potential oil and gas production will be




            about half of what will occur when reinjection is




            required in 1983.




         •  Investment requirements in 1977 will be the same, but




            total investment requirements will be about 25% of the




            total required in 1977 and in 1983 if reinjection in




            1983 is required.




         •  Completion abandonments will be negligible.
                                 VI-31

-------
                                     TABLE VI-12
                  Sensitivity of Results to Changes in Key Variables
(1974 dollars)
State waters; reinjection required; oil
Producers Absorb All Costs
% Loss of Total Number of
Varied
Parameter
Price


Decline
Rate

Cost of
Capital

Extra Space
Required
3 Platform
Unit
*Base Case:

Potential
Value Production
Oil Gas
$ 5.25 2.38 2.38
*$ 7.50 1.64 1.64
$ 9.00 1.40 1.40
$11.00 1.33 1.33
12% 1.19 1.19
18% 1.83 1.83
15% 1.64 1.64
20% 1.64 1.64
25% 1-64 1.64
NA
NA
1 Platform Unit
Equipment Technology C
Price
Decline Rate
Cost of Capital
Investment Completions
(in MM$) Abandoned
1977 1983 Total 1977 1983
13.37 35.73 49.10 1 66
13.47 37.74 51.21 2 53
13.47 37.74 51.21 2 53
13.47 38.88 52.35 2 40
13.85 40.24 54.09 2 40
13.09 34.43 47.52 2 66
13.47 37.74 51.21 2 53
13.47 37.74 51.21 2 53
13.47 37.74 51.21 2 53



$7.50
15%/year
12%/year
Number of
Producing
Completions
End 1976
786
788
788
788
788
788
788
788
788




SOURCE:   Arthur D. Little, Inc.,  estimates
                                               VI-32

-------
                                   TABLE VI-13

                  Sensitivity  of  Results  to  Changes  in  Key  Variables
Varied
Parameter
Price


Decline
Rate
Cost of
Capital

Extra Space
Required
3 Platform
Unit
Value
$ 0.30
*$ 0.50
$ 0.75
$ 1.00
9%
15%
15%
20%
25%


(1974 dollars)
State waters; reinjecticn required; gas
Producers Absorb All Costs
% Loss of Total Number of
Potential Investment Completions
Production (in MM?) Abandoned
Gas Oil 1977 1983 Total 1977 1983
1.76 1.76 5.87 15.27 21.14 0 9
1.10 1.10 5.87 16.39 22.26 0 6
0.58 0.58 5.87 17.11 22.98 0 4
0.41 0.41 5.87 17.47 23.05 0 2
0.71 0.70 5.92 17.18 23.10 0 4
1.34 1.34 5.82 15.20 21.02 0 11
1.10 1.10 5.87 16.39 22.26 0 6
1.10 1.10 5.87 16.39 22.26 ° 6
1.10 1.10 5.87 16.39 22.26 0 6
NA
NA
Number of
Producing
Completions
End 1976
425
425
425
425
425
425
425
425
425


*Base Case:   1 Platform Unit
             Equipment Technology C
             Price                   $0.50
             Decline Rate            12%/year
             Cost of Capital         12%/year
 SOURCE:  Arthur D. Little, Inc., estimates
                                           VI-33

-------
         Likely Average Cost Increases for Oil and Gas, State Waters
                                        ~             3


         As explained in Section VI-4, producers might be able to pass on



the additional costs they have to incur to comply with the new water



treatment regulations.



         Therefore, an estimate was made of the average cost increase for



oil and gas which can be expected to result in state waters in 1977 and 1983



and which producers would like to pass on.  For the calculations, it



was assumed that producers would like to recover investment costs includ-



ing a return on that investment and after tax operating costs over a period



of 15 years following the investment.



         The cost increase to be expected will then be the sum of the



average per barrel capital charge and the average per barrel net increase



in operating costs.  These calculations are shown in Table VI-14.  The



results show that oil prices would have to be increased by 11.60 to 16.3c



per barrel in 1977 and by about 77.30 to 107.90 per barrel in 1983 to



allow producers to recover their additional costs.  Gas prices would



have  to be increased by 0.410 to 0.570 per MCF in 1977 and by 2.410 and



3.310 per MCF in 1983.
                               VI-34

-------
                                        TABLE VI-14

                      Likely Average Cost Increase in 1977 and 1983
                                      for Producers in
                                       State'Waters
 1.   Production in
 2.   Production in
 3.   Cum. Productic
 4.   Investment (MM $)
 5.   Cap. Charge (4
 6.   Add. Op. Costs ($/yr)
 7.   Add. Op. Costs
 8.   Add. Dep. Charge (4/3)
 9.   Add After Tax Op. Cost
     0.5 x (7-8)
10.   Cost  Increase
     (Assuming 12% Annual Cap. Change)
11-   Cost  Increase
     (Assuming 20% Annual  Cap. Char
(1974 dollars)


n i
7/1983 v '
\~\ /I QQ7
15 years) (1)

2.8 )/3
Yyr)
i x 15) /3
(4/3)
Oil
1977

66.7
6.3
342.3
13.5
11.0 C/B
1.2
5.2 C/B
3.9 C/B
Wells
1983

25.0
0.8
137.1
35.0
71.5 C/B
3.4
37.2 C/B
25.5 C/B
Gas Wells
1977

689.2
112.6
4228.4
5.8
0.38 C/MCF 2.
0.55
0.20 C/MCF 1.
0.14 C/MCF 0.

