EPA-230/l-75-063(B)
DECEMBER 1976
             ECONOMIC ANALYSIS
         OF  PROPOSED AND INTERIM
        FINAL EFFLUENT  GUIDELINES
                      FOR
      THE ONSHORE OIL PRODUCING  INDUSTRY
                     QUANTITY

      U.S. ENVIRONMENTAL PROTECTION AGENCY
             Office of Analysis and Evaluation
          Office of Water and Hazardous Materials
                Washington, B.C. 20460
                     USB
     Ul
     (3
\

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              ECONOMIC ANALYSIS

                      OF

PROPOSED AND INTERIM FINAL EFFLUENT  GUIDELINES

                     FOR

      THE ONSHORE OIL PRODUCING  INDUSTRY

             (non-stripper wells)



                  report  to



     U.S. Environmental Protection Agency

      Office of Analysis  and  Evaluation

   Office of Water and Hazardous Materials

           Washington, D.C.    20460
           Partial Fulfillment  of
           Contract No.  68-01-1541
                   Task  20
               December 1976
           U.S. Environniontn! Protection Agency
           Rcg-on V. L''h-.;:y
           230 South  Dearborn  Street ^x"'
           Chicago, Illinois  60604 --"        ;,-&

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                          TABLE OF CONTENTS
List of Tables
List of Figures
                                                                      Page
  I.  EXECUTIVE SUMMARY                                               1-1
      1.  Scope of Work                                               1-1
      2.  Summary of Conclusions                                      1-3
 II.  CHARACTERIZATION OF THE ONSHORE OIL EXTRACTION INDUSTRY        II-l
      1.  Oil and Gas Supply/Demand                                  II-l
      2.  Characteristics of the Onshore Oil and Gas Producing       11-14
          Companies
      3.  Oil Pricing                                                11-18
      4.  Financial Characteristics                                  11-31
III.  PROPOSED EFFLUENT LIMITATIONS                                  III-l
      1.  Interim Final Limitations                                  III-l
      2.  Current State Regulations                                  III-2
      3.  Cost of Pollution Abatement Systems                        III-ll
 IV.  ECONOMIC IMPACT ASSESSMENT METHODOLOGY                          IV-1
      1.  Scope of the Analysis                                       IV-1
      2.  Model of Producer Decision Making                           IV-2
      3.  Analysis of Production Data                                 IV-5
      4.  Analysis of Selected States                                 IV-13
  V.  CHARACTERIZATION OF AFFECTED PRODUCTION                          V-l
      1.  Production Profiles                                          V-l
      2.  Production Cost Models                                       V-14
 VI.  ECONOMIC IMPACTS                                                VI-1
      1.  Summary                                                     VI-1
      2.  Base Case Results for Selected States                       VI-5
      3.  Sensitivity Tests and Range of Impacts                      VI-9
VII.  LIMITS OF THE ANALYSIS                                         VII-1
      1.  Data Limitations                                           VII-1
      2.  Methodology Limitations                                    VII-2

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                            LIST OF TABLES

No.                                                                   Page


1-1       Characterization of Affected Production                      1-2

1-2       Estimated Well Closures and Production Losses                1-4

1-3       Estimated Cost of Compliance with Reinjection Requirement    1-5


II-l      U.S. Energy Demand by Primary Source - 1970-72, 1974,       II-2
          1975, 1976

II-2      Supply/Demand of Crude Oil                                  II-4

II-3      U.S. Energy Demand by Primary Source - 1985                 II-6

II-4      U.S. Crude Oil Production - 1974 to 1985                    II-9

II-5      Potential Rates of U.S. Oil Production                      11-10

II-6      U.S. Natural Gas Supplies, 1972-1985                        11-11

II-7      Comparison of Participation in Various Aspects of the       11-15
          Petroleum Industry for the Nine Largest Oil Companies

II-8      Market Share of Eight Largest Producers                     11-16

II-9      Market Share of Smallest Producers                          11-17

11-10     Representative Posted Prices and Actual Costs Per Barrel    11-21
          of Foreign Equity Crudes and U.S. Crude

11-11     Historical Posted Crude Oil Prices                          11-23

11-12     Delivered Prices of Foreign and Average Mix Domestic Crude  11-24

11-13     Delivered Price of Foreign and Decontrolled Domestic Crude  11-25

11-14     FEA  Projections of Ceiling Prices for Lower and Upper Tier  11-29
          Oil  Production, February 1976 - May 1979

11-15     Capital Needs of the Oil and Gas Industry, 1975-1990        11-33

11-16     Geographical Breakdown of Capital Expenditures              11-34

11-17     Estimated Capital and Exploration Expenditures              11-36

11-18     Exploration and Development Expenditures  in the U.S.:       11-37
          1973 and 1974

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                       LIST OF TABLES (Continued)

 No.                                                                    Page


 11-19     Estimated Capital and Exploration Expenditures of U.S.      11-38
           Oil Industry

 11-20     Typical Yearly Capital Expenditures of Segments of the      11-39
           Oil Industry in the U.S.

 11-21     Cash Flow of Chase Group                                     11-40

 11-22     Sources and Uses of Working Capital, 1974                   11-42

 11-23     Income Statement of the Chase Group                         11-43

 11-24     Balance Sheet of the Chase Group                            11-47

 11-25     Petroleum Industry Capitalization, 1975                     11-49

 11-26     Calculation of Cost of Capital                              11-54

 11-27     Oil Stock Prices                                            11-55


III-l      State Brine Disposal Practices                              III-3

III-2      Summary of State Regulations                             III-4 - 111-10

III-3      Capital Costs for Disposal of Oil Field Effluent            111-12

III-4      Operating Costs for Disposal of Oil Field Effluent          111-13


 IV-1      Sample State                                              IV-7 - IV-8

 IV-2      EPA Formation Water Disposal Analysis, Reinjection,          IV-10
           Non-Stripper, Sample State, Cash Flow Table for
           Ex Ante Case

 IV-3      EPA Formation Water Disposal Analysis, Reinjection,          IV-11
           Non-Stripper, Sample State, Cash Flow Table for Ex
           Post Case, Additional Investment in Year 26

 IV-4      EPA Formation Water Disposal Analysis, Reinjection,          IV-14
           State Wyoming

 IV-5      EPA Formation Water Disposal Analysis, Reinjection,          IV-16
           Non-Stripper, State Wyoming, Production Lost After
           Regulation by Category

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                       LIST OF TABLES (Continued)

 No.                                                                    Page
 IV-6      EPA Formation Water Disposal Analysis,  Reinjection,          IV-18
           Non-Stripper, State Wyoming, Results  of Impact  Analysis


 V-l       U.S.  Oil Production by State                                 V-2

 V-2       Texas,  Louisiana,  and Wyoming Oil Production -  1975           V-3

 V-3       Productivity of  Onshore Wells in Texas, Louisiana, and       V-4
           Wyoming - 1975

 V-4       Reinjection in Texas, Louisiana, and  Wyoming (Onshore)       V-5

 V-5       EPA Formation Water Disposal Analysis,  Reinjection,           V-7
           State Wyoming

 V-6       EPA Formation Water Disposal Analysis,  Reinjection,           V-8
           State Louisiana, Onshore

 V-7       EPA Formation Water Disposal Analysis,  Reinjection,           V-9
           State Louisiana, Offshore

 V-8       EPA Formation Water Disposal Analysis,  Reinjection,           V-10
           State Texas, Land

 V-9       EPA Formation Water Disposal Analysis,  Reinjection,           V-ll
           State Texas, Offshore

 V-10      Potentially Impacted Production                              V-12

 V-ll      Potential Production of Impacted Wells                        V-13

 V-12      Capital and Operating Costs for 10-Well Leases                V-16

 V-13      Oil Price and Tax Assumptions                                V-17


VI-1       Productive Capacity, API Proven Reserves and Number  of       VI-2
           Onshore, Non-Stripper Wells Covered by  the Impact Analysis

VI-2       Summary of Results, Range of Likely Impacts for Selected     VI-4
           States

VI-3       Estimated Well Closures and Production  Losses                VI-6

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                        LIST OF TABLES (Continued)

 No.                                                                    Page


 VI-4       Estimated Cost of Compliance with Reinjection and           VI-7
            Treatment Requirements

 VI-5       Cost of Compliance If Producers Pass On Costs               VI-8

 VI-6       Summary of Sensitivity Tests for Selected States:           VI-10
            Changes in Decline Rate

 VI-7       Summary of Sensitivity Tests for Selected States:           VI-11
            Base Case, High Price, High Cost of Capital


VII-1       Percent of Non-Complying Wells Which Are Subeconomical      VII-4
            According to Production Model
                              LIST OF FIGURES


II-l        1977 U.S. Petroleum Supply and Demand Functions             11-13

IV-1        Computer Flow Diagram                                       IV-6

IV-2        Computer Flow Diagram                                       IV-15

VI-1        Reinjection Requirement:  Sensitivity Tests                 VI-12

VI-2        Alternative Requirement:  Sensitivity Tests                 VI-13

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                          I.  EXECUTIVE SUMMARY






1.   Scope of Work




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




final effluent guidelines for the 1977 Best Practicable Technology Currently




Available (BPT) and the 1983 Best Available Technology (BAT)  for onshore




oil production from wells with an average production greater than ten




barrels per day.  An economic impact analysis of the guidelines was per-




formed by Arthur D. Little, Inc. (ADL), under contract with the EPA and




is reported here.




     The economic impact analysis estimated the number of wells




in Louisiana, Texas and Wyoming which would be shut  in rather than brought




into compliance, the investment required by the operators to come into




compliance, the volume of oil production foregone as a result of the guide-




lines, and the average increase in the cost of oil production.




     The characterization of the oil well populations in the impact states




and the costs of compliance were developed by Jacobs Engineering, Inc.,




under another contract with EPA.




     Significant volumes of salt water are produced along with oil from




oil wells.  The water associated with most U.S. onshore oil production is




pumped back into the ground in a reinjection well.  However,  large volumes




of produced formation water from perhaps 25% of the wells are discharged



to surface waters.  Table 1-1 lists the number of wells and production by state.




     The impacts of the proposed guidelines were examined in Wyoming, Texas




and Louisiana.  Texas and Louisiana production is divided into platform




and on-land wells.  A small number of platforms in estuaries and bays




are classified as onshore.  In Wyoming much of the currently discharged




water is of comparatively low salt content and is used for watering live-




stock.





                                  1-1

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                                              TABLE  1-1
Louisiana
  on land
  on platform
Texas
  on land
  on platform
Wyoming

  Total
}
CHARACTERIZATION OF AFFECTED PRODUCTION
Total
Number
of Wells
a
per State
15,829
71,226
6,821
93,876
Number of
Potentially
Impacted Wells
715
1,033
1,108
456
1,594
4,906
Total State
1975 Oil
Production
(bbl's/day)
V 773,189
!• 3,000,362
130,836
3,904,387
Potentially
Impacted
Production
(bbl's/day)
64,513
156,394
82,761
10,027
89,853
403,548
a.  Includes non-stripper, on-land wells and all "onshore" wells producing to platforms.
    Table V-l for total state production statistics.
                                                                      See
SOURCE:  Petroleum Statement,  March 1976,  U.S.  Bureau of Mines;  Jacobs Engineering

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     Texas, Louisiana, and Wyoming contain 42% of the onshore U.S. wells in




1975 producing more than ten barrels per day, including those in coastal areas




producing to platforms.  These states have 71% of the crude production from




onshore wells producing more than ten barrels per day.




     The three impact states may have as many as 24,000 wells whose formation




water is not currently reinjecting, including stripper wells.  These wells may




be 70% of the currently non-reinjecting wells in the 17 largest oil-producing




states, excluding Illinois, which has predominantly stripper wells.  Their




non-stripper production whose brine is not currently reinjected is estimated




to be 72% of the total U.S. onshore/non-stripper production whose brine is not




reinjected.




2.   Summary of Conclusions




     The impact of a requirement that formation water from wells producing more




than ten barrels per day be reinjected into the ground appears to be small in




Texas, Louisiana, and Wyoming.  The primary results of the impact analysis




shown on Tables 1-2 and 1-3 can be summarized as follows.




     •  A requirement to reinject formation water from existing near-shore




        platforms would result in the closure of about 2% of the Louisiana




        platforms and 64% of the Texas platforms.  An effluent treatment




        rather than a reinjection requirement would substantially reduce the




        number of well closures.




     t  The reinjection requirement is not expected to close any on-land, non-




        stripper wells in Louisiana and Texas, but could close as many as 144




        wells in Wyoming.
                                    1-3

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                                               TABLE 1-2
Louisiana
  on land
  on platforms
Texas
  on land
  on platforms
Wyoming

  Total
ESTIMATED WELL CLOSURES
Number
of Wells
Closed3
0
21
0
291
144
Percent
of Impacted
Wells Closed3
0%
2
0
64
9
AND PRODUCTION
Wells
Closed as a
Percent of All
Wells Covered
by Regulation
0%
0.1
0
0.4
2.1
LOSSES
Production
Foregone
(MM bbl's)
1.1
6.0
1.9
11.1
11.4
Foregone
Production
As a Percent
of Potential
Production by ,
Impacted Wells
0.4%
0.9
0.5
27
3.0
Foregone
Production
As a Percent
of Total
State API
c
Reserves
0.03%
0.2
0.02
0.1
1.3
456
0.5%
31.5
                                                                                        l.i
                                                                                 0.2%
a.  Wells closed rather than brought into compliance with a reinjection requirement.
b.  Production lost by immediate well closures plus shorter well life due to higher operating costs.
c.  Offshore reserves included.
d.  The effluent treatment requirement would close an estimated 2 and 110 wells on Louisiana and Texas
    platforms respectively.
SOURCE:  Arthur D. Little, Inc.

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The investment required to install reinjection equipment in the three




states, including platforms, is $80 million.  It is estimated that the




total U.S. requirement is roughly $110 million.  This level of invest-




ment spread over several years is modest compared to $3-5 billion




projected as yearly capital expenditures by the industry on onshore




oil and gas production.




The reinjection requirement would result in approximately 32 million




barrels of foregone production in the three states as a result of well




closures in 1977 and shorter well lives as a result of higher operating




costs.  The foregone production is 1.8% of the projected remaining life-




time production of the impacted wells, assuming a 12% decline rate and




current price regulations.  The total is 0.2% of 1975 API proven reserve




estimates for the three states.




The average increase in production costs for the three states would




be $.34 per barrel of affected oil as a result of the reinjection




requirement.  Operating costs would increase by about $.06 per barrel.
                                1-6

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       II.   CHARACTERIZATION OF THE ONSHORE OIL EXTRACTION INDUSTRY






1.    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-l lists the components of U.S.




energy demand for 1970, 1972, 1974, 1975 and 1976.  Oil was the primary




source of 46.5% of energy consumed in 1976.  Natural gas accounted for




27%.  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 consumption 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




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 forms.
                                  II-l

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                                                         TABLE II-l
M
I
U.S. ENERGY DEMAND BY PRIMARY SOURCE - 1970-72, 1974, 1975, 1976
Energy Form
Oil (quadrillion Btu/yr)

Gas

Coal

Nuclear

Hydro

1976 1975 1974
34.4 32.8 33.5
(46.5%)
20. 20.6 22.2
(27%)
13.8 13.2 13.2
(18%)
2.6 1.8 1.2
(3.5%)
3.2 3.1 3.1
(4.3%)
1972 1970
32.8 29.6
(44.1%)
23.3 22.
(32.7%)
12.5 12.7
(18.9%)
.6 .2
(.3%)
2.9 2.7
( 4%)
          Total
74.0
                                                             71.5
73.1
                                        72.1
                                                                                                   67.2
           SOURCE;   Oil  and Gas Journal,  January 26,  1976

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     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.  Table  II-2 indicates the historical




supply/demand pattern in the United States for crude oil.





       There is the potential for some substitution away from oil, such as the




  conversion of electric power plants to coal.  There is also some potential




  for an absolute reduction in petroleum/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 conser-




  vation 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.





      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
                                    H-3

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                                                              TABLE II-2
i
-e-
Supply



   Crude Imports



   Crude Production








Demand



   Crude Refinery Runs    ]

   Crude Transfers, Losses]


   Crude Exports



Total



Stock Charges
SUPPLY/DEMAND OF CRUDE OIL
('000 barrel/day)
1976a 1975 1974
5,235 4,133 3,477
8,085 8,343 8,764
13,320 12,476 12,241
13,209 12,465 12,161
36 2
13,212 12,471 12,163
-86 +5 +78


1973 1972
3,244 2,222
9,208 9,477
12,452 11,699
12,463 11,756
2 1
12,465 11,757
-13 -58
           SOURCE:  Oil and Gas Journal , January 26, 1976; July  26,  1976

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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.

     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-3 lists  the estimated U.S. energy demand by form, with

imported oil reported separately.  The base case assumed that government
  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.
                                  II-5

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                                  TABLE  I1-3
Energy Form




U.S. Oil




Imported Oil




Gas




Coal




Hydro & Geo.




Nuclear




Synthetics






    Total
U.S.
ENERGY DEMAND
BY PRIMARY SOURCE - 1985

(Quadrillion Btu's)
1972
22.4
11.7
22.1
12.5
2.9
0.6
_


Base
23.
24.
23.
19.
4.
12,
—
1985
$7 Oil $11
Case Accelerated Base Case
Supply
1 30.5 31.3
8 17.1 6.5
8 24.7 24.8
9 17.7 22.9
8 4.8 4.8
.5 14.7 12.5
_ —

Oil
Accelerated
38.0
0.0
25.5
20.7
4.8
14.7
0.4
72.1
109.1
109.6
102.9
104.2
 SOURCE:   Project Independence  Report,  FEA,  November 1974,  p.  46
                                           II-6

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policy towards energy, and particularly petroleum production, will be




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




remain at about 2-3 million acres per year.  Government royalties for




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-3 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.
                                 II-7

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     Table II-4 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 11-5 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 OCS production is 4.8 million barrels per day




(24%) under the accelerated development case.




     Table II-6 lists the estimated gas production assuming the $11 per




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




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.
                                     II-8

-------
                                  TABLE 11-4
                    U.S. CRUDE OIL PRODUCTION - 1974 TO 198S
                            (million  barrels per day)


                            "Business as Usual" Case

World Price ($/bbl)          1974     1977     1980     1985

      4
      7
     11
10.
10.
10.
5
5
5
9
9
9
.0
.5
.9
9.
11.
12.
3
1
2
9.
11.
15.
8
9
0
                            "Accelerated Development"  <  • e
       4
       7
       11
10.5
10.5
10.5
9.7
10.2
10.3
11.1
12.9
13.5
±1.0
16.6
2'1".
 SOURCE:   Project  Independence  Report, FEA, November  1974,  r
                                  II-9

-------
                                       TABLE II-5
    Production Area
1.   Onshore - Lower 48 States
    - Conventional fii
      primary fields
    - New secondary
    - New tertiary
    - Natural gas liquids
    - Naval Petroleum
2.   Alaska
    - North Slope
    - Gulf of Mexico
    - California DCS
    - Atlantic OCS
 4.  Heavy Crude and Tar  Sands

    Total Potential Production
POTENTIAL RATES OF U.S. OIL PRODUCTION



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

"Business
1974 As Usual"

rates 8.9 9.1
3 and new
6.4 3.4
2.4
1.8
s 2.0 1.5
serve //I
0.2 3.0
2.5
ncluding OCS) 0.2 0.5
serve //4 - -
nental Shelf 1.4 2.6
1.3 2.1
0.1 0.5
-
Sands - 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)
10.5
15.0
(4.5)
                                    20.0
(9.5)
     SOURCE:   Project  Independence  Report,  FEA,  November 1974,  p.  83
                                               11-10

-------
                                  TABLE I1-6
                 U.S. NATURAL GAS SUPPLIES, 1972-1985
                  (trillions of cubic feet per year)

Source                            1972        1977       1980       1985

Lower 48 States,Onshore           19.A        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
 r.ssumes $11 per barrel world oil prices  and  accelerated development scenario.

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

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




oil supply and demand, Figure II-l  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.




     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.
                                      II-12

-------
   15
   13

   12

   11


   10
    9
£   8
Q-
0)
T3
         Total U.S. Potioleum
         Demand
u
Jx
a
a.
to
a>
o
.c
M-
O
to
       Imports Supply Curve
                                    U.S. Offshore Plus Onshore
                                    Supply Curve,
                  Total U.S. Crude Oil
                  Supply Curve
                                   G
8
                                           10
11
12   13
                                                                            14
                                    15
                                   Demand/Production
                                     (MM bbls/day)
                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
                                                II-13

-------
2.   Characteristics of the Onshore Oil and Gas Producing Companies




     The oil and gas industry can be divided into two categories — onshore and




offshore operations, the former predominating.   In 1972 the onshore operations




consisted of 5,530 operating companies employing 111,300 workers.  Total pro-




duction was 2,647.6 million barrels from 340,148 oil wells, and 17,488.2 billion




cubic feet of gas from 83,985 wells.  The value of this production was $12,896.1




million.  Expenses for supplies were $4,268.3 million, and payrolls amounted to




$1,305.7 million.  Capital expenditures totaled $2,171.9 million, of which




$1,232.4 million went into mineral development and exploration.




     The onshore industry has been and continues to be concentrated in a few




large fully-integrated companies that exert control from production through




distribution.  The reasons for this dominance come from their control of trans-




portation and market sources, plus their ability to afford both the large capital




expenditures and risks necessary for exploration.  Tables II-7  and II-8 indicate




the extent of this concentration.




     On the other end of the spectrum are the small producers.   Table 11-9  shows




their share of the industry, in which 75% of the operations account for less




than 2% of the value of shipments.  Interestingly, their share of the volumes




produced is significantly less than their share of the value.
                                     11-14

-------
                                                        TABLE I1-7
(J1
COMPARISON OF PARTICIPATION IN VARIOUS ASPECTS OF THE PETROLEUM

Company
Exxon
Texaco
Shell
Amoco
Socal
Mobil
Gulf
Arco
Sun
Total,
SOURCE:
FOR THE NINE LARGEST

Production
11.9
9.7
7.8
6.0
5.7
4.8
6.9
5.4
2.9
9 companies 61.1
Market Performance and Competition in the
OIL COMPANIES
% of U.S. Total
Refining
8.6
8.2
8.0
7.6
7.3
6.8
6.3
5.6
3.4
61.8
INDUSTRY

Product Sales
10.6
8.3
6.5
6.6
6.4
6.1
4.9
4.7
3.5
57.6
Petroleum Industry, Part 1, Committee or
                      Interior and Insular Affairs, Washington, D.C.,  1974,  p.  102

-------
                                     TABLE II-8
                      MARKET SHARE OF EIGHT LARGEST PRODUCERS

Eight Largest Producers                                               % of Total

Value of shipments + receipts ($ mil.)         8,256.7                    53%
Crude petroleum:  value                        6,187.6                    57%
                  quantity (mil. bbls.)        1,816.0                    56%
Natural gas:  value                            2,059.3                    50%
              quantity (bil. cu. ft.)         10,595.7                    50%
Employment (000)                                  22.6                    19%
Capital expenditure                            1,300.6                    44%
 5,530 total producers
 SOURCE;   1972  Census of Mineral  Industries,  p.  13A-61.

-------
                                     TABLE II-9
                       MARKET SHARE OF SMALLEST PRODUCERS

4,130 Smallest Producers                                                  %  of Total

Value of shipments + receipts  ($ mil.)                274.1                 1.7%
Crude petroleum:  value                               525                    .5%
                  quantity (mil. bbls.)                16.5                  .5%
Natural gas:  value                                    12.2                  .3%
              quantity (bil.  cu. ft.)                  68.1                  .3%
Employment  (000)                                        6.2                 5.0%
Capital expenditure                                    43.9                 1.5%
 5,530 total producers
SOURCE:  1972 Census of Mineral Industries, p.!3A-62.

-------
     JDil_ 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 dis-




torted 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 limi-




tation guidelines.  At sufficiently high prices, there would simply be no




potential for the pollution control costs making an existing 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.




     The Congress enacted a new set of oil price regulations in December 1975




which established a two-tier pricing  system for domestically-produced oil. As




written, the regulations will be in effect through May 1979.   However, there is




a major public policy debate in progress 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 now priced at a higher tier price, the removal of controls from old oil would




have the effect of providing additional capital to the oil companies to undertake




new exploration and production.  The argument on the other side is that there
                                     11-18

-------
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 companies.




     All offshore and onshore production to which the effluent guidelines would




apply are now price controlled.  Deregulation would increase these prices to




near 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 crude oil prices are




deregulated and there is a specified level of world crude prices.  Recent tax




legislation has effectively ended the depletion allowance for large producers.




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




21 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) under the Emergency Petroleum Allocation Act




(December 1973),which imposed regulations on crude prices.  In December 1975,




the Congress enacted the Environmental Policy and Conservation Act  (EPCA),




which revised the price control regulations and established a two-tiered  system




of prices for domestically-produced crude.
                                     11-19

-------
     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 organization called




the Organization of Petroleum Exporting  Countries (OPEC) was formed to specifi-




cally 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 11-10 lists representative posted and actual prices.




     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  (particularly  independents and non-




foreign  oil-producing  companies, as  this segment  of  the  industry was in an
                                     11-20

-------
                           TABLE  11-10
         REPKKSKNTATIVE POSTED  PRICKS AND ACTUAL COSTS

       PER BARREL  OF FORK 1ON  EQUITY CRUDES AND U.S. CRUDE

Algeria
Canada
Iran
Iraq
Kuwait
Libya
Nigeria
Qatar
Saudi Arabia
U.A. Knii rales
Vone/Aifla
U.S. Old Oil
U.S. Nnw Oil
U.S. Composite**
Imported Composite
Total Composite
*Includcs transportation
Posted Prii-i1
$1G'.21
G.60
11.87
1 1 .67
11.54
15.70
M.69
12.01
11.05
12.G3
14.87
• - .
. - .
_ - .
...
...
"Domestic o
                                              Arlual Cost*
                                              ~$ii."25
                                                11.08
                                                 9.35
                                                 9.23
                                                 9.12
                                                10.95
                                                10.2G
                                                 9.70
                                                 9.20
                                                 9.82
                                                10.95
                                                 5.25
                                                10.20
                                                 7.15
                                                10.42
                                                 8.01
SOURCE;   Platts Price News.  June 26,  1974
                                    II-21

-------
over-production situation), partly to prevent long-range dependence on foreign




oil, and partly to use as a level 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 expensive




than domestic oil.  Even though the production costs of most domestic oil is




far below the price of imported oil, production cannot meet demand.  Table II-U




lists historical crude prices from various domestic and foreign producing areas.




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




delivery to a refinery.  Tables 11-12 and 11-13 list crude price and transpor-




tation costs to U.S. refining areas from several producing areas.  Table 11-12




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 11-13 compares U.S. new oil with minimum




foreign oil prices.  One sees in the table that the price of the new oil has




risen to just below the same price as the foreign oil when transportation costs




are taken into consideration.




U.S. Crude Petroleum Price Regulations




     Under the Emergency Petroleum Allocation Act there was a domestic crude




price control program with two levels.  "Old" oil (a volume equivalent to the




average daily production from a particular property during the year 1972 less




volumes, if any, of "released" oil produced) had a ceiling price of its May 15,




1973 posting plus $1.35 per barrel.  According to FEA figures, the weighted




average "old" oil price that emerged from these guidelines was $5.25/barrel.
                                    11-22

-------
TABLE 11-11
HISTORICAL
CRUDE.
Arab light
Iran light
Kuwa i t
Abu Dhabi Murban
Iraq Basrah
Qatar Dukhan
Iraq Kirkuk
Libya
Nigeria
Sumatra light**
Venezuela Tia Juana (31°)**
Venezuela Oficina**
Louisiana
East Texas
West Tt-xas sour
*\oar's highest price ^iveii
POSTED CRUDE OIL PRICES
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
, 1074 pr
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
ioo oil ivt
**0fficial selling price for Sumatra, reference
all others are posted prices. Kirkuk priced
prices are representative postings for crude
SOURCE: Oil and Gas Journal


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
ivo Jan. 1 .
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

price for Venex.uela,
at Mediterranean; U.S.
oil.



        11-23

-------
                                      TABLE F1-L2

                         ni'lUVKKKlJi  I'KJCKS OK  KOKKICN  AN!)
                                  X'-   MIX  nOMKSTIC CKlimT"
Wc.\t Tf\ns Arabian '] HI JIIUIHI
Sour. 12' Light 34' Light. 11°
'$7.38 $10.46 $11.10
0.18 0.18
$7.38 $10.64 $11.28
0.95 1.40 0.34
$8.33 $12.04 $11.62
U.S (iULF COASI
0.25 1.39 0.32
$7.63 $12.03 $11.60
CHICAGO
0.41 1.58 0.51
$7.79 $12.22 $11.79
U.S. WIST COAM (l.OS ANGfl
$ Sour \'rniiiro28°
0.20 1.16 0.73
J$7.33 $11.80 $12.01
S /<.i/nm;m
Light 3 7*
•S7.63
$7.63
0.85
$8.48
025
$7.88
0.32
$7.95
.is)
Ciiniitlian
t$!2.!5
0.18
$12.33


0 50
$12.83

Nigcnun
Light 34'
$11.75
0.18
$11.93
072
$12.65
0.83
$12.76
1.02
$12.95
••
        F.o h  Price
        License Fee
        Sub-total

        Transportation
        Delivered  Price

        Transportation
        Delivered Price

        Transportation
        Delivered  Price
        Transportation
        Delivered  Price
        •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
                                             11-24

-------
                                           TABLE  IT-1 3
                           DELIVJERKj) IMUCK  OK  FOKKICN  AND
                            DECONTROLLED DOMKS'l'Tc  CRUDKS
              F.o.b.  Price
              License Fee
              Suit total

              Transportation
              Delivered  Price

              Transportation
              Delivered  Price

              Transportation
              Delivered  Price
              Transportation
              Delivered  Price
              *For price control
              and includes $5.20
West 7>.tH .»•/*
t$!2.15 $1175
0.18 0 IK
$J2.33 $11.93"
0 (>•»
5/2.^7
071
$ 1 2 66
0.50 0.92
$12.83 $12.85
  Sour Ventura 28°
       0.20       0.54       0.6S
    •J10.K3     $11.18     $11.96
-exempt,  free market  crude,  t Allows for  currency  exchange differentials
Canadian export  tax.  U;rcc market f.o.h.  price $10.63.
Note:   Transportation  costs are  on .1  .spot lias Is.
SOURCE:    L'etroleum Intelligence Weekly,  December 9,  1974
                                               11-25

-------
"New" oil, or the production in excess of the daily average during 1972, as




well as "released" oil, or an amount of "old" oil from a property equivalent




to the production of "new" oil from that property,  was not subject to ceiling




prices and could theoretically rise to import parity.   Production from stripper




wells, that is wells yielding less than 10 barrels per day, was also exempt




from price controls.  Imported crude remained free of  price controls, although




it was subject to the import duties and license fees.