1983

320.0
40.2
2051.9
15.5
13 C/MCF
1.82
33 C/MCF
76 C/MCF
 0.6 C/B    5.8 C/B   0.03 C/MCF   0.28 C/MCF
11.6 C/B   77.3 C/B   0.41 C/MCF   2.41 C/MCF
16.3 C/B  107.9 C/B   0.57 C/MCF   3.31 C/MCF
 (1)
    In MMB or MM MCF
  SOURCE;   Arthur D.  Little,  Inc., estimates
                                             VI-35

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VI.4.   ALASKA, RESULTS OF A PRELIMINARY IMPACT ANALYSIS




          The production and treatment economics developed for the Gulf of Mexico




could not be applied to present offshore production in Alaska.




          Industry sources indicated that operating cost levels are three-to-




six-times higher than the operating cost level used for the Gulf of Mexico analysis.




Investment levels can also be expected to be much higher given the harsher climate




under which construction has to take place and longer distances from major supply




centers.




          The most important production statistics for the four oil fields and




one gas field producing in the Cook Inlet are summarized in Table VI-15.  Water




production in each of the four oil producing fields is not sufficient to fulfill




the needs for the pressure maintenance programs by water injection in those fields.




          The seawater which is used for this purpose is chemically incompatible




with the produced formation water, which precludes the use of a mixture of these




types of water  for reinjection purposes.     Therefore, only seawater is used for




reinjection purposes, even though the high solids content of this water necessitates




costly filtering before the water can be injected.  Separation of produced fluids




and water treatment on the platform is limited to free water knockout.  All other




treatment is done onshore by four large water treatment plants, one for each field.




One of these plants is judged by the EPA to be capable of meeting 1977 treatment




standards without any additional investment.  All three others would require




additional equipment or equipment modifications, the economics of which were not




available.If the volumes of  produced  formation water  increase  to  meet  the total




 reinjection requirements by 1983,  the  use  of produced  formation  water  for pressure
 (1)  Information obtained  through discussions with EPA representatives
                                        VI-36

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                                   TABLE VI- 15

                     1973 Statistics on Oil and Gas "Fields

                         Offshore Alaska, Cook Inlet
Field Name
Granite Point
MeArthur River
Middle Ground
  Shoal
Trading Bay
Average Production

Number of
Platforms
3


3


4



3



Number of
Completions
9
7
9
19
23
12
7
10
11
6
8
31
5

Oil
(B/D)
6,139
3,307
3,613
38,650
42,982
24,771
3,350
7,291
11,409
5,681
2,164
15,168
4,105
in 1973
Gas
(MCF/D)
5,368
3,812
3,199
9,614
16,200
7,429
1,512
3,807
5,292
2,182
601
7,637
1,157

Water
(B/D)
14
54
202
4,028
5,689
7,806
202
854
4,488
2,521
1,993
3,917
5,118
Water
Reinjected
Field Total
(in B/D)
26,122


154,463


55,950



35,358


North Cook
 Inlet (Gas)
0   117,011
Source:   "Statistical Report 1973," State of Alaska Department of
          Resources, Division of Oil and Gas.
                                       VI-37

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lintenance might be  the  economically most attractive way  to comply with  the
•injection requirement.   In  *-hat  case,  n/ i  Testment in reinjection  facilities
Ight be necessary  in 1983.   However, if .hi'  is not the case,  then investment
i reinjection facilities f<.,r produced  fo :mation waters would b*-  ler.essary  in
183 either on the  platform itself or onshore  next  to the  existing treatment plants.
   Cost  estimates of these  solutions  were not available.  Therefore,  to indicate
i which range the  impact from new regulations can  reasonably by  expected to fall,
'o cases  were evaluated,  both using estimates of operating and investment  costs
>r treatment and reinjection facilities of  three and six  times the costs used
r the Gulf of Mexico.   The  two cases  differed in  that the fi ••. t case  assumed  the
eatment  and reinjection facilities would be  placed on _ae platforms and the
cond case assumed they  would be  placed onshore near tht  present treatment facilities
   The results of this  preliminary analysis  of the first case are shown on
ble VI-16 and can be summarized  as the following:
    •    If no investment in reinjection facilities would be  required in  1983,
         and assuming that  producers would have to absorb all costs,  then:
            Loss  in potential production would range between  0.8 and  1.9%
            or 2.2  to 5.1 million barrels of oil  and between  0.9 and  2.1%
            or 2.4  to 5.0 million MCF  of associated gas.
         -  No early abandonments would occur in  1977.
         -  Total required  investment  would  range from $12.6  to $25.1 million.
    •    If it is assumed that producers would be able to pass  on all costs
         throupb  ?>  "rice increase, calculated in  the same wav as discussed in
         Sections VI-2.3 and VI-3.3
         -  The required price increase in 1977 in terms of 1974 dollars  would
            be between  14£   per  barrel and 28£    per barrel,  assuming a 12% cost
            of capital  and  between 21c per  barrel and 42<;    per barrel,  assuming
            a 20% cost  of capital.

                                           VI-38

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                                    TABLE VI-!6
                                Alaska, Cook Inlet
                      Preliminary Estimate  of Likely Impact (3)

                               	(1974 dollars)	
1.  Assuming Producers Absorb All Costs
Potential Prod. Oil (MMB)
        Ass. Gas (MM MCF)

Loss in Pot. Prod. (MMB)
                 (MM MCF)

% Loss in Pot. Prod:  Oil
                 Ass. Gas

Early Abandonments, 1977
                    1983

Investment Required, 1977
   (in MM$)          1983
                                No Reinjection Req.
                                3x
                                   (1)
                                          6x
                                             (1)
                                                        Re injection Req.
                                                                           (4)
3x
  (1)
6x
  (1)
280
261
2.2
2.4
0.8
0.9
0
NA
12.6
NA
263
242
5.1
5.0
1.9
2.1
0
NA
25.1
NA
280
261
6.8
7.0
2.4
2.7
0
8 (= 5%)
12.6
35.0
263
242
14.7
16.7
5.6
6.9
0
54 (= 34%)
25.1
54.7
2. Increases  in Average  Cost  per  Unit  Produced

Average Cost  Increase Oil            i-n 0/B
Cost of Capital 12%, 1977
                     1983
Cost of Capital 20%, 1977
                     1983
                                                             in
14
NA
21
NA
28
NA
42
NA
14
46.0
21
167
28
71.0
42
313
(1)
(2)
(3)
(4)
3 x:  Assuming all operating and investment costs are  3 x  as high  as  in the
      Gulf of Mexico.
6 x:  Assuming all operating and investment costs are  6 x  as high  as  in the
      Gulf of Mexico.
Based on a calculation of the per-barrel after tax operating costs plus invest-
ment costs including a return on that investment over  a period of  15  years.
Assuming treatment facilities will be put on each of fourteen oil  production
platforms.
Assuming that reinjection facilities on platforms will be  necessary in
addition to existing injection plants used for pressure maintenance.
  SOURCE;  Arthur D. Little, Inc., estimates

                                           VI-39

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     •    If investment reinjection in facilities would be required in 1983

          and assuming that producers would absorb all costs, then:

          -  Loss in potential production would range between 2,4 and 5.6%

             or 6.8 and 14.7 .Trillion barrels of oil and between 2.7 and 6.9%

             or 7.0 and 16.7 million MCF of associated gas.

          -  Early abandonments in 1983 would be between 8 and 54 or between

             5% and 34% of total producing completions in 1977.

          -  Total investment required would be between $12.6 and $25.1

             million in 1977 and between $35.0 and $54.7 million in 1983.

     •    If it is assumed that producers would be  able  to  pass  on  all  costs  as  price

          increases and that they would calculate these price increases as

          described in Sections VI-2.3  and  VI-3.3,  then:

          -  The required price increase would be 6.3C to 11.4C per barrel

             in 1977 and 46
-------
                                    TABLE VI-17

                                Alaska, Cook Inltt

                      Preliminary Estimates of Likely Impact (3)

                      	
280
261
3.6
4.1
1.3
1.6
0
0
7.7
25.7
6x(1)
•263
242
11.1
12.2
4.2
5.0
0
44.0
15.4
43.1
   3 x:  Assur.ing all operating and investment costs are 3 x as high as  in  the
         Gulf of Mexico.
   6 x:  Assuming all operating and investment costs are 6 x as high as  in  the
         Gulf of Mexico.
m
   Assuming producers pass on the per-barrel after tax operating costs plus  invest-
   m^n.u costs including a return on that investment over a "eriod of 15  yeir?.
(3)
   Assuming treatment and reinjection facilities onshore - one for each  of  four
   oil producing fields.
(4>A
   Assuming reinjection facilities will be  necessary in  addition  to  existing
   injection plants for pressure maintenance purposes.     SOURCE: Arthur D. Little, Inc.
                                           VI-41

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 -  No early abandonments would occur in 1977.




    Total required investment would range from $7.7 to $15.4 million.