     Curiously enough, what had been designed as a two-tier system of crude




prices, with an "old" controlled price and all other crude at import parity,




did not work out so neatly in practice.  In reality there were three price




levels — "old", "new", and foreign.  The average "new" crude price was typically




about $1.00 to $1.50 per barrel below the average price of imported crude.  One




of the principal reasons that "new" oil prices did not rise to import parity




may have been the existence of state regulations known as "equal purchaser




laws" in many of the oil-producing states.  These laws refer to a purchaser's




right to offer fundamentally different prices to different crude producers in a




state for the same quality crude.   Such laws were originally enacted to protect




independent producers in their transactions with majors, but were interpreted to




apply to "old" and "new" oil prices when these classifications were created.




     The text of the EPCA was not explicit as to the actual mechanics of domestic




crude price controls and specified only that a system be devised by February




1976 which resulted in an average controlled domestic  crude price of $7.66 per




barrel.  Using its rule-making powers, the FEA instigated a price control program




which achieved an average domestic ceiling of $7.66 per barrel by having a two-




tier crude pricing system.  "Old" oil became lower tier oil and prices were held
                                     11-26

-------
at the previous controlled levels (giving an average "old" oil price of $5.25




per barrel).  "New" oil and stripper well production became upper tier oil




which was priced at its September 30, 1975 posting less $1.32 per barrel. The




resultant average upper tier price was $11.28 per barrel.   The concept of




"released" oil was eliminated.  The weighted average of lower tier and upper




tier production was designed to give the required national average of $7.66 per




barrel.




     In the process of devising the new two-tier domestic crude pricing struc-




ture, the PEA specified some important changes in the definitions of old and




new.  Lower tier oil is essentially "old" oil, but the base period control




level used in defining "old" has been changed.  Instead of being a volume of




production equal to the production level for a similar period in 1972, lower




tier oil is defined as either crude production equivalent to the daily average




"old" oil production in 1975 or production equivalent to the daily average




crude production in 1972.  However, the base period production levels will be




subject to semi-annual review beginning in July, 1976.  If a property produced




no upper tier oil in the six months preceding the semi-annual review, then its




base period production level is eligible for revision.  The FEA can make a




downward revision in the property's base period production level equal to three-




quarters of the average annual rate of decline between 1972 and 1975 (1972 pro-




duction minus 1975 production divided by 3).  This new definition of the base




period gives producers whose "old" oil production had been declining an oppor-




tunity to regain the losses in their base period production levels experienced




in 1973 through 1975 and also to retain a possibility of crossing the upper




tier threshold despite declining production.  In the current pricing regulations
                                      11-27

-------
there is also a cumulative deficiency clause which stipulates that producers




may not sell any crude as upper tier oil until the average daily production




since February 1, 1976 exceeds the base period control level.  In general, it




is hoped that the revised regulations will provide strong incentives for pro-




ducers to maintain and maximize their production levels.




     According to the provision of EPCA, the average domestic crude price




(i.e., the initial $7.66 composite price for lower and upper tier oil) will be




allowed to increase by a rate not to exceed 10% on an annual basis.  In the




EPCA legislation it is stated that the 10% maximum is to be comprised of an




inflation factor not to exceed 7% per annum and a production incentive of 3%.




The 10% ceiling will be the subject of some further FEA consideration regarding




whether or not this ceiling will act to suppress potential domestic production.




     The price increases were designed to compensate producers for the effects




of inflation and also to provide an incentive to expand production levels.  In




its implementation of the EPCA provisions for price increases, FEA has decided




to apply the increases  (at least in the initial year or so)  equally to upper and




lower  tier production.  In later years FEA anticipates  that  it may weight the




allowable increases in  favor of upper  tier production to assure  the maintenance




of adequate  incentives  to sustain and  expand upper tier production levels.




Table  II-14  shows the FEA's initial schedule for monthly increases in the average




lower  and upper  tier  crude prices.  FEA plans to  review the  schedule  of  increases




on at  least  a  semi-annual basis  in  order  to  adjust for  unanticipated  distortions




in the composite average  price caused  by  changes  in  the mix  of  upper  and  lower




tier  oil production or  in the  average  price  of  upper  or lower tier crude.
                                         11-28

-------
                              TABLE 11-14

FKA PROJKC
FOR LOWER AND
TIONS 01'
UPPER '1
February 1976



Month
2/76
3/76
4/7b
5/76
6//6
7/76
8/76
9/76
10//6
! 1/76
12/76
1/77
2/77
3/'77
4/77
5/77
6/77
7/77
8/77
9/77
Effective 10/77 Up
price calculations
10/77
M/77
12/77
1/78
2/78
3/78
4/78
5/78
6/78
7/78
8/78
9/78
10/78
11/78
12/78
1/79
2/79
3/79
4/79
5/79
End of Program pri

Lower Tier
5/15/73
post ing
plus:
$1.35
1.38
1.41
1.45
1.48
1.51
1.54
1 .58
} .61
1 .64
1 ,6H
i . 71
1 .74
1.77
1 . 80
1.83
1.87
1.89
1.93
1.96
per Tier
change
1.99
2.02
2.05
2.08
2.12
2.14
2.16
2.19
2.19
2. 19
2.20
2.21
2.21
2.2?
2.22
2.23
2.23
2.25
2.26
2.26
cos: $6.16


E:;t i
Low i
1 CE
'1ER
- M

' nia t'
>r T
Price
$5.
5.
5.
5.
5.
5.
5.
5 .
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.


5.
5.
5.
5.
6.
6.
6.
6.
6.
6.
6.
b.
6.
6.
6.
6.
6.
6.
6.
6.

25
28
31
35
38
41
44
48
51
54
58
61
64
67
70
73
77
79
83
86


89
92
c>5
98
02
04
06
09
09
09
1.0
11
11
12
12
13
13
15
16
16

1 1, INC PRICES *
OIL PRODUCTION
ay 1979
Upper Tier
eJ 9/30/75
'ier post 1 nix
less:
$L.'^
' 1 .2'i
1 . 18
l.J 1
1.05
0.97
O.'-K)
0.83
0. 76
0.69
0.62
0.55
0.47
0.4L
0.34
0.28
0.21
0.15
0.08
0.01
9/30/75
posting,
0.05
0.12
0.19
0.26
0 . 2 3
0.38
0.43
0.48
0.55
0.62
0.70
0.77
0.84
0.91:
0.99
1.07
1.14
1.2?
1.29
1.35

                                                                     list Limited
                                                                     Upper Tier
                                                                       Pi Ice
                                                                      $11,
                                                                       11,
                                                                       1 1 ,
                                                                       11,
                                                                       11.
                                                                       11.
                                                                       11.
                                                                       11.
                                                                       11.
                                                                       11.
                                                                       11 .
                                                                       12.
                                                                       12,
                                                                       12.
                                                                       12,
                                                                       12.
                                                                       12.
                                                                       12,
                                                                       12.
                                    28
                                    35
                                    63
                                    70
                                    77
                                    84
                                    91
                                    98
                                    05
                                    13
                                    19
                                    26
                                    32
                                    39
                                    45
                                    52
                                                                       12.59
iascd on 4th quarter 1975 deflator.
current deflators are available
Price will be subject  to  revision as more
                                      II-29

-------
     It is not the intent of this analysis to make a projection of world or




U.S. crude oil prices over the period of the analysis — about 20 years. There




are strong economic and political forces with opposing views on what United




States crude pricing policy should be.  There is, in addition, a wide range




of speculation on Middle Eastern oil pricing over a 10 to 20 year period.




     For the purposes of this analysis, the current two-tiered domestic price




system is assumed to stay in effect through the study period.  Costs and




prices are held at 1975 levels.   The 3% yearly increase in real crude prices




(in excess of inflation) allowed by the EPCA has been incorporated in the




computation of yearly revenues from production.  The price schedule shown in




Table 14 has been extended beyond the current expiration of the regulations.
                                      11-30

-------
 4.    Financial Characteristics






The Role of Financial Characteristics in the Economic Impact Analysis




     The onshore oil and gas industry has several unique financial characteris-




tics   which reflect the risks of the business, its special tax status, and




its cash flow patterns.   Three issues are particularly relevant to this




economic impact analysis:





     •  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?






The following sections of this chapter address these issues.




     In contrast to the  offshore oil industry, the onshore oil industry is




characterized by the presence of both major oil companies and small




independent producers.  These small independents account for about 50%




of domestic onshore production.  Furthermore, in 1971 and 1973, the




lower quartile of these  smaller companies showed operating losses.  Thus,




the impact of the capital costs for pollution control equipment may be




more significant for the smaller operators.  The special characteristics




of the smaller companies will be discussed separately.






Capital Investment and Capital Availability




     According to the latest analysis published by the Chase Manhattan




Bank, the petroleum industry will need to invest about $480 billion in
                                      11-31

-------
exploration and production during the next ten years.  Another $475 billion




will be required for additional transportation, marketing, and processing




facilities.  This total investment of $955 billion is nearly four times




more than actual expenditures during the past four years.  This amount does




not include provision for repayment of debt, expansion of working capital,




or payment of dividends.




     Another study of the oil and gas industry's capital needs, performed




by Bankers Trust Company, estimates that the total capital requirements of




the industry will be about $300 billion, in constant 1974 dollars, between




1975 and 1990 (see Table 11-15).  Nearly 75% of this amount is required for




exploration and development alone.  Whether or not the U.S. financial markets




can supply these capital funds continues to be an important subject of




discussion.





     One of the principal determinants of the industry's level of investment




and access to capital is its profitability.  Historically, from 1952 to




1972 the industry's profits were low and capital investment was inadequate.




In 1973 and 1974, both profits and capital investment improved dramatically.




In fact, 1974 investment increased 46% over 1973.  Although profits declined




in 1975, the level of capital spending has continued at its high level.  The




industry apparently is borrowing heavily and drawing down working capital




to sustain this rate of spending.




     About 45% of the industry's capital outlay in 1974 was devoted to




production.  Moreover, the U.S. accounted for about 60% of the worldwide




investment in exploration and development and nearly 60% of the increase in




investment (see Table 11-16).  However, about half of these expenditures in




the U.S. were for lease bonuses.
                                     H-32

-------
                       TABLE  11-15




    CAPITAL NEEDS  OF THE  OIL  AND GAS  INDUSTRY,  1975-1990




                (millions of  1974 dollars)
 Exploration and  development              220,727




 Refining                                 35,250




 Tankers                                    6,377




 Pipelines                                 25,101




 Deepwater  ports                            1,500




 Marketing                                  9,600





 Total                                   298,555
SOURCE;    Oil and Gas  Journal,  February  2,  1976.
                            11-33

-------
                          TAlil.K  11-16
   GKOGRAPlirCAL BREAKDOWN OF  CAPITAL  EXPENDITURES
                             1974   1973         Ch.mtie
                             Million Dollars      Mill  S Percent
  United Slalws                 11.450    7,43!>
  Canada                      l.:fOO    1.0/">     '  I'.'!)  '.'(1!)
  VtMWViiola                     305     20b     <  1OO  «<1HH
  Other Western Hemisphere        975     G2'j     '  3!>0  '500
       Western HemisphRre      14.030    9,"345     >4.(>S'J  »50 1

  Western Europe               2.415    1,32b     «1.090  'R2 3
  Alric.T                         800     025     *  205  *4? 4
  Middle East                  1.000     855     '  145  '170
  Far East                    _1200_ 775    _*  425  
-------
     The Chase study also includes an analysis of the capital investments




of the world petroleum industry.  The most recent year for which data is




available is 1974.  Table 11-17 lists capital expenditures for the world




and the U.S. from 1968 to 1974.  Table 11-18 is a breakdown of exploration




and development expenditures in the U.S. for 1974 and 1973.  In the Chase




analysis, expenditures for lease rentals and geological and geophysical




expense are not capitalized.  This pattern may not always hold true,




particularly for dry holes and geological and geophysical expenses.




     The Oil and Gas Journal also collects statistics on capital expenditures




each year from 150 firms.  These statistics are proportionately projected




to the whole industry on the basis of the companies' share of total




industry crude production.  Table 11-19 lists the results for 1973-1975,




with projections for 1976.  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.




     Comparing the Chase study with the Oil and Gas Journal analysis, it is




evident that the estimates for expenditures are significantly different for




the exploration and production categories.  However, they do give general




guidance as to the order of magnitude of expenditures that one should use




as a point of comparison with the pollution control capital expenditures.




Table 11-20 lists the general comparison values which can be used in the




impact analysis.





     The Chase Manhattan Bank studies of major oil companies compile




information on the sources and uses of funds.  Table 11-21 contains the




sources of cash for 1974 and 1973.  In 1974, the cash flow from capital




recovery mechanisms such as depletion and depreciation dropped to 35% of the
                                    11-35

-------
                                                       TABLE  11-17
                                     ESTIMATED CAPITAL AND EXPLORATION  EXPENDITURES
M
M
I


WORLD
CO ^.0'"' l~lli i' ";'':" ' •'• '-''•%
' ,-i j'<)' G.-"- _ : ''• '•''••.'i'^
P'LV L"V<
Takers
Bo-iou'ie^
Cfr^ifri Dif^u
% '-,, ^f.'i'ii'i
Ohner
Fora/ Capital Expenditures
Geological & Geophysical
Expense and Lease Rentals.
COMBINED
UNITED STATES
0-..CM 3'' c^". ' .V.\.'c.\ ' -^
. ..' ' Ga; lia:,ds Plarus .
• • ~ L ' 'C?
~ --'- . .-• .,
*~ M- ' • S
0 ' f'1 iCd! ^IftTS
'. r'; P'Tlu
" -r-e,
Total Capital Expenditures .
Geological & Geophysical
Expense and Lease Rentals .
COMB/MED
1968


6,871
r'-.-.
1 0- "
1.6'-".
2.9C'
1 480
2 gp^
015
1 7,900

1 .330
TO Tjf

4.075
200
425
50'
300
650
1 150
35:
&.3BO

715
0,065
1969 1970
Mi

- •:•-•: o.ooo
451 -3\
9 ': '" °, 50
2,?50 2,075
' 3.21"~ 4,000
",310 ' ,525
" 505 3.220
53r 72:
133^5 20/25

1 ,350 1 ,340
19, "55 21,405

4 ::o 4,110
025 223
30'"' 450
-co 100
-1-0 1.075
575 050
' 350 1,450
23' 255
'-'17- c 225

~2~ 005
3 000 8,330
1971
///on Dollars

6,520
,^r, -,
! - • '~
'^ or ~7 r~
4.750
1 .530
3,380
84 C
21,300 2

1 ,305
23 195 2

3/85
_ O'J
ci?0
12E
' OF:
500
1,350
70r
7,250

715
. ,06:
1972


o 59 fj
515
1.230
3,775
4.955
1 ,'y^f
2,325
~ 1 ^
4 G5'

1 ,54C
p,490

^4;
, i

12"
- , -
4-::
1,100
260
C, QC

740
9,790
1973 1974


' 2 4 i 0 ', 3 705
7/0
:./'.' ^."O ^
' . -. - -- ^ .
^-.^DC- // -
7; yj1"-
2 4C0 2.2''5
"' ~i r ^ 7 '
20 OOi 4; 7'/,

'.700 2 '30
3' 095 45 ^30

2V . ^ ,
^o
- . .
^
. , o .
^25 320
C^ . '. "- ,
;z-_ :/
"'Ji-» „ ' . ' ^ s '-

-o. ;
' - f '^' ' ~ ~ ', ^
             SOURCE:   "Capital Investments  of the World Petroleum Industry," 1974,"  Chase Manhattan Bank.