 If it is assumed that producers would pass on all costs through a price




 increase, then:




 -  The required price increase in 1977 in terms of 1974 dollars would




    be between 3.8c per barrel and 7.6<: per barrel for a 12% cost of




    capital and 4
-------
VI.5.   CALIFORNIA

        There are 14 producing platforms off of California, nine in state

waters and five in Federal waters.  In addition, there are seven man-made

islands on which wells are producing offshore in state waters. (See Table VI-18).

        All of the produced formation water from offshore facilities on state

and Federal leases is sent ashore for processing and disposal.  The formation

water produced from facilities in Federal waters four to five miles offshore

is piped ashore, treated and returned to the platforms for reinjection.  Of

the nine platforms in state waters, four have their production piped to one

onshore processing facility and the other five to five separate processing

plants.

        Most formation water is reinjected for pressure maintenace.  A small

portion is treated onshore and pumped into the ocean; while accurate data

is not available, the percentage of offshore produced formation water dis-

carded into the ocean has been estimated at 3.9% of total produced brine

in 1974.    The 1974 brine production was 293.3 million barrels.  If the same

percentage tage is applied *    '^"'3, the volume of formation water discarded

is 10.9 million barrels.  In addition to the brine from offshore production,

about 16 million barrels of formation water from onshore wells is discarded into

the ocean.     This is about 2.3% of total onshore water       produced with oil

and gas in the coastal basins.
   Estimate made by Mr. John Hardoin, California Division of Oil and Gas,
   Long Beach.


                                      VI-43

-------
                               TABLE VI-18

                California; Platforms and Offshore Oil,

                       Gas and Watef Production

                              in 1973(1)
                                           State Waters
                                                           Federal Waters
Number of Platforms

Oil production MMB

Associated Gas MM MCF

Non Associated Gas MM MCF

Water Associated MMB with Oil

Water Associated MMB with Gas
9 + 7(2)
70.5
20.9
9.7
266.0
0.5
5
18.8
9.1
0.0
12.2
0.0
(1)
(2)
Source:  "Oil, Gas and Geothermal Production Statistics, 1973."
         Resources Agency of California, Vol. 59, No. 2.

9 Platforms and 7 man-made islands.
                                   VI-44

-------
     California has enacted a brine disposal requirement that is more




restrictive than the proposed Federal effluent guidelines for 1977.




California regulations require water to be discharged in the ocean to be




treated to 20 parts per million (ppm) long-term average of oil and




grease.  The Federal requirements are a 27 ppm long-term average. Unlike




the produced formation water from the Gulf of Mexico, the California




formation water has far lower salinity and is typically less saline than




the sea water.





     The proposed EPA 1977 effluent guidelines do not appear to  impose an




additional burden on California offshore  production.  The California state




requirement resulted in Phillips shutting in  and removing one platform and




Texaco  stopping production on two others  in 1973 when the requirements went




into effect.
                               VI-45

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VI.6.  INFERRED IMPACT. EXISTING SOURCES IN THE GULF OF MEXICO

          The estimates of the total impact in federal and stat^ waters was

based on units already producing in 1974.  It can be expected uhat by 1977

quite a few additional wells will have been drilled.  Therefore, the total

number of, what the EPA considers to be "existing sources,"    will be larger

than the number of production units considered in the earlier analysis.

          To obtain an idea of how much this actual number of  existing

sources  will differ from the number of sources considered, the total  reserves

       (2)
implied    by the analysis was compared with the sum of demonstrated and

                                                          (3)
inferred reserves as defined and estimated by the U.S.G.S.

          The underlying assumption was that demonstrated and

inferred reserves will be produced by wells existing in 1974 and wells to be

drilled until 1977 in federal waters and existing wells plus wells drilled until

1983 in state waters.

          Assuming that the relative number of wells in federal and state

waters would remain the same and assuming that the measured impacts would be

extrapolated on a unit of reserves basis an estimate was made of the

total impact for these existing sources.

          The results of this calculation using the assumptions for the

base case are shown in Table VI- 19 and Table VI-20.
    Source" in this context should be understood to mean point source of
    discharged water.

(2)
   Implied reserves consisted of the total potential production of all com-
   pletions considered.

(3)
   "Geological estimates of undiscovered recoverable oil and gas resources in
    the United States,"  Geological Survey circular 725, 1975.
                                       VI-46

-------
                                      TABLE VI-19
                     Total Inferred Impact for Existing Sources in
                           the Gulf of Mexico as Derived from
                                   the Measured Impact
Gulf of Mexico, Oil Wells
   Federal, measured impact
   Implied reserves
   State, measured  impact
   Implied reserves
Producers Absorb All
(1974 dollars)
Recoverable
Reserves
Oil Gas
MMB MM MCF
Costs
Potential
Prod. Lost
Oil Gas
MMB MM MCF
Required
Invest-
ment
MM $
                                   1590
                                    419
3600
 398
   Total measured impact
   Total implied res.
                         (2)&(4)
                                   2233
   U.S.G.S. reserves    ^~'4612
   Inferred total impact (lx(3:2)) =
Gulf of Mexico, Gas Wells
   Federal, measured impact
   Implied reserves                 162
   State, measured impact
   Implied reserves                  62
   Total measured impact
   Total implied res.
   U.S.G.S. reserves('2)&('4')
   Inferred total impact  (5x(7  :6)) =
   Total Gulf of Mexico (4+8) =
                                             14743