-------
                            TABLE 11-18
             EXPLORATION AND DEVELOPMENT EXPENDITURES
                    IN THE U.S.:  1973 AND  L974
                                       1973
                                     ($ million)
                    1974
                 ($ million)
Expenditure

Lease acquisition

   Onshore

   Offshore

Producing wells

Dry holes

Geological and geophysical
   expense

Lease rentals


   Total

3
2



500
,100
,705
985
675
175
700
5,100
3,975
1,450
925
205
8,140
12,355
SOURCE;    "Capital  Investments  in  the  World  Petroleum
          Industry,  1974,"  Chase Manhatton Bank
                               11-37

-------
                                  TABLE 11-19
ESTIMATED CAPITAL AND EXPLORATION EXPENDITURES OF U.
S. OIL INDUSTRY
(1973-1976)

Exploration and Production
Drilling and Exploration
Production
OCS lease bonus
Total
Other Expenditures
Refining
Petrochemicals
Marketing
Crude Products Pipelines
Natural Gas Pipelines
Other Transportation
Miscellaneous
Total
1976
(budgeted)
($ million)
8,485.0
6,670.0
1,250.0
16,405
1,760.0
2,282.0
830.0
2,559.0
490.0
230.0
1,946.0
10,097.0
1975
(estimated)
($ million)
8,347.0
4,372.0
1,087.0
13,806.0
2,724.0
4,266.0
834.0
2,675.0
564.0
188.0
1,364.0
12,615.0
1974
($ million)
7,329.0
2,135.0
5,024.0
14, £88.0
2,446.0
810 . 0
679.0
1,096.0
541.0
163.0
1,278.0
7,013.0
1973
($ million)
6,660.8
1,734.8
3,082.0
11,477.6
1,103.8
269.1
914.5
150.0
600.0
152.9
646.9
3,837.2
Total Expenditures
26,502.0
26,421.0
21,501.0
15,314.8
SOURCE:  oil and Gas Journal. February 23, 1976.
                                     11-38

-------
                             TABLE 11-20
                TYPICAL YEARLY CAPITAL EXPENDITURES

            OF SEGMENTS OF THE OIL INDUSTRY IN THE U.S.
Offshore Oil and Gas Production       $6-8 billion per year
Onshore Oil and Gas Production        $3-5 billion per year
Other Capital Expenditures
(refineries, pipelines,
marketing, etc.)
$6-8 billion per year
    Total
$15-21 billion per year
SOURCE:   Arthur D. Little,  Inc., estimates
                           11-39

-------
                                 TABLE 11-21
                          CASH FLOW OF CHASE GROUP
                                          1974
                                      ($ millions)
                            1973
                        ($ millions)
Net Income
16,371
(57%)
11,678
(55%)
Write-offs (including
  depreciation and depletion)
10,133
(35%)
 8,345
(39%)
Other non-cash charges (net)
 2,332
( 8%)
 1,207
( 6%)
     TOTAL
28,836
              21,230
 SOURCE:  "Financial Analysis of a Group of Petroleum Companies," 1973  and  1974,
         Chase Manhattan Bank
                                      II-40

-------
total cash flow from 39% in 1973.  Table 11-22 lists all of the sources and




uses of working capital for the Chase Group in 1974.  The percentage of funds




available from cash earnings was slightly lower in 1974 (72.8%) than it was




in 1973 (73.4%).  Long-term debt accounted for a slightly higher percentage




of funds in 1974 (15.9%) than in 1973 (15.2%).  Perhaps the most important




fact is that total funds available in 1974 were $39.6 billio. ,  an increase of




37% over 1973.  In 1974, 57.8% of the available funds were used for capital




expenditures whereas only 50.6% were used for this purpose in 1973.  Dividend




payments to shareholders dropped to 11.5% of total available funds, from 13.7%




in 1973.






Profitability





     Due to large price increases for crude oil dictated by the governments




of some foreign producing countries, there were significant changes in the




income statements of the Chase Group of companies.  Gross revenue increased




83% over 1974, while record revenue levels were recorded in all product




categories (see Table 11-23).  in spite of this increase, operating costs




increased by an even larger percentage, 94%.  Net income also grew, but not




by as large    a percentage as revenue or expenses.  Earnings increased by




about 40% over 1973.  Important factors in this gain were inventory profits




early in the year and improved contributions from chemical operations.  The




pattern of earnings growth dwindled as the year progressed and became a




decline of 12% by the fourth quarter.  One of the most significant changes




was the increase in estimated income taxes.  They were 117.5% higher in




1974 than in 1973.  The Group's rate of return on revenue dropped tc 6.7%




in 1974, compared to 8.7% in 1973, 6.5% in 1972, and 7.4% in 1971.  The
                                     11-41

-------
                                  TABLE 11-22
                   SOURCES AND  USES_OJLWORKING  CAPITAL.  1974
                                                      Million
                                                      Dollars
              Percent
            Distribution
 Funds Available From:
    Cash Earnings
    Long-Term Debt  Issued
    Preferred and Common Stock  Issued
    Sales of Assets and Other Transactions
        TOTAL
28,836
 6,275
   119
39,602
 72.8
 15.9
  0.3
-1JLJ3
100.0
 Funds Used  For:
    Capital Expenditures
    Investments and Advances
    Dividends  to Companies' Shareholders
    Dividends  to Minority  Interests
    Long-Term  Debt Repaid
    Preferred  and Common Stock Retired
         TOTAL
 Change  in Working Capital
22,902
914
4,562
210
4,124
102
32,814
+6,788
57.8
2.3
11.5
0.6
10.4
0.3
82.9
17.1
SOURCE:    "Financial Analysis of a Group  of  Petroleum Companies,"  1974,
          Chase Manhattan  Bank
                                       11-42

-------
                               TABLE TI-23
              INCOME  STATEMENT OF THE CHASE GROUP
                                              _Wy        7.973 __     Pcic,,m
                                                 Million Dull.11 <;        C/i.i'"/'1

  Gross Operating Revenue   	   239,502    130,948    + 82.9
  Non Operating Revenue	       5.033      7,901    +_ 70 0
      Total Revenue  	    244,535    133.009    i_82-6
  Operating Costs and Expenses	    175,188     90,298    ~94.0
  Taxes - Other than Income Taxes (a)	       7,214      6,241    + 15.6
  Write-offs	      10,133      8,345    + 21.4
  Interest Expense	       2,478      2,008    + 23.4
  Other Charges	      	1_5    	37    - 59.5
      Total Deductions  	    195,028    106,929    + 82.4
  Net Income before Income Taxes	      49,507     26,980    + 83.5
  Estimated Income Taxes	      32,379     14,889     117.5
  Income Applicable to Minority Interests....	757       413      83.3
          Net Income (bj	      16,371(c)  11,678      40.2

  (a) Excludes S27.113 million  m 1974 and S25.78G million in 1973 rupn'sentinq salus jncl
     excise taxes,  on qasolme and other refined products, which arc collected 1rorn customers
     and accounted for  to United  States federal,  state ami city authouties. and to other
     governments  Such taxes are deducted before arriving at vt:mn'
  (b) Incluiles earnings from operations outside U.S.:  1974  S'J.Q 70 million and 1 9 /'S  S7.544
     million.
  (c) Excludes SI 12 million of extraordinary income
SOURCE:    "Financial Analysis of a Group  of  Petroleum
            Companies,"  1974,  Chase  Manhattan  Bank
                                    11-43

-------
proportion of earnings attributed to U.S.  operations increased slightly, to




39%, from 35% in 1973.  This represents a  continued sharp decline from the




levels reached in 1972 and 1971 (about 50%).




     Earnings of the Chase Group in 1975 confirm the suspicion that the




record levels of 1974 were a one-time tiling,  brought about by external




events.  In 1975, the Groups earnings declined by 29%.





Issues Affecting Capital Investment and Profitability




    Two important political issues, "windfall" profits tax and divestiture




of integrated oil companies, are presently being debated by the Congress.




The resolution of these issues can potentially have a serious impact on




the profitability, level of capital investment, and access to capital of




the industry.




    Of these two issues, the question of divestiture is receiving the most




attention by the Federal government and the press at the present time.  Two




approaches have been taken to this issue.   After recent investigations into




the oil industry, the Federal Trade Commission has issued an antitrust




complaint against the eight largest oil companies with marketing operations




on both the East Coast and the Gulf Coast.  In addition, several bills have




been introduced in Congress to separate the major oil companies into




independent, functional, operating companies.  The stated purpose of both of




these  approaches is to eliminate monopolistic practices and increase




competition in the petroleum industry.




    There has been a significant reaction to  the divestiture plans,




especially the proposed legislation,  from both government, industry, and the




financial community.  Much of  this reaction is negative.  A study recently
                                       11-44

-------
concluded by the U.S.  Treasury Department states that "divestiture would be




contrary to U.S. national interests and would handicap the achievement




of our national energy goals.   It is likely that divestiture would create




upward pressure on domestic prices and cause domestic energy investment to




decrease."




     A number of industry analysts believe that the long-term financial




effects of divestiture would be particularly severe.   They cite several




reasons that support this belief.  Historically, the integrated oil companies




have exhibited more stable case flow levels than the smaller independents.




This stability of cash flow, together with other factors such as debt-to-




equity ratio, company size, and debt coverage ratios, are significant factors




in determining a company's bond ratings, and thus, its cost of debt.  Forced




divestiture would threaten the stability of this cash flow, causing bond




ratings to fall and the cost of debt to increase.  Given the level of




uncertainty due to potential litigation over various issues, it is also highly




likely that companies' ability to raise new equity capital would be dampened.




Thus, a principal effect would probably be an increase in the cost of capital




for the petroleum companies.  Because of this increase in the cost of capital




and a lower capacity to raise sufficient funds in the external capital markets,




the long-run level of capital investment would probably be reduced.




     In addition to windfall profits, taxes and divestiture, other serious




issues facing the oil industry include the government's policies on oil prices




and oil imports.  It is difficult at this time to assess fully or predict the




impact of all of these issues on the industry's ability to raise capital.  The




principal effect at this time is that the industry's environment is




characterized by considerable uncertainty.
                                      H-45

-------
Capital Structure




     For the onshore oil and gas industry, two classes of producers are




important:  larger, major companies and smaller independent producers.  This




analysis will discuss these two categories separately.




     The petroleum industry has historically depended on internally-generated




funds as its primary source of capital.  The sample balance sheet for the




Chase Group of companies is contained in Table 11-24.  Long-term debt plus




deferred credits and minority interests made up about 19.2% of total




capitalization.  The ratio of debt to equity was about 40%, the same as




in 1373.  If long-term lease arrangements had been capitalized, long-term




debt would be 31% of total capital employed.  In 1974, the ratio of current




assets to current liabilities - the current ratio - dropped to 1.4, the




lowest it has ever been.
                                      11-46

-------
                                  TABLE 11-24
                       BALANCE SHEET OF THE CHASE GROUP
 ASSETS
 Current Assets
 Investments and Advances
 Property, Plant and Equipment (a)
 Other Assets
     Total Assets
                                          12/31/74
                                        ($ Million)
193,247
                      12/31/73
                    ($ Million)
86,889
10,628
91,169
4,561
45.0
5.5
47.2
2.3
56,149
10,386
79,613
4,268
37.3
6.9
52.9
2.9
100.0    150,416    100.0
 LIABILITIES AND NET WORTH
 Current Liabilities
 Long-Term Debt
 Deferred Credits
 Other Reserves
 Minority Interests
 Net Worth:
   Preferred Stock
   Common Stock
   Capital Surplus
   Earnings Reinvested in Business
     Shareholders' Equity
   Total Liabilities and Net Worth
60,454
25,591
7,591
3,803
4,068
335
11,536
8,773
71,096
91,740
193,247
31.3
13.2
3.9
2.0
2.1
0.2
6.0
4.5
36.8
47.5
100.0
36,502
22,727
5,711
2,821
3,274
315
10,455
8,597
60,014
79,381
150,416
24.2
15.1
3.8
1.9
2.2
0.2
7.0
5.7
39.9
52.8
100.0
 (a)
     After deducting accumulated reserves of $69,219 million in 1974 and  $64,060
     million in 1973.
SOURCE:    "Financial Analysis of a Group of Petroleum Companies," 1974, Chase
          Manhattan Bank
                                      II-47

-------
Cost of Capital for Larger,  Major Companies




     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  interdependences  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 11-25 ,  preferred stock does not represent a very




 high proportion  of the  capital  structure of the  leading  producers.   Thus,  for




 the purposes of  this  analysis,  the weighted average cost of  capital will  consist
                                           11-48

-------
TABLE 11-25
PETROLEUM INDUSTRY CAPITALIZATION.
Total Long-Term^1)
Firm Capital
($ Million)
Amerada Hess 2,359
Apache Corp. 127
Apco Oil 131
Ashland Oil 1,448
Atlantic Richfield 6,236
Belco Petroleum 234
British Petroleum 8,834
Buttes Gas and Oil 191
Charter Company 384
Cities Service 2,412
Clark Oil & Refining 190
Commonwealth Oil 360
Continental Oil 3,040
Dome Petroleum 440
Exxon 20,476
Getty Oil 2,108
Gulf Oil 7,752
Gulf Oil Canada 1,147
Husky Oil 303
Imperial Oil 1,920
Kerr-McGee 1,024
Kewanee Industries 273
Louisiana Land Exploration 504
Marathon Oil 1,261
Mobil Oil Corp. 8,675
Murphy Oil 571
Natomas Company 369
Occidental Petroleum 2, 62
Pacific Petroleums 479
Pennzoil 1,472
Phillips Petroleum 3,317
Quaker State Oil 160
Reserve Oil & Gas 137
Royal Dutch Petroleum 15,574
Shell Oil 5,112
Skelly Oil 807
Standard Oil (Cal.) 7,832
Standard Oil (Ind.) 7,294
Standard Oil (Ohio) 3,422
Sun Oil 3,894
Superior Oil 639
Tesoro Petroleum 543
Texaco 10,909
Total Petroleum 162
Union Oil of California 3,066
United Refining 67

1975

Debt Preferred
(%)
27
43.5
51
35
26
26
38.5
65
52
32
47
49
30
58.5
17
8.5
17
10
33
18
21
33
32
20
21
40.3
40
39
26
55
27
21
15
25
23.5
12
17
23
57
17
15
40
20
20
24
34
(1) Includes long-term debt, preferred stock and common
(%)
29
0.5
0
15
15
0
0.3
1
11
0
0
7
0
0
0
1.2
0
0
3
0
0
0
0
0
0
0.2
0
19
0
6
0
0
5
0
0
0
0
0
0.3
22
0
19
0
15
13
0
stock net

Common Equity
Net Worth
<«
44
56
49
50
59
74
61.2
34
37
68
53
44
70
41.5
83
90.3
83
90
64
82
79
67
68
80
79
59.5
60
42
74
39
73
79
80
75
76.5
88
83
77
42.7
61
85
41
80
65
63
66
worth.
SOURCE: Balance Sheets as of December 31, 1975.
      II-49

-------
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--   (k)
                            e          d-




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
            d


           t  = marginal tax rate of the firm.