                                              5471

                                             24212
                                            102834
                                                      14.0
                                                       6.9
                                                      20.9
                  40.3
                   6.5
                  46.8
 63.9
 51.2
115.1
43.2
1.1
0.7
1.8
7.6
50.8
96.6
75.4
60.4
135.4
575.1
671.7
237.7
23.5
22.3
45.8
194.5
432.3
 (1)
 (2)

 (3)
 (4)
   Including condensate produced with nonassociated gas.
   Source:  "Geological estimates of undiscovered recoverable oil and  gas  resources
             in the United States,"  Geological Survey circular  725, 1975.
   Including associated and dissolved gas to be produced with oil.
   Including Demonstrated and Inferred Reserves.

    SOURCE:  Arthur D. Little, Inc., estimates
                                           VI-47

-------
                                          TABLE  VI-20

                            Total Inferred Impact  for New Sources in
                            	the Gulf  of MeyLco	
                                  Producers Absorb All Costs
                                         (1974 dollars)
 I
 2
Gulf of Mexico, Oil Wells
   Federal, measured impact
   Implied reserves
                   (2)
      Undiscovered
      Recoverable resources
Recoverable
Reserves
Oil
MMB
Gas
MM MCF
Potential
Prod. Lost
Oil
MMB
Gas
MM MCF
Required
Invest-
ment
MM $
1752
                                 3000-8000
                   14.0
40.3
63.9
_4     Inferred impact   (1 x  (3:2)) =
   Gulf of Mexico, Gas Wells
_5     Federal, measured
      Implied reserves
                       (3)
                                          18,343
                                                    24.0-64.  69.-184  109.-292.
                                                      1.1
                             75.4
           23.5
8
   Undiscovered
   Recoverable resources

   Inferred impact   (5 x (7:6))  =
   Total  inferred impact (4 + 8)
                                          18.000-91,000
                  1.1-5.5   75.4-374.  23.5-116.6
                25.1-69.5  144.4-558.  132.5-408.6
   (1)
   (2)

   (3)
   Including  condensate  produced with nonassociated gas.
   Source:  "Geological  estimates of  undiscovered recoverable oil and gas resources
             in  the United  States,"   Geological Survey circular 725,  1975.
      Including associated and dissolved gas to be produced with oil.
    SOURCE: Arthur D. Little, Inc., estimates
                                                VI-48

-------
          According to these results, loss in potential oil production,




including lease condensate, will be 50.8 million bbls and loss in potential gas




production, including associated gas, will be 671.7 million MCF; total invest-




ment requirements in 1977 and 1983 will amount to $432.2 million.




          Given the gross assumptions which were made in deriving these




numbers, they should be regarded to be no more than a very rough estimate,




which might be off by as much as a hundred percent.
                                       VT-iq

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VI.7.  INFERRED IMPACT, NEW SOURCES IL THE GULF OF MEXICO

          The  earlier  sections  of  thxs  chapter have presented estimates

of foregone production from wells existing in 1974 and  the i equired  invest-

ments  in  treatment  and reinjection facilities for these wells  resulting

from the  application  of the effluent limitations guidelines.   As  explained

in Chapter III, the EPA is also proposing a New Source  Performance Standard

(NSPS) guideline  applicable to all new wells in both  state and Federal

waters which  is identical in its  requirements to the  1985 guidelines for wells

which were already  producing prior to  1977 except the:*-  it becomes applicable

in 1977.  This implies that     new wells in state waters as of 1977   will

oe required to reinject all produced formation water  and new wells in federal

waters must comply with the BATEA/NSPS requirements in 1977.



         A rough worst case estimate can be made of the foregone  production

resulting from the  application of  the NSPS requirements to wells  beginning

production in 1977  and thereafter. The majority of these new  wells  are

expected to be in federal waters,  not state waters.  To simplify  the

estimating process, which is crude  at best, the assumption has  been  made

that all new wells after 1977 will be in federal waters, which  implies that

there will be no reinjection requirement for these wells.

         The U.S.  Geological Survey has published estimates of  the total

recoverable resources  from the U.S. given existing production  technology.
^  "Geological estimates of undiscovered recoverable oil and gas resources
   in the United States" Geological Survey Circular 725, 1975.
                                   VI- 50

-------
Table VI-21 lists the resource estimates for the offshore areas.   The




estimates can be regarded as an approximate estimate of the total life-




time production from all new offshore oil and gas wells in the future.




As production technology and the relative cost of other energy sources




change in the future the volumes of oil and gas which may ultimately




be produced from U.S. offshore wells can also change.  However, the U.S.




G.S. resource estimates at least provide one basis from which the long




term production losses resulting from the proposed regulations can be




estimated.




         The earlier analysis of potential production losses from the




application of BPCTCA and BATEA requirements to wells in federal waters




which were producing in 1974 showed that 0.5% to 1.0% of their remaining




lifetime oil production and 0.2% to 0.75% of their remaining lifetime




production of gas would be lost if prices could not be increased to




recover the pollution control costs.  Table VI-20 lists the projected




 production losses if these percentages are applied  to the U.S.G.S.




 resource values.




          Using this estimating proceedure as demonstrated in Table VI-19




 for new sources in the Gulf of Mexico, the projected loss in potential




 production is 25 to 70 million barrels of oil and 144 to 558 million




 MCF of gas.   These losses would be stratched out over the entire period




 of offshore U.S.  production beyond 1977.   Most  of the potential  losses




 would not occur until after the year 2000.




        The estimate of total investment  was made in a  similar way  as




demonstrated in Table VI-20.  First, investment  required  for future  oil
                                   VI-  51

-------
                                        TABLE  VI-21


                         Total Inferred Impact for New Sources

                         	Offshore U.S.A.(1)	

                                    (1974 dollars)
                               Producers Absorb  All  Costs
                                                 ( .   Potential .
                                  Rec. Resourcesv '   Prod. Lost^ )   Required^ '
                                    Oil      Gas      Oil      Gas    Investment
                                  Billion  Billion  Billion  Billion  Billion
                                    Bis      MCF      Bis      MCF       $	


Gulf of Mexico                   5.4-8.0  18.0-91.0  .03-.07 .i.<\-.56  .13-.41

Alaska                           3.0-31.0  8.0-80.0  .03-.25 .10-1.04 .12-1.35

Atlantic Coast                   2.0-4.0   5.-14.0   .02-.03 .06-.15  .08-.16

Pacific Coast                    2.0-5.0   2.0-6.0   .01-.07 .05-.14  .08-.19


Total                                                .08-.35 .30-1.75 .33-1.92

                                                     .11-.38 .65-1.89 .53-2.12
   Based on base case results for the impact analysis for old sources .and as such
   presenting a lower limit for the estimated impact for new sources.

   Source:
   "Geological Estimates of Undiscovered Recoverable Oil and Gas Resources
    in the  United States,"  Geological Survey circular 725,  1975.
   The  low and high  estimates have been made at the  95% and  5%  confidence  levels
   respectively.
   Source:  Arthur D. Little, Inc. calculations based on U.S.G.S. estimates  of
            recoverable resource.

(3)
   Expected to occur over a period of about 50 years starting between 1990 and 2000.

(4)
   Expected to be required over a period of at least 25 years following 1977.


SOURCE;  Arthur  D. Little,  Inc., estimates
                                           VI- 52

-------
and gas producing wells in each area considered was estimated multiplying




the estimated investment requirement per unit of estimated remaining




reserves in 1977 for wells producing in 1974 by the total estimates of




total recoverable oil and gas resources respectively.  The total invest-




ment requirement shown in Table VT-21 was     obtained by summing these




estimates obtained for oil and gas resources.




         In addition to the uncertainty about the resource values them-




selves, there are several potential errors from simply multiplying the




percentage loss from 1974 wells times the resource estimates.  The




percentages are the portion of the remaining life after 1977 of the




wells existing in 1974.




         All of these wells have been producing prior to 1974.  This




implies that the estimated percentage loss of remaining production in




1977 is considerably higher than it would have been if this percentage




would have been calculated using the total lifetime production of these




wells.




         As a result, the estimated loss in potential production for




new wells, which has ..  .  derived by multiplying this percentage




obtained for 1974 wells with the estimated total lifetime production




for new wells (i.e. estimated total recoverable resources), should be




too high.




         For the same reasons the investment estimates for new sources




derived by using investment requirements per unit of potential production




of wells producing in 1974 might be too high.




         On the other hand, this upward bias in estimated loss in potential




production may be mitigated by the fact that much of the new production
                                  VI-53

-------
will be from wells in areas with higher production costs such as Alaska




and the Atlantic.  It can be expected that the cost of compliance per




well or unit of production in these areas will be higher than was




assumed in the Gulf of Mexico  analysis which will result in higher




losses of potential production.




         The relative weight of these opposing biases is not known.




However, they do suggest the approximate nature of the estimates.
                                   VI-54

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VI.8.  DIRECT ENERGY EFFECTIVENESS OF TREATMENT EQUIPMENT






     The following analysis has assumed that EPA1s estimate that a




long-term average of 27 ppm of effluent hydrocarbon concentration is




achievable    with the application of the BPCTCA regulation.  See




Chapter III for a discussion of the analysis behind the assumptions.