In determining the weighting of debt and equity for the weighted average



cost of capital, the book values of long-term debt and the net worth of stock-



holders' equity as of December 31, 1975, were employed.  The market value of



debt is not easily determined for most corporations.  This approach does not



significantly affect the estimate of the weighted average cost of capital.



     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.
                                      11-50

-------
The tax rate does vary significantly between firms.   Thus, in estimating




the cost of debt, the effective tax rate for the year 1975 has been used




as the marginal tax rate.




     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 are to buy stock.




     One method is to calculate the actual rates of  return achieved by




shareholders 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




ancl 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 revenues 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
                                     11-51

-------
risk-adjusted rate of return.  By owning a portfolio of stocks, an investor




can partially eliminate the risk involved in owning one stock.  The 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" (3).   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 of investment risk;  stocks which have




higher betas have higher costs of equity.  The cost of equity can be




determined by using the following relations:





                  ke = rf + (rm - V ^


where:     k  = cost of equity




           r  = risk-free rate; usually the U.S.  Treasury Bill rate




           r  = total market return
            m



           3  = beta of the stock.




     The risk-adjusted method was used to calculate the cost of equity to




be used in the economic impact analysis.  The approach seemed most appropriate




because it measures the risk of an investment while eliminating instability in




individual stock prices.  The risk-free rate has varied from 4.35% in 1971 to



7.01% in 1974 averaging 6.05% over this period.  The total market return from




1928 to 1965 averaged 9.3%.  The market return ranged from 10.9% in 1971 to



18.2% in 1974 averaging 13.2% from 1971 to 1974.   Using the beta for each




company and the appropriate values for the risk-free rate and the market return,




the cost of equity was calculated for different investment periods from 1971 to




1974.




     Estimate of the Cost of Capital for the Petroleum Industry




     Given the range in the cost of equity for each firm and a cost of debt of





                                      11-52

-------
9.5%, a weighted average cost of capital was calculated.  To arrive at an




estimate of the cost of capital for the industry, several weighting methods




were considered:  weighting by total long-term capital and total revenues.




The arithmetic mean was also calculated.  The estimated industry cost of




capital ranges from a low of 10.3% (weighted by long-term capital)  to a high




of 10.6% (weighted by total revenue), with an average of 10.5%.  (See Table 11-26




for an example of the calculations.)  Several oil companies contacted during




this analysis indicated that they currently consider their cost of equity to




be about 15%, implying a cost of capital of approximately 12%.  Thus, an




industry cost of capital of about 11% seems reasonable.




     Several words of caution about the cost of capital for an industry should




be added at this point.  Although 11% 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 7.8% to 12.8%.  Rather than saying that




the cost of capital of the industry is about 11%, it may be more appropriate




to state that the cost of capital in the industry ranges from 7.8% to 12.8%.




     Furthermore, interest rates and stock prices have fluctuated widely in the




past 36 months.  As shown in Table 11-27, common shares of many of the 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
                                       II-53

-------
                                  TABLE 11-26
     Firm
     Amerada Hess
     Apache Corp.
     Apco Oil
     Ashland Oil
     Atlantic Richfield
     Belco Petroleum
     British Petroleum
     Buttes Gas and Oil
     Charter Company
     Cities Service
     Clark Oil & Refining
     Commonwealth  Oil
     Continental Oil
     Dome Petroleum
     Exxon
     Getty Oil
     Gulf Oil
     Gulf Oil Canada
     Husky Oil
     Imperial Oil
     Kerr-McGee
     Kewanee Industries
     Louisiana Land Exp
     Marathon Oil
     Mobil Oil Corp.
     Murphy Oil
     Natomas Company
     Occidental Petroleum
     Pacific Petroleums
     Pennzoil
     Phillips Petroleum
     Quaker State  Oil
     Reserve Oil & Gas
     Royal Dutch Petroleum
     Shell Oil
     Skelly Oil
     Standard Oil  (Cal.)
     Standard Oil  (Ind.)
     Standard Oil  (Ohio)
     Sun Oil
     Superior Oil
     Tesoro Petroleum
     Texaco
     Total Petroleum
     Union Oil of  California
     United Refining
CALCULATION OF COST
Average' '
Beta
1.05
1.10
.90
.95
.90
1.05
.75
1.25
1.25
.85
ig 1.30
1.10
1.00
1.10
.90
.85
.90
.75
.85
.90
1.00
1.30
.oration 1.15
.85
.95
1.30
1.10
im 1.05
1.10
1.30
1.10
1.15
1.15
:um 0 . 70
0.95
0.50
1.05
0.90
0.85
0.75
1.00
1.25
0.90
1.05
>rnia 0.90
1.05
OF CAPITAL^1'
(2)
Tax Rate
/ 01 \
\ to )
60
38
—
51
61
37
90
50
70
41
—
—
64
37
74
62
74
45
47
49
41
47
46
73
75
61
76
74
43
30
55
49
48
70
42
47
45
60
32
64
45
34
54
47
50
50

Cost of(3)
Equity
13.6
13.9
12.5
12.9
12.5
13.6
11.4
15.0
15.0
12.1
15.4
13.9
13.2
13.9
12.5
12.1
12.5
11.4
12.1
12.5
13.2
15.4
14.3
12.1
12.9
15.4
13.9
13.6
13.9
15.4
13.9
14.3
14.3
11.1
12.9
9.6
13.6
12.5
12.1
11.4
13.2
15.0
12.5
13.6
12.5
13.6
Cost of(3)
Capital
  9.9
 10.3
 11.0
  9.5
  9.9
 11.6
  9.3
  8.3
  7.8
 10.0
 12.6
 11.6
 10.3
  9.3
 10.9
 11.4
 10.8
 10.8
  9.7
 11.1
 11.6
 12.0
   .4
   .2
   .7
   .7
11.
10.
10.
10.
 9.3
 8.3
11.7
10.2
11.3
12.3
12.8
 9.0
11.2
 9.1
 12.2
 10.5
  8.9
  9.6
 12.0
 10.7
 10.9
 11.5
 10.3
 10.6
(1)  Based on 1971-1974 average market return of 13.2% and U. S. Treasury Bill
    rate of 6.05%.
(2)  SOURCE:   Value  Line,  July 23,  1976.
(3)  SOURCE:   Arthur D. Little, Inc.,  estimates based on cost of debt
    of 9.5%.
                                         11-54

-------
                               TABLE II-27
Atlantic Richfield
Cities Service
Continental Oil
Exxon Corp.
Gulf Oil Corp.
Kerr-McGee Corp.
Mobil Oil Corp.
Pennzoil
Phillips Petroleum
Shell Oil Co.
Signal
Skelly Oil Co.
Southern Natural Gas-
  5/73 into Southern
  Resources, Inc.
Standard Oil (Cal.)
Standard Oil (Ind.)
Sun Oil Co.
Superior Oil Co.
Texaco, Inc.
Union Oil  (Cal.)
Tenneco
OIL STOCK
High
113 3/4
62 1/4
58 1/2
99 3/4
25 1/4
92 1/2
56 1/2
30 1/2
71 3/8
72 7/8
22 3/4
73
—merged
Natural
55 1/2
36 5/8
45 7/8
61 3/4
304
32 7/8
56 3/4
24 3/4
PRICES
Low
73
32 3/4
29
54 7/8
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
11
 5
 5
 5
 3
16
 3
 5
 7
 6
 2
 7

 7
 3
 6
 4
15
 3
 4
 6
            Closing
 20
 42 1/4
 44
 63 1/8
 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
SOURCE:  Company Annual Reports, Wall Street Journal, Value Line
                                         11-55

-------
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  overall  cost




of capital.  However, if the industry is moving beyond the "optimal" capital




structure, the cost of capital will rise.  Furthermore, given the fact that




interest rates were high in 1973 and 1974, one might expect a continuing 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 7.8% to 11.0% range,




theoretically, more firms will be able to make the investment.   If the




industry cost of capital lies in the 11.0% to 12.8% range, fewer firms can be




expected to make the investment.  Furthermore, estimates of the cost of




capital provided include international operations and other aspects of the




industry's business such as refining, marketing and chemicals in addition to




domestic onshore oil production.  Current standards of financial reporting do
                                     H-56

-------
not provide sufficient data to estimate the cost of capital for domestic




onshore production by itself.
                                      II-57

-------
                   III.  PROPOSED EFFLUENT LIMITATIONS








1.  Interim Final Limitations




     In the Federal Register of October 13, 1976, the U.S. Environmental




Protection Agency (EPA) published interim final effluent guidelines for




segments of the onshore oil extraction industry.  The industry segments




for which guidelines were published were:




     •  onshore oil wells producing more than 10 barrels per day




        of oil,




     •  coastal platforms landward of the Chapman line,




     •  onshore oil wells whose produced formation water is used




        "beneficially."




     A guideline was not published for onshore oil wells with an average




daily production of less then 10 barrels per day called stripper wells.




The BPT limitations on oil and grease are summarized as follows:




     •  onshore, non-stripper wells - no discharge;




     •  coastal platform   - 72 mg/1 daily maximum;




     •  beneficial use - 45 mg/1 daily maximum  (no discharge other




        than for the beneficial use).




     These effluent limitations are intended to represent the degree of




effluent reduction attainable by the application of the best practicable




control technology currently available (BPT) for the industry subcategory.




     The interim final BAT and new source effluent limitations differ  from




BPT only in that the coastal platforms have a zero discharge requirement.




This report is an evaluation of the economic impact to the oil extraction




industry segments of complying with the effluent limitations.
                                III-l

-------
2.    Current State Regulations




Introduction




     An understanding of current state regulations for the disposal of




brine from oil production is important in determining incremental compliance




costs.  Any implementation of stricter regulations must be examined in




comparison with the present regulations and practices.




     Arthur D. Little, Inc., and Jacobs Engineering Co. both have conducted




surveys of the current state regulations, employing essentially the same




techniques.  Information was obtained by telephone interviews with




representatives of the state regulatory agencies.  In addition, the Arthur




D. Little, Inc., survey involved a mail follow-up to confirm and elaborate




on the information obtained by telephone.




     Although there are some differences between the ADL and Jacobs findings,




the results of the two surveys are generally consistent.  There are, however,




differences in several states between the regulatory requirements and the




actual practices.  These differences have been identified in the




summaries  of  the state regulations and in Table III-l.




      The  following table, Table III-2, summarizes state brine  disposal  prac-




tices, focusing on reinjection.  Note that although reinjection of




brine may  be  required, it is infrequent  that 100% of  the brine actually




is reinjected.
                                      111-2

-------
                                                      TABLE  III-l
                                             STATE  BRINE DISPOSAL PRACTICES
State
Texas
Louisiana
California
Oklahoma
Wyoming
New Mexico
Alaska
Kansas
Mississippi
£} Colorado
M
,', Montana
Florida
Utah
Illinois
North Dakota
Arkansas
Michigan
Ohio
Kentucky
Ponncyl vani^a
West Virginia
Crude Oil
Production
1975
(MM bbl's)
1,222
651
322
163
136
95.1
69.8
59.1
46.6
38.1
32.8
41.9
42.3
26.1
20.5
16.1
24.4
9.6
7.6
3.3
2.5
Reinjectio
Existing
Wells
no
no
yes
yes
no
no

no
no
no
no
yes
no
no
no
no
yes

no
nn
?
n Required
New
Wells
no
yes
yes
yes
no
no

yes
yes
no
no
yes
no
no
no
no
yes

yes
no
?
Number of
Oil Wells
1975
160,603
27,734
% Brine
Reinjected
94%
66. 66« onshore
0% offshore
AT n9Q lover 90/oOnshore
41,029 |g6
-------
                     TABLE III-2

               SUMMARY OF STATE REGULATIONS


Alabama

1. surface discharge:  not  allowed.

2. evaporation ponds:  impervious pits for storage only.

3. reinjection:  permitted;  strict regs (since above methods not allowed
   for disposal, reinjection seems to be required); annular injection
   specifically allowed with approval.

Alaska

1. surface discharge:  no rules (allowed, but water must be treated to
   EPA standards).

2. evaporation ponds:  impervious pits for storage only (evap. ponds
   ineffective in Alaska).

3. reinjection:  no rules re disposal - decisions made case-by-case;
   there are regulations for secondary recovery (mandatory reinjection
   could cause problems because of different salt contents).

Arizona

1. surface discharge:  not allowed.

2. evaporation ponds:  allowed if impervious.

3. reinjection:   permitted; strict regs.

Arkansas

1. surface discharge:  not allowed  (allowed  if fresh water, case-by-case
   decisions).

2. evaporation ponds:  allowed with  approval (law - no, practice  - yes).

3. reinjection:   permitted, strict  regulations  (must be to non-productive
   oil  or gas  zones  or to zones  of  brackish  water; rarely  to  depleted  oil-
   bearing strata).

California

1. surface discharge:  Jacobs  survey:   ocean discharge with  treatment;
   phase-out 1977.   ADL  survey:   not allowed.

 2.  evaporation ponds:   impervious evaporation pits allowed by permit;  per-
    colation  pits allowed in certain areas by permit;  (evap.  ponds allowed
   where no  underlying fresh water  deposits  - west side of San Joaquin
    Valley).

 3.  reinjection:  permitted, strict  rees (brine must be returned to the

                              III-4

-------
   producing stratum or to a similar-water  zone or  oil  core.   If  there
   are high boron or IDS counts,  brine must be reinjected.   No published
   regs).

Colorado

1. surface discharge:  allowed only in areas where  low  salinity water is
   produced - water discharged for beneficial, agricultural uses;  permit
   required.  (Colorado Water Pollution Control Commission defines accept-
   able quality.)

2. evaporation ponds:  for storage only; must be lined; permit required.
   (Unlined ponds may be permitted upon inspection; factors:  salinity
   of water, topography of land,  location of source.)

3. reinjection:  permitted; strict regs (use of strata  other than pro-
   ducing must be approved - water must generally be of equal or lesser
   quality than reinjected brine).

Florida

1. surface discharge:  not allowed.

2. evaporation ponds:  temporary disposal in pits with permit (must be
   closed containers).

3. reinjection:  Jacobs' survey:  permitted; strict regs; ADL survey:
   required; must be reinjected to non-fresh water stratum.

Illinois

1. surface discharge:  not allowed,

2. evaporation ponds:  must be impervious; permit required  (majority of
   producers dispose of brine in lined  pits).

3. reinjection:  permitted; strict regs  (must  not contain  frosh wuLer;
   cement casing).

Indiana

1. surface  discharge:  not allowed.

2. evaporation ponds:  allowed if  impervious;  permit required.

3. reinjection:  permitted; strict regs.