     The average hydrocarbon influent concentration of all units




considered by Brown & Root  was 196 ppm.  Based on this information,




an average of 169 ppm (mg oil per liter of water treated) to be




recovered by treatment of produced formation waters will be used in




this analysis of the direct energy effectiveness of treatment equipment.




     This 169 ppm of recoverable crude oil corresponds with 2.02 bbl




of oil recovered per 10,000 bbls of water treated.
 Jrown & Root report, page IV-8.
                                 VI-55

-------
          Figure  VI-3 taken from the B-own. & Root report shows the horse-

powers required as  a function of treatment capacity for treatment by flotation

and treatment by coalescence, respectively.  Based on these graphs, the

horsepower requirements for flotation equipment used in the following analysis

will be 1 HP/344 barrels water treated.  Treatment by gravity separation using

pits or tanks has a negligible energy requirement.
                                                                       _c
          To inject 1 bbl/day of water at 1 psi pump pressure, 1.7 x 10  HP

pump power is required.

          Assuming  that 80% of the total installed pump capacity will be used,

one will need 2.125 10   HP installed pump capacity for each barrel of water

reinjected at a discharge pressure of 1 psi.

          Assuming  a 3000 foot deep reinjection well and knowing that the

overburden pressure decreased by the hydrostatic is about 0.5 psi/foot, we know

that the maximum discharge pressure cannot exceed 1500 psi.  Using 1300 psi as the

maximum injection pressure at the pump (1300 x 2.125 10~ ) or .0276 HP will

have to be installed for each daily barrel of water to be reinjected.

          A daily volume of 1000 barrels per day will thus require 27.6 HP of

installed pump power.

          One HP delivered during one day is equivalent to .061 MCF of natural

gas or to .0101 barrels of diesel oil. '

          Assuming  a conversion efficiency of 20%, 5 x .061 = .305 MCF/day

natural gas or 5 x  .0101 =* .0505 bbls/day diesel oil will be required for each

HP-day.
  'Approximately:   1 bbl diesel oil   =     6000 Btu
                    1 bbl crude oil    =     5850 Btu
                    1 MCF natural gas  =     1000 Btu
                                        VI-56

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                         FIGURE  VI-3

                       POWER REQUIREMENTS
                   FOR BRINE TREATMENT  SYSTEMS
         120
         100
          80
 LU
 I-H  
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          Direct energy effectiveness, a- used here, is the ra~,- > of number




of barrels of crude oil recovered "by treatment over number of barrels of diesel




ril equivalent required by the treatment  (and reinjection) equipment.




          Using these values it is estimated that by treatment with flotation




units, on the average, 1 barrel of diesel oil equivalent will have to be




consumed for treatment of 6850 barrels of water to recover 1.4 barrels of crude




oil.




          When treated formation waters are reinjected, then only .13 barrels




of crude oil will be recovered for each barrel of diesel oil required for




treatment plus reinjection of 719 barrels of water.




          In terms of natural gas the requirement would be for 1 MCF natural




gas to recover 0.23 barrel of crude oil from 1141 barrels of treated formation




water.  However, 1 MCF natural gas will only treat and reinject 120 barrels of




formation water from which .022 barrels of crude oil will be recovered.




          This analysis estimates the total energy recovery from the BPCTCA




treatment system.  The analysis is not intended to represent the incremental




energy recovery from the application of the BPCTCA guidelines.   The platforms




in federal waters presently are under a 50 ppm long-term average requirement




of the USGS.  Thus, the incremental oil recovery resulting from compliance




with the BPCTCA requirement is 23 ppm per barrel of formation water treated.
                                       VI-58

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VI.9.  ECONOMIC COST PER BARREL RECOVERED

          Given the fact, shown in the previous section, that on the average

the treatment equipment expected to be installed in 1977 will recover more

energy than it consumes, it was of interest to consider the economic cost

of the average additional barrel recovered by the BPCTCA facilities.(See Table VI-22

and Table VI- 23.)  For the calculation of this economic cost it was assumed

that producers would expect to recover their investment plus a return on

that investment over a period of 15 years in addition to net after tax operating

costs incurred for the treatment equipment during that same period.

          An estimate of maximum and minimum number of barrels of oil

recovered during the 15 years considered was made.

          The minimum estimate was based on the average water/oil and water/gas

ratio in 1974 of all platforms considered, assuming that this ratio would not

increase during the next 18 years.

          The maximum estimate was obtained assuming that platforms would

produce the maximum amount of water considered to be possible based on the

engineering considerations and analysis of actual water/oil and water/gas

ratios as discussed in the previous chapter.

          Minimum and maximum amount of oil recovered was calculated using the

average recovery factor of 2 barrels of oil per 10,000 barrels of water

treated as derived in the previous section.