Kansas

1. surface  discharge:  not  allowed.

2. evaporation ponds:  allowed with permit,  for  emergency  only  (new
   leases:  must provide  storage  facilities  and  dispose by reinjection;
   existing leases:   ponds  gradually  being phased  out.  All  evap.  ponds
   still  in use  are in areas  where grpundwater supplies are  not usable
   due  to lack of  volume).

                                 III-5

-------
3. reinjection:   permitted;  strict regs (must be disposed of in original
   stratum or salt-water stratum;  since 1970, required except by variance
   where low chloride content).

Kentucky

1. surface discharge:  ADL survey:  not allowed; Jacobs survey:  allowed
   with approval, based on final quality of receiving water.

2. evaporation ponds:  ADL survey:  not permitted for new wells; permit-
   ted for existing wells in some circumstances.  Jacobs survey:  no
   rules.

3. reinjection:   permitted:  strict regs ( required for new wells or
   when necessary - i.e., high  brine production - for existing wells;
   stratum must be approved by  Div. of Water - Kentucky Geological Survey),

Louisiana

1. surface discharge:  allowed  into tidal waters; into streams with
   permit; oil limit 30 ppm (.3% onshore production to rivers and streams,
   31.04% to non-potable water  bodies; no offshore-produced brine to
   rivers and streams, but 78.78% of offshore-produced brine disposed of
   in non-potable water bodies  - tidally affected, brackish, or unsuit-
   able for human consumption or agricultural purposes).

2. evaporation pits:  disposal  pits allowed with permit (case-by-case
   approval).

3. reinjection:  permitted; strict regs (not required; must be to salt-
   water zone).

Maryland

1. surface discharge:  NPDES permit required; no regulations.

2. evaporation ponds:  no rules.

3. reinjection:  no  specific rules regarding brine disposal; no permit
   or approval required.

Michigan

1. surface discharge:  not allowed.

2. evaporation ponds:  storage pits on approval  (disposal in pits not
   allowed and also  impractical,  as evap. rate  less than precipitation
   rate).

3. reinjection:  permitted, strict regs; annular  injection  specifically
   allowed with  approval  (required by administrative  regulation - any
   disposal method other  than reinjection must  be approved; reinjection
   prohibited to fresh water or chemical industry strata; only  exceptions
   to reinjection are beneficial  uses.as dust control and ice  removal
   from roadways).

                                 III-6

-------
Mississippi

1. surface discharge:  ADL survey:   only fresh water of loss than
   250 ppm - fed. std. - or less than 10,000 ppm - state std.  -
   may be discharged; Jacobs survey:  permit required;  may be  discharged
   to waters of 10,000 ppm or greater.

2. evaporation ponds:  impervious disposal pits allowed with permit
   (approval especially extended to those wells in isolated areas).

3. reinjection:  permitted; strict regs; annular injection specifLcally
   allowed with approval (required for new and existing wells, but for
   existing wells, under certain conditions, evaporation pits  may be
   allowed; must be to non-productive or non-fresh-water stratum).

Missouri

1. surface discharge:  NPDES permit required; no regulations.

2. evaporation ponds:  no rules.

3. reinjection:  permitted; vague regulations, must submit "pertinent
   data" for permit; decisions made case-by-case.

Montana

1. surface discharge:  not allowed  for brine;  "fresh water" discharged in
   central Montana    (3,000 ppm considered  reasonably fresh; cattle will
   tolerate 10,000 ppm - surface discharge  is  for beneficial use).

2. evaporation ponds:  allowed with permit  (must be lined).

3. reinjection:   permitted; strict  regs  (prohibited to fresh water
   stratum).

Nebraska

1. surface discharge:  vague  regulations; not  allowed  if  unfit  for domestic,
   livestock,  or irrigation use; NPDES  permit  required.

2. evaporation ponds:   impervious  retaining pits  allowed  with  permit.

3. reinjection:   permitted;  strict regs.

Nevada

 1. surface discharge:   not allowed.

 2. evaporation ponds:   disposal pits  allowed if impervious.

 3.  reinjection:   permitted;  strict regs (more stringent  rules for second-
    ary recovery).
                                  III-7

-------
New Mexico

1. surface discharge:  brine only into waters   10,000 ppm;  "fresh
   water" allowed to discharge - only small amounts produced (not
   allowed).

2. evaporation ponds:  approval necessary (strict requirements, no
   applications since 1967).

3. reinjection:  permitted; strict regs (not required; must  be returned
   to producing stratum; widespread except in areas where no fresh
   water, then evap. ponds or discharge to natural salt lakes).

New York

1. surface discharge:  vague regulations; method of disposal must be
   approved;  NPDES permit required.

2. evaporation ponds:  storage pits with approval.

3. reinjection:  permitted; strict regs (more stringent rules for second-
   ary recovery).

North Dakota

1. surface discharge:  not allowed.

2. evaporation ponds:  impervious storage pits allowed with permit.

3. reinjection:  permitted; strict regs (not required; strata must be
   approved).

Ohio

1. surface discharge:  not allowed; few minor exceptions, i.e., dust
   and ice control in rural areas.

2. evaporation ponds:  impervious storage pits allowed (trying to elimi-
   nate  them).

3. reinjection: permitted; vague regs; interval must be approved; annular
   injection specifically  allowed with approval  (must be to producing
   stratum or stratum of similar of higher salt content).

Oklahoma

1. surface discharge:  not  allowed.

2. evaporation ponds:  ADL survey:  not allowed  for brine disposal;
   pits  containing  salt water must be emptied and  leveled; Jacobs survey:
   allowed if  impervious;  permit required.

3. reinjection:  permitted; strict regs  (required  for all wells; must be
   injected  to salt  water  zone).
                              III-8

-------
Pennsylvania

1. surface discharge:  industrial discharge permit required; allowed if
   free of oil and petroleum residues; allowance of surface, discharge to
   streams based on fact that very small amounts of water are produced
   (measured in gallons/day) by individual wells; vague regulations -
   new rules being formulated.

2. evaporation ponds:  storage pits must meet requirements; limits on
   turbidity if overflow.

3. reinjection:  no rules; new rules now being formulated; must show
   that "pollution is improbable" - vague.

South Dakota

1. surface discharge:  not allowed for brine; minor amount "fresh water"
   discharged - considered beneficial.

2. evaporation ponds:  need approval.

3. reinjection:  permitted; strict regs.

Tennessee

1. surface discharge:  not allowed.

2. evaporation ponds:  disposal pits allowed with approval.

3. reinjection:  permitted; strict regs; annular injection specifically
   allowed with approval.

Texas

1. surface discharge:  discharge to tidal waters allowed; discharge to
   streams allowed where quality high; gradually phasing out all surface
   discharge; small amount quality water discharged for beneficial uses.

2. evaporation ponds:  allowed if impervious,; permit required.

3. reinjection:  permitted; strict regs (must be to salt-water zone).

Utah

1. surface discharge:  not allowed for brine; "fresh water" discharged for
   agric. use.

2. evaporation ponds:  allowed if impervious  (technically allowed only
   for emergencies).

3. reinjection:  permitted; strict regs (to producing stratum or to stratum
   of equivalent or greater salt content).
                              III-9

-------
Virginia

1. surface discharge:   permit required;  must meet water quality standards
   for industrial discharges; vague regs.

2. evaporation ponds:   no rules.

3. reinjection:  permitted;  strict regs.

West Virginia

1. surface discharge:   permit required;  must meet water quality standards
   for industrial discharges; no discharge of water unfit for general
   use may be made (state lets small strippers dump brine to ground,
   although state law requires reinjection).

2. evaporation ponds:  no rules (no information).

3. reinjection:  required; vague regs formation must be approved.

Wyoming

1. surface discharge:  allowed if quality within limits; permit required;
   oil content not to exceed 10 ppm  (surface discharge of brine not
   allowed; fresh water may be discharged - beneficial use - stock; no
   specific quality guidelines).

2. evaporation ponds:  no rules (lined  pits not required; case-by-case
   approval of such disposal).

3. reinjection:  permitted;  strict regs (trend  towards reinjection; may
   be  injected to any stratum containing water  of  a poorer quality).
 SOURCE;  Arthur D. Little, Inc., estimates
                               111-10

-------
3j,	Cost of Pollution Abatement Systems




     The costs of compliance with the potential effluent guidelines have been




developed by Jacobs Engineering, Inc., under contract to EPA.  Jacobs collected




costs of reinjection and treatment costs as a function of water capacity at




existing facilities in several states and developed engineering cost estimates




in situations where the desired technology is not currently in use.




     Using the cost data points provided by Jacobs, functional relationships




were developed between the compliance costs and water volumes by a least




square fitting of the function to the data point.  The functions were of




the following form:




     CC = Constant for 0 < CAPTY <_  100 B/D




     CC = A  (log CAPTY)8 for 100 <_  CAPTY  (in B/D)




where




     CC:  Capital cost or operating costs  of the treatment and




          disposal equipment (in 1975$),




  CAPTY:  The capacity of the installation,




    A,B:  Parameter values found through least squares regression.




The functions then were used in the economic impact analysis.  Tables  III-3




and III-4 summarize the cost functions.






     Reinjection costs were developed for each of the states studied.  In the




cases of on-land  Louisiana and Texas, there were not enough data points to




warrant a distinction between the states,  and they were combined.




     The treatment regulations divided the onshore producers into stripper




wells (less  than 10 barrels per day),  non-stripper wells and beneficial uses
 1EPA  Contract No. 68-01-3278, J.E.C. Job No.  27-1460.
                                   III-ll

-------
                                  TABLE  III-3
                          CA? HAL >051S FOR L'.: : >. SAL
                             OF OIL FIELD EFFLUENT
                               (Sl.OOO's of 1975  $)
                              10
Reinfection
  Wyoming
  Texas/Louisiana  (on land)
               •a
  Pennsylvania
     Case I
     Case 11


   Texas (platforms)
   Louisiana (platforms)
 Dispos^i 1  :Lq\iipr.ient  Capacity	
     (bbl/«iay ot water)
1C,.        500      1,000       10.000
75
30
28
15
400
400
80
46
52
24
400
400
140
115
130
47
420
420
175
160
190
61
500
470
300
410
470
110
1,600
1,680
 Treatment
   Non-Stripper & Beneficial    62
   Platform                     53
 62
 53
62
80
 96
125
198
340
 a.  Case  I assumes water  flooding  not  now practical and Case II assumes it is in
     practice.  Case  II  predominates in Pennsylvania.
  SOURCE:   Jacobs  Engineering,  Inc.
                                               Revision Date: 8 July  1976
                                   111-12

-------
                                  TABLE  II1-4
                          OPERATING COSTS FOR 1)ISL'OSAL


                              OF OIL. FIELD EFFLUENT^


                               ($l,000's  of 1975  $)
                                          Disposal Equipment. Capacity
Reinjection


  Wyoming


  Texas/Louisiana (on land)


  Pennsylvania


    Case I


    Case II




                    *
  Texas  (platforms)

                        *
  Louisiana  (platforms)




 Treatment





  Non-Stripper & Beneficial   13


   Platform

10
8
8.5
7.6
5
26
16
13
8
(bbl/day of water)
100 500 ltOOO
8.8 15 18.5
9.5 18.5 24
14 33 46
6.5 13 16.5
26 27 32
16 16.5 22
13 14 18.5
8 10.3 15.5

10,000
32
43
100
32
122
134
49
47
 a.  Case  f assumes water  flooding  not  now practical  and Case II assumes it is in

     practice.  Case  II  predominates  in Pennsylvania.
 *
  New costs from Jacobs are higher.
 SOURCE:  Jacobs Engineering,  Inc.
                                                  Revision Date: 8 July 1976
                                          111-13

-------
on  land, and near coastal platforms. The impact of potential regulations on stripper




wells has not been evaluated in this report.   The platforms are assumed




to  use a dissolved air flotation unit.  The  larger on-land producers are




assumed to use dissolved air flotation units up  to 2,500 BPD of water and




induced air flotation for units of greater than  2,500 BPD water flow.




     The assumption was made that virtually  none of  the required




facilities for compliance with a reinjection or  treatment  guideline  are




currently on site. To the extent that usable equipment is currently  on  site,  the




compliance costs would be overstated.
                                   111-14

-------
              IV.  ECONOMIC IMPACT ASSESSMENT METHODOLOGY









1.   Scope of the Analysis




     This chapter describes the methodology used to estimate the economic




impact of effluent limitations for the discharge of produced formation water




from onshore oil wells with a production greater than 10 barrels per day.




The regulation is applicable to all U.S. wells on shore of the Chapman Line.




However, the economic impact analysis is confined to wells in Texas, Louisiana,




and Wyoming, as representative of non-complying production.  While classified




as onshore,  there are a number of wells in bays and estuaries producing to




platforms inside of the Chapman Line.These "onshore" platforms have  been  treated




as a separate category.




     The analysis used the following measures of economic impact:




     •  average increase in production cost




     •  foregone production




     •  total capital cost of pollution control




     •  number of wells closed rather than brought into compliance




     •  loss of reserves




     •  implied increase in crude oil prices




     The costs of compliance with the effluent limitation were estimated by





the engineering contractor under a  separate contract with  EPA.   Regression




analyses were made of the engineering data in order to represent it as cost




functions (see Chapter III).
 Contract Number 68-01-3278, JEC Job No. 27-1460.
                                   IV-1

-------
     The production cost models were developed for this contract by revising




and updating the production costs in Bureau of Mines Information Circular




IC8561 to 1975 (see Chapter V).  The production profiles were also developed




by the engineering contractor estimating the numbers of wells and their pro-




ductivity in each state.




     The model of producer response to the regulation using a discounted cash




flow analysis of the decision whether to investLn reinjection equipment was




developed under this contract and applied to the non-complying production




profiles of the three states.  The production unit in the analysis is a




cluster of producing wells on one or adjacent leases under the control of one




operator and which would require at least one reinjection unit.  The produc-




tivity values are averages for the production unit.




     Given inherent uncertainties about future cost and price conditions, such




as world crude prices,  cost  of capital, and production decline  rates, a range of




possible impacts was examined  through sensitivity analysis and  expressed in




terms of high, most likely,  and  low estimates.






2.  Model of Producer Decision Making




     An economic impact analysis requires a model portraying, the response of




producers to the regulation.   If the oil well operator were able to increase




prices sufficiently to  cover all of the costs of compliance with the effluent




guidelines, the only economic  impact would be higher crude oil prices.  However,




as discussed in Chapter II,  crude oil pricing patterns do not allow operators




to change crude prices  in  the  face of the higher production costs resulting




from the effluent guidelines.  The producer must decide whether the well will




continue to be economically  viable in spite of the higher costs.  Therefore,




the base case  for economic impact analysis assumes that producers will absorb
                                       IV-2

-------
 all  pollution  control  costs.  A  sensitivity  analysis deals with  the  case  in




 which producers are able  to pass on  their  increased costs to  the  consumer.




     To minimize the cost of  compliance  that he will have to  absorb,  each




 operator will  try  to find the solution which suits him best at that




 moment.  For example,  he mny  pool his efforts with oilier operators,  or lit- may




 be able to reduce his  cost of compliance by buying used equipment rather  than




 new  equipment.




     Given the wide variety of options, it is impractical to  allow for all possible




 operators' decisions.  Therefore, two simplifying assumptions  have been made:




     •  operators of individual production units would not pool their




        efforts in trying to comply with the regulation; and




     •  operators would base their decisions of whether to comply with the




        regulation on  a rational economic basis alone.




     The first assumption will result in a "worst case" (i.e., high) estimate




of the potential impact.  Economies of scale apply to the treatment equipment




required to comply with the proposed regulation.  Therefore,  considerably




lower costs of compliance, on a per unit basis, are possible if operators




pool their efforts by combining investment in one large treatment unit, rather




than several smaller units,  as assumed in the analysis.




     The second assumption does not imply that some producers would continue




 production if  they knew it to be economically irrational.  Rather, it is




possible that where the impact analysis methodology specifies an exact




definition of economic viability, in reality some small producers may not know




precisely whether continued production makes economic sense.   It is also




possible that a producer may wish to continue production of an otherwise sub-




economical well for factors other than simply the profitability of the well




itself.   The rational  economic decision assumed in the impact analysis is




restricted to the economic viability of the individual production units.





                                    IV-3

-------
     The assumption about rational economic behavior of operators not currently




complying with the regulations implies that:




     •  an operator will first estimate how much lie will have to invest in




        formation water treatment and reinjection facllJties, and what the




        additional operating costs will be if he comes Into compliance with




        the effluent guidelines;




     •  next, he will estimate how much oil production to expect over the




        remaining life of his production unit;




     •  he will then assess whether the production unit's remaining production




        can be expected to pay for the additional costs necessary for the




        treatment equipment;




     •  if he finds that the remaining production will not. pay for the invest-




        ment and operating costs for the treatment and disposal equipment, he




        will shut in his production unit;  this will result: in the loss of those




        barrels of oil which would have been otherwise produced;




     •  if, on the other hand, he finds that the remaining production will pay




        for the additional costs, he will  continue to produce after having




        installed the required equipment;  some of the potential production will




        still be lost because the increase in operating costs will result in a




        decrease in the  life of  the production unit.
                                    IV-4

-------
3.   Analysis of Production Units




     The decision process of the producer faced with the effluent limitation




is modelled by the cash flow program depicted in Figure IV-1.




     As background for decision making, the following parameters are con-




sidered for each state:




     •  production costs as a function of production unit size,




     •  cost of compliance (investment cost) as a function of size,




     •  fiscal variables (e.g., taxes, royalties, etc.),




     •  price assumptions,




     •  cost of capital.




     Within this set of parameters, the cash flow is analyzed for a range of




production unit sizes and production decline rates.  These variables are set




at initial values at the beginning of the program and changed with successive




cash flow analyses.




     The impact of pollution control is first assessed by determining a pro-




duction unit's economic life both with and without the additional operating




costs attributable to the pollution control equipment  (Table IV-1, sections 1-2),




The economic life of a lease or production unit will terminate in the year in




which gross revenue from oil production, decreased by royalty and state tax




payments, is just equal to the operator's out-of-pocket operating costs




 (i.e., his variable costs).  Lost potential production as a  result of a




shortened life is recorded  (Table IV-1, section 3).




     Impact of pollution control is further analyzed by establishing the




minimum well productivity  (for the given production decline  rate) required to
                                     IV-5

-------
                                                      Figure  IV-1
                                                  COMPUTER FLOW DIAGRAM
                                  START
                             Read Input Data
                           Initiate Production
                                Unit Size
                         Next  Production Unit Size
                                   1
J

1
Calculate E
Without and
Operati
line Rate
»

conomic Life
With Added
ng Costs
1
1
Calculate Loss
Production due
Operating
in Potential >
to Added
Costs
                         Investment  in Reinjection
                         Facilities  in First Year
                         First  Year  of Production
                For This Year,  Calc.  Production, Cashflows
              For Year of Investment,  Calc. Present Value of
                            After Tax Cashflows
                          1 Production Unit Sizes
                       For this year calculate:
                           Oil 4 Gas Production
                           Gross Revenue from Sales
                           Royalty Payment and State Taxes
                           Working Interest  (-2 - 3)
                           Depreciation and Depletion Allowance
                           Taxable Income  (  » 4 - 5)
                           Federal Income Taxes  (FIT)
                           FIT Decreased by Previous Year's Loss
                           After Tax Income  ( - 6 - 8)
                           Cashflow  ( - 4 - 8)
                                                                             For the Year of Investment calculate:
                                                                             Present Value of This and Previous Years
                                                                             Cashflows
                                                                 Calculate Maximum
                                                             Loss in Potential Production
                                                               Due to Early Shut-in
SOURCE:
           Arthur D.  Little,  Inc.
IV-6

-------
                                 TABLE IV-X

                                SAMPLE STATE
                                 Section 1

              Producing Life Before Investment in Reinjection (years)
                        Average Welldepth: 4000 ft.

                        Initial Productivity (barrels  per day):

                           25          50          100          200
Decline Rate
    .05
    .10
    .15
    .20
    .25
51.4
25.3
16.6
12.3
 9.6
64.9
31.9
20.9
15.4
12.0
78.5
38.5
25.1
18.5
14.5
90.0
45.0
29.4
21.6
16.9
                                 Section 2

              Producing Life After Investment in Reinjection (years)
                        Average Welldepth:  4000 ft.

                        Initial Productivity (barrels  per  day):

                           25          50          100          200
Decline Rate
    .05
    .10
    .15
    .20
    .25
49.6
24.4
16.0
11.3
 9.3
63.2
31.0
20.3
14.9
11.7
76.7
37.6
24.6
18.0
14.1
90.0
44.2
28.8
21.2
16.6
                                 Section 3

         Loss in Potential Production Due to Added Operating Cost (barrels)
                        Average Welldepth:  4000 ft.

                        Initial Productivity  (barrels  per day):

                           25          50          100           200
Decline Rate
    .05
    .10
    .15
    .20
    .25
12136.6
5772.6
3634.6
2565.6
1924.2
12186.6
5772.6
3634.6
2565.6
1924.2
12186.5
5772.6
3634.6
2565.6
1924.2
                                        0
                                     5772.0
                                     3634.6
                                     2565.6
                                     1924.2
SOURCE;  Arthur D. Little, Inc.
                                   IV-7

-------
                            TABLE IV-1  (cont.)
                                Section 4

              Required Remaining Life to Pay for Investment (years)
                      Average Welldepth:  4000 ft.
                      Initial Productivity (barrels  per  day)

                           25          50          100
Decline Rate
    .05
    .10
    .15
    .20
    .25
6.3
4.0
3.1
2.3
2.1
6.4
4.1
3.1
2.4
2.0
6.4
4.0
3.0
2.6
2.2
                                     200
  ,1
  ,1
13.
 4.
 3.0
 2.5
 2.1
                                Section 5

            Lowest Productivity Which Will Pay for Investment (barrels per day)
                       Average Welldepth:  4000 ft.
Decline Rate
    .05
    .10
    .15
    .20
    .25
                       Initial Productivity (barrels  per day) :
25

2.7
2.9
3.0
2.3
2.1
50

2.7
2.9
3.0
2.4
2.0
100

2.7
2.9
3.0
2.6
2.2
200

3.9
2.9
3.0
2.5
2.1
                                 Section 6

             Loss in Potential Production Due to Early Shut-in  (barrels)
                       Average Welldepth:  4000 ft.

                       Initial Productivity  (barrels per day):

                           25          50          100          200
Decline Rate
     .05
     .10
     .15
     .20
     .25
53312.4
34227.7
27888.0
20348.6
18157.0
54078.8
35428.0
24829.4
29527.8
17585.7
                        53785.4
                        34540.8
                        26426.8
                        25805.5
                        19425.9
                          135573.1
                           35455.5
                           20151.7
                           22630.0
                           18216.3
 SOURCE;  Arthur D. Little, Inc.
                                   IV-8

-------
pay for the investment in the pollution control equipment and the cost of




operating it.  Different production units will be caught at different points




of their producing lives when the compliance date for pollution control




arrives.  Given a unit's production decline rate and average well productivity




at that point in time, there will or will not be sufficient future cash flow




from oil production to cover the cost of pollution control equipment.  If




the present value of the future cash flows is less than the required invest-




ment, the operator will choose to abandon his wells rather than continue to




operate,  and thus forego  the   production which otherwise would have




resulted until the end of the unit's economic life.




     A trial-and-error method is utilized to determine the minimum well pro-




ductivity, or latest year within the economic life of a given production unit,




which justifies an investment in pollution control equipment.  This trial-and-




error process is started by the assumption that the investment is made in




the first year of a unit's life.  Cash flows related to the unit's production




from the first to the last year of its economic life are then calculated and




converted into present values (Table IV-2 presents a typical cash flow for




the ex ante, i.e., no-investment,case).   Next it is determined whether the




present value of all cash flows subsequent to the year of investment are suffi-




cient to cover (i.e., are greater than)  the required investment.  If so, then




the year of investment is advanced until the present value of the remaining




years' cash flows just equal the cost of the pollution control equipment.  This




year may be termed the "last year of investment."  Table IV-3 presents the




cash flow results for a production unit whose last year of investment is the
                                IV-9

-------
                                                                      TABLE  IV-2

                                               EPA FORMATION KATCR DISPOSAL  ANALYSISt RtlNJFCTJON NONST&IPPER

                                                                   SAMELE-^TATE


                                                      CASH FLOW TABUC FOR EX  ANTE  CASE
     ULP'H IN FT
     DLCLTHt KATE
     y t thi nF ADD.  I^v.
     PV. OF AMIH  7AX CAS"FIO-
     ADD. IWVESTNtNT  IN  I
     AD!1. INTANGIBLES IN *
     ADP. o^LuATjkjc; COSTS  l»
     DISCOUNT RATfc
     AVr«ACt f.U.L. PRODUCTIVITY
     ''ATEH/OIL HAHU
                                           -.00
                                            .10
                                         100.00
                                              1
                                     1901185.30
                                        8000.UO
                                            .10

                                            .00
I
M
o
YR GROSS INC STAtf TAX  OP.  CUSTS

 1
                                             TOT,
                                                                      OEPL.ALL. TAXHLt  IN  F.I.  FAX  AFTER TAX CAShFLOn  LIFT COST
 3
 a
 5

 7
 8

to
U

13
H
15
16
17
IB
     ??

     ?1
so
si
     910219.    171702.
     B|9j97.    157286.
     7^7^77.    t'U'i57.
     663'5'|9.    i ?//io | .
     597195.    11166).
      99S95.

     17J53o)
           ''2115.
          *V'jW.    67/06.
          317V4.    6U946.
          1365.I1),    26^41.
                     ?5?7<>.
                17686.
          2'j7u75.    49J5H.     69bKr>.
69085,
696W5.
6968*5,
                                          'U'002.
                                          1 «*»7B.
1761,
                                                        0.
0.
0.
0.
0.
0.
0.
<>.
0.
0.
o.

o!
o.
0,
o.
o.
o.
0.
o,
o,
0.
o.
0.
o,
o.
o.
o.
                                                             339793,
                                                             126167.
                                                         PH955.
                                                         73091.
                                                         4£i9fo1,
                              23990,
                              11623.
                               619?,
                              B1790,
                              666H ,
                              53010.
                              10711 ,
                              2969P,
                              19760.
 2765.
•4480,
0.
o.
0.
0.
V.
0.
o .
o.
0.
0.
u.
0.
0,
"•
0.
0.
0,
0.
os
0.
0.
n.
u.
f.
0,
0.
0.
0.
0.
0.
o.
131120.
5?a«2i ,
I92u U,
435*u3,
3R5291,
339793,
293«UC),
26) "92,
2?W>^ T ,
1939 7«,
1 7?10*.
1 1792",
126167,
IdftSfl?,
*'<9?>5 .
75i)9| ,
5 ~ a 1 u ,
159bU,
3<-J99.
? 599(1 ,
1 fc>>23«
61 92.
f 1 79n ,
666UJ,
5401(1.
107U1 ,
29»<98,
19760.
10*15.
2765.
•4460.
64521.
266) 2",
256)66.
209£|J5,
1849/10,
163101 ,
1 4 } U H 6 ,
12'o756.
109^56.
9'j507,
P2612.
71006.
60560,
51)59,
1 11 6 9 P ,
35u«'t.
? H c' 3 1 ,
22063,
165! ! ,
11S15,
7C19,
r' 9 ; 2 .
39^59,
3J9B9,
25115 ,
19555,
14255,
9485.
5191.
1327.
0.
69«9»,
2A8 JO 1 .
25S»'I7,
2266^9,
200451 ,
176692.
1 5 5 4 0 u ,
1 J6J36.
( i uqpi}(
1 0 5166,
R9'I96,
76923.
65607,
55425,
46P57,
3eil07.
30583,
25901.
! 7PB7.
12175.
7604,
3220,
4255 1 .
34651,
2756S.
21ler),
154 'i 5.
10275,
5624 .
1138.
2150.
6ol25<',
5261 Or',
2»9»fr9,
257258,
227909.
20)194,
177721,
156325.
M7069,
1 19739,
Itllt'll .
90)03.
77470 ,
6 6 '1 9 9 .
55*65,
46655.
3«366.
309U6.
24 ! 9.-1.
1*149,
127) (i.
7P16.
46667,
3P377,
30916.
21200,
16157.
U7I7.
7822.
34|6,
•2699,
1 ,7fl
3.16
3.19
3.21
3.?5
3.26
3.32
3.36
3,41
3.47
3. S3
3.59
3.67
3.75
3.^4
3.94
1.06
4.18
4.32
1.48
4,65
4.84
8. -55
8.78
9.04
9.34
9.66
10.02
10.82
10.86
11.65
     SOURCE:  Arthur D.  Little,  Inc.  estimates

-------
                                                              TABLE  IV-3

                                          EPA  FORMATION  u,ATER DISPOSAL ANALYSIS.«EINJECTION  NOSSTRJPPER
                                                             SAMPLE STATE
                                                  CASH  FLOW TABLE FOR fX POST CASt
                                                  ADDITIONAL INVFSTMENT IN YEAR it,
 OLPTH IN FT
 DCCLTNf  UAT£
 Yf-AK  oF ADD. JNV.
 PV.  OF AFTfcR TAX C«S'JFltM
 A^r>.  I"lvFSTMt NT IN $
 ADD.  I NT ANi; 1 'Jit S IN *
 ADD.  OPCNATjMfi COSTS IN S/YR
 DISCOUNT RAH
 AVFRAlif E.O.I. PKOOUCriVIlY
 i»'ATE.K/OIL RATIO
                                            .10
                                         100,00
                                             26
                                       58175.28
                                       7'>0 00.110
                                            ,00
                                        8000.00
                                            ,10
                                           4.42
                                            .00
 YK  GROSS IMC sTATt TAX CIP. COSTS TOi.
 1
 2
 3
 a
 s
 fc
 7
 B
 9
10
It
I?
13
I'I
15
16
17
 ?W
 ?t
?7
?B

Ju
8|9197.
737077.
       I 7 3 7 'I ,
231
?OH,
I fl 7 'i n 6 ,
     151799.

     122057!
     1 I (Hi&t .
                17176?.
      537175.   103195.

      '135355^

                 67/06.
'I'"I??.


42480.
                           646PS.
                           b'H-riS.
                     69MS5.
                     6 91; fi 5 .
                 1 7686.
                     77oft5.
                     774.K5.
                     77685.
                     77685.
                     77685,
3076').