          Using investment and operating cost estimates developed in previous

sections, the capital charge and total increase in after tax operating costs
   Economic cost is supposed to mean the average cost per barrel recovered
   allowing for the additional operating and investment costs which have to
   be incurred for recovery equipment.
                                      VI-59

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for the 15-year period could be calculated.  The sum  of these  two cost




items divided by the total number of barrels recovered during the 15 years




resulted in the estimate of minimum and maximum economic cost per barrel of




oil recovered (See Table VI-22  and Table VI-23  ). The results show that:




     •    For federal waters the economic cost per barrel recovered by




          treatment of produced formation water will range from $94 to $2382




          for oil producing units and from $42 to $4511 for gas producing




          units.




     •    For state waters the economic cost per barrel recovered will




          range from $36 to $123 7 for oil producing units and from $133 to




          $2984 for gas producing units.









Reinjection is not really part of the treatment installation but it could be




argued that the barrels of oil recovered by treatment should also pay for the




additional costs incurred for reinjection in state waters starting in 1983.




Therefore, the economic cost per barrel recovered was also calculated for




reinjection facilities, which may be required in 1983.  The range of $371 to




$8321 for oil producing facilities and $808 to $17741 for gas producing




facilities (see Table VI-19) derived as the economic cost per barrel of oil




recovered for treatment and reinjection installations, shows that the




reinjection requirement increases the economic cost by about a factor of nine.
                                       VI-60

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                                        TABLE VI - 22
                         Economic Cost per Barrel of Oil Recovered
Federal Waters
(1974 Dollars)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Cumulative Production (15 yrs . ) (MMB/MM
(a)
Minimum Water Production (MMB)
Minimum Oil Recovered (MB)
Maximum Water Production (MMB)
Maximum Oil Recovered (MB)
Investment (MM$)
Capital Charge (6x 2.8)(MM$)
Added Op. Costs (15 yrs.)(MM$)
Added Dep. Charge (15 yrs.)(MM$)
Net Increase in Op. Cost (8-9) (MM$)
Oil
1977
MCF)1296.5
648.3
129.7
6555.9
1311.0
40
112.0
51
40
11
Wells
1983
N/A
- 100
- 280
- 129
- 100
- 29
Gas
1977
11328.5
85.0
17.0
1891.9
378.4
5
14.0
6.8
5
1.8
Wells
1983
N/A
- 25
- 70
-31.7
- 25
- 6.7
11.  Minimum EC. Cost per Bbl Recovered
      ((741Q)/5)($/B)

12.  Maximum EC. Cost per Bbl Recovered
      ((7+10)/3)($/B)

13.  EC. Cost Range ($/B Recovered)
                                             94


                                           2382

                                             94  - 2382
  42


4511

  42  - 4511
 (a)

 (b)
Assuming 0.5 Bbl water per Bbl of oil and  .0075 Bbl water per MCF  gas  in 1977,

Assuming (oil prod. + water prod./.7) = constant and  .167 Bbl water per
gas in 1977.
     SOURCE:  Arthur D. Little, Inc., estimates
                                           VI-61

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 • v,i, -4' -f •>'*"• 'J '•'*-'' ••
                                       TABLE VI -23

                         Economic Cost per Barrel of Oil Recovered
                                       State Waters
                                      (1974 Dollars)
                                                  Oil Wells
                                                                  Gas Wells
 1.   Cumulative Production (15 yrs.)
       (MMB or MM MCF)
            (a)
 2.   Minimum    Water Production (MMB)

 3.   Minimum Oil Recovered (MB)

 4,   Maximum    Water Production (MMB)

 5.   Maximum Oil Recovered (MB)

 6.   Investment (MM$)

 7.   Capital Charge (6x 2.80)  (MM$)

 8.   Added Op. Costs (15 yrs.)(MM$)

 9.   Added Dep. Charge (15 yrs.)(MM$)

LO.   Net Increase in Op. Costs
       0.5 x (8-9) (MM$)

-1.   EC.  Cost per Bbl Recovered ($/B)
1977
342.3
171.2
34.2
5882.0
1176
13.5
37.8
18
13.5
1983
137.1
68.6
13.7
1537.0
307
35
98
51
35
1977
4228.4
31.7
6.3
706.0
141
5.8
16.3
8.3
5.8
1983
2051.9
15.4
3.1
342.0
68
15.5
43.5
27
15.5
                                              4.5      16         2.5       11.5

                                        36 - 1237   371 - 8321 133 - 2984  808 - 17741
 (a)
 (b)
Assuming 0.5 Bbl water per Bbl  of  oil and .0075 Bbl water per MCF gas in 1977.

Assuming (oil prod. + water  prod./.7) = constant and .167 Bbl water per Bbl MCF
gas in 1977.
      SOURCE;  Arthur  D.  Little,  Inc.,  estimates
                                                     VI-62

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