2'I920.

2016',.

I'lVifl!
1 4 7 I 5 .

I 1919.
10727.
                                      7oi«.
                     5701.
                     51 51.
                     4 (, I ft .
                    20320.


                       13.
CM TOT.OVCWH

         o,
         0.
         o,
         o,
         0.
         0,
         0.
         o.
         o,
         o,
         0.
         0.
         0.
         0.
         0.
         ".
         0.
         o,
         0.
         0.
         o,
         0.
         0.
         0.
         0.
         0.
         0.
                                                                  DEPL.ALL. T»XBLfc  IN F.I.  1 AX   AfTfB TAX
              o.
              o.
                                        134219.

                                        4V185U
                                                   33967*!
                                                   22B75".

                                                   172038,
.--111,
106531,
                     73051),

                     4595o!

                     2396s!

                      61/0,
                     H1771,
                     66625,
                                                          13178,
                                                           4092.
                                                          16070.
                                   0,
                                   0,
                                   0.
0.

o!
0,
0.
II.
n.
o.
•i.
0.
o.
0.
0.
0.
n.
o.

o.
o.
o.
o.
0,
0.
o,
0.
                                                            5*5159.
                                                            359675.
                                                                             172038,

                                                                             12&111,
                                                                              89909.
                                                                              7J'1S(!.
                     24963.
                     1«S99,
                       61 7n,
                     81771,
                                                                              52994,
                                                                              13178.
                                                                             -1 laub,
                               236U89,

                               J8U8?6,
                               1630'4«.
                                                                                         95U70,
70975,
60555,
51135.
12677.
28211,

1 6 « 9 7 .
1 1502,
 700 7,
 2962.
39250.
319BU,
25437,
 6326.
                                                  U.
                                                  o.
                                                  0.
          6979/1,
         288207,
         255763,
         226565.
         20028?.
         176631,
         1553't".
         136186,
         1169'tn,
         103«26.
                                                                                             7689H,
                                          5=596.
                                          16233.
                                          37°86.
                                          3056",
12'I6I ,
 759| ,
 3209,
12521,
346n5,
27557.
 68S3.
 2128.
 1961.
 1964.
    0.
32M69.
2899^6,
257326.
22797?,
201551,
177772.
156371,
1371 I  I .
119776,
104175.
 90)3".
 7/U97,
 66125.
 55«?7.
 Ot675.

 30022,
 ?>>? 16.
 16162,
                                                                                                              7826.
                                                                                                             16677.
                                                                                                             38385,
                                                                                                             30923,
                                                    224U8.
                                                    1420?,
                                                     SOI i,
                                                    •3256.
LIFT C"ST

    1 .78
    3.16
    3,19
    3.21
    3,?5
    3,26
    3.32
    3.36
    3.41
    3.47
    3.53
    3.59
    3.67
    3.75

    3!9'4
    4.06
    4.18
    1.32
    1,17
    1.65

    8'.55
    S.78
    9.01
    8.92
    9.26
    9.87
   10.7i
   11.66
SOURCE;   Arthur D. Little,  Inc. estimates

-------
26th year of Its economic life.   In all years beyond that year, if presented




with the initial investment decision, the operator would decide to abandon




his well and forfeit future potential production (Table IV-1, section 4). The




average well productivity in the last year of investment is the minimum required




to justify investment (Table IV-1, section 5).  The maximum loss in potential




production will occur if the pollution control compliance date forces an




operator to make an investment decision after the last year of investment,




when future production will not cover the investment cost of compliance




(Table IV-1, section 6).  The program calculates this maximum potential lost




production, and these results are retained along with the other  calculated




impacts.




     The program next chooses a new combination of the parameters of production




unit size and decline rate, and recalculates the impacts in terms of lost pro-




duction due to the incremental operating and investment costs required by




pollution control facilities.




     This procedure is repeated until all possible combinations of different




production unit sizes and production decline rates which are believed to exist




in the population of potentially impacted production units of the particular




state in question have been analyzed.
                               1V-12

-------
 A. Analysis of Selected States




     The production profiles of non-complying units in the three states were




 developed by Jacobs Engineering in 1975.  Table IV-4 shows an example of such




 a production profile.  While the regulation will not come into effect  until




 1977, when the profile will be somewhat different, no attempt has been made to




 modify the 1975 populations.  Given the relatively small time interval between




 1975 and 1977, it can be assumed that the production profiles based on 1975




 data adequately represent the number and size of non-complying production




 units in 1977.




     The results of the impact analysis on the model production unit, described




 in the previous section, are then compared to the production profiles of non-




 complying wells.  This comparison establishes which of the non-complying




production  units will have to shut in because the remaining production will




 not pay for the pollution control costs and how much production will be fore-




 gone by those production units which will be able to comply but which will




 experience an increase in operating costs due to the pollution control




 equipment.




     A flow diagram of the computer program developed to apply the results of




 the  production unit analysis to the state's production profiles is shown in




 Figure IV-2.  The cells of each state's production profile show the number of




 production units in the state with the specified number of wells and average




 well productivity corresponding to the location of the cell in the production




 profile's matrix (see Table IV-4).  For the value of average productivity




 and number of wells per unit for each cell, the program first establishes




 whether the production unit contained in the cell would have to be shut in or




 not.  If so, the number of wells shut in and the total production loss are




 calculated;   Table IV-5 shows the results   for Wyoming.  If not, the total




 investment required in pollution control equipment, the production lost due




                                IV-13

-------

                                           TABLE  1V-4
                                             /, F-OHMATJON  WATER DISPOSAL  ANALYSIS?  «ttN-
                                                           STATE
                                                       PK(?0'JtlNr«  '.'MIT CARGOhlLS
(B/D)                                                     (# wells/producing unit)
                     2f      5,      9.     13,     10,     2rJt     *b.     SO.     "0.    100,

                                                                                    0       0
                                                                                            1
I I. SO
1 ? , S 0
I situ-
1 '4 1 So
1S.S'
i rt • j './
£? S . o g
35.00
« S . i' 9
SS.i'O
0 S . U 0
75. CJ
~ r> , U j
^ S . U 0
J25.UO
175.00
225.00
375.00
500, 00
c'
t,
If)
^
'i
c'n
? /
tM
1 1
u
tt
1
/
^
^
/»
i)
it
(J
U
1

1
1
;)
<>
'»
1
3
.'i
i
1
1
2
0
w
0
0
tl
\
1
r.
i
I
5
"
4
1
r
>•
i
0
c
1;
r
I'
'.
I
cf
1
0
u
1
1
(4
0
I
0
(1
1
0
0
0
0
0
0
0
n
0
"
'•<
1
(i
n
1
1
1
'!
• '•
1'
0
(1
1
0
it
vr n
0 i1
u
i r
!
1
'J !
0 ('
u 1
c ''
•>
1 '
l
0 C
0 
-------
                          FIGURE IV-2

                     COMPUTER FLOW DIAGRAM
                       Next cell of State's
                       production profile
             Avg.
         well produc-
_tivity less  than  minimum re-
      jjuired for,  invest^-
                                                         Calculate:
                                                         Number of wells closed   j
                                                         Productive capacity lost
                                                         iPotential production lost]
                                    no
                      Calculate:
                      Required investment'
                      Increase in operat-I
                      ing costs.         j
                      Loss in production j
                      due to increase in
                      operating costs.
            Calculate:                              '
            Average increase in producer's costs (1);
            Average required price increase    (2)  i
            Total number of wells closed
            Total potential production loss         j
                         Print tables
                (Table IV-12 and Table IV-13)
 (1)  Producers absorb all costs (Base Case)
 (2)  Producers pass on all costs
Arthur D. Little, Inc., estimates

                             IV-15

-------
                                                  TABLE IV-5 .

                              EPA FORMATION WATER DISPOSAL ANALYSIS, REINJECTION NONSTRIPPER

                                                 STATE WYOMING
AVI
                                  PRODUCTION  LOST AFTER  REGULATION *Y  CATEGORY
                                     (PERCFK-TAGE OF UNREGULATFD PRODUCTION)
PRODUCING
      18,
   CATEGORIES
25,     35.
 (// wells)
bO,     80.    100,
(B/D)
1-> u •»
2. SO
1 5. bo
1'I.SO
1S.S'.)
1 .'< . 1) ">
2*.-'»P
5 S » (i 0
tl C /> rt
O ^ • " '"^
7 ^ . 0 r,
HS.U..I
9 ri 9 0 ^
j -> r n >\
1 ?•>.'•' 0
1 7 ] • n. c
1^,'V. :'('
H '•.'"'
r-
100
1 00
100
luo
100
100
iJ
2i
18
lrj
^ 3
1 1
10
g
7


***
•
.0
.0
.0
.0
.0
.0
.B
.7
.'h
.'1
.2
.0
•"
?'*
• ^
•'•>
**
**

*****
59.9
'4,9
/! .6
*****
3.0
I'i!^
12. "3
10. fa
9.2
7»
. 5
S»
• f
4 * * -fr 4
*****
*****
• w
/U/4
ti . 0
*****
*****
2.7
2,0
,4, 4 * * ^
*****
1*2
1,1
*****
*****
*****



*****
*****
• "* W
3,5
V 4
•J t '
2.9
*****
*****
2.1
1,6
1 .2
*****
te
*****
*****
,fc
*****


*****
*****
• •»• w
*****
4 A A A dr
T T T ™ ₯
*****
*****
*****
1.7
*****
j ^ ^ ^ ^
*****
,8
06
• '>
*****
*****



*****
*****
«. — • T
*****
*****
1.7
1 .6
It*
*****
*****
,S
*****
• 'J
*****


£ * * * *
^ T T T T
*****
*****

*****
*****
*****
*****
*****
.8
.5
*****
*****
.3
*****


«* A* *
V T ^ T
*****
*****

*****
*****
*****
*****
*****
*****

*****
.3
*****
*****


± ± * A A
T T T * T
*****
*****

*****
* £ * * *
^ ^ T * T
*****
*****
*****
*****
*****
*****
*****
.2
*****
*****


* * * * *
T ~ T ~ ~
*****
.0

*****
7
• f
*****
*****
*****
*****
*****
*****
. 
-------
to the increase in operating cost, and the total remaining production are
calculated on an annual basis.   As with the model production unit analysis,
the calculations are done using a representative range of decline rates
(see Table IV-6).
     For those production units which are projected to make the necessary
investments to come into compliance, an estimate is made of the average
increase in production costs per unit of production.  This cost increase
is calculated using the following formula:
    COST


where
COST
PV [  ]
SUM  (  )
INVMT
1C
t

°Ci
DEP±
PROD.
            PV[INVMT - 1C] - (1-t) x SUM(PV[OCi + DEP±])
             SUM
,  the average per barrel cost  increase for impacted producers
,  the present value operator
,  the summation of annual values
,  the investment in pollution control equipment
,  investment credit on investment in pollution control equipment
,  the federal tax rate
,  annual operating costs for pollution control equipment
,  annual depreciation of investment in pollution control equipment
,  annual production of oil
 The results of this type of calculation for Wyoming are shown in the last
 column of Table IV-6 .
                                IV-17

-------
                                                           TABLE IV- 6



                                            EPA FORMATION WATCR DISPOSAL ANALYSTS*RF-INJECT10N NONSTRJPPfR

                                                          STATE wYOMJNG
                                                      RESULTS OF IMPACT ANALYSIS

                                                    AVERAGE wCIL DEPTH     0 FEFT

                                                      PRODUCERS ABSORB ALL COSTS
<
(-•
oo
RATE
      I97S
                                    TOTAL PRODUCING *CU,S I* 1975                 8656
                                    TOTAL DAILY OIL PRODUCTION IN J975         348605. B/D
                                    197-5 TOTAL APJ RlfStRvfS                      877,1 MMB
                                    HPHNTJHLY IMPACTED PRODUCING NEILS IN 1975  1590
                                    POTENTIALLY JHpACTtD PRODUCTION JN 1975     89853. B/D
                      WILLS CLCSFO
                      PC f 1*P  r>CT TOTAL
       JVE  CAPACITY
19/'j   PCT  IMP   PQT  TOTAL
             RESERVES LOST                  COMPLIANCE COSTS
LOST m  PCT TOTAL  LOST (2)  *CT TOTAL  197* INV  INC OPC08T
 CMM3)                 (MMB)                 f*wj)      (S/8)
  (t)  TOTAL PRODUCTION LUST DUE TO JNCRFASEO OPERATING COSTS

  (?>  TOTAL PRODUCTION LOST OUC TO «tlL CLOSURES
• 0"0
.(00
.120
.t'10
,i";o
90
90
1'I4
i ««
t S
S • ft j
9.03
9.0i
9.0J
1 .04
1 .0"
1 .66
1.66
1.66
li-Jl. J.'l')
U27. J.
-------
              V.  CHARACTERIZATION OF AFFECTED PRODUCTION









1.  Production Profiles




     In December 1975 there were 493,729 producing oil wells in the United




States, including offshore, of which 74% were stripper wells producing less




than 10 barrels per day (Table V-l).  The 132,213 non-stripper wells accounted




for 88.6% of the total oil production and had an average productivity of




56 barrels per day.  The three states included in the impact analysis (Texas,




Louisiana, and Wyoming) had two billion barrels of production, 66% of the U.S.




total.




     Offshore production,primarily off Louisiana, was 16% of U.S.  oil produc-




tion (Table V-2).  The three states had 1.65 million barrels of onshore




production, which was 65% of total U.S. onshore production in 1975.  Of the




onshore production in the three impact states, 92% was from non-stripper wells.




     In Chapter III, a survey of current formation water disposal  regulations




and practices was reported for the 19 largest oil-producing states.  They




accounted for 99% of total production.  Based on the survey, it was estimated




that 22% of 490,000 wells in these states, including stripper wells, did




not have their formation water reinjected into the ground in 1975.  Texas,




Louisiana, and Wyoming contain a large percentage of the wells not re-




injecting and are more generally representative of the non-reinjecting




and non-stripper production (Table V-4).
                                   V-l

-------
                                                                      TABLE V-l
U.S. OIL PRODUCTION BY STATE
Annual Production and Number of
Wells Producing (Dec. 31, 1975)
Total U.S. and Stripper Wells
1975 Production

State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah .
Virginia
West Virginia
Wyoming
Misc.
Stripper
MB a
116.7
_
5.2
5,042.7
60,574.2
1,953.4
-
25,214.7
4,031.7
43,706.7
6,182.8
7,574.2
4,760.3
648.8
57.0
3,578.7
1,545.4
-
11,082.5
875.0
929.7
6,704.6
72,530.6
3,199.0
17.9
125.6
126,018.3
98.2
3.0
2,478.0
5,107.0

TotaL
MB ^
13,477
69,834
635
16,133
322,199
38,089
41,877
26,067
4,632
59,106
7,556
650,840
24,420
46,614
57
32,844
6,120
115
95,063
875
20,452
9,578
163,123
3,199a
472
682
1,221,929
42,301
3
2,479
135,943

Stripper
I of Total
0.9
-
0.8
31.2
18.8
5.1
-
96.7
87.0
73.9
81.8
1.2
19.5
1.4
100.0
10.9
25.2
-
11.6
100.0
4.5
70.0
44.5
100.0
3.8
18.4
10.3
0.2
100.0
100.0
3.8

1975
•*
Stripper
75
-
6
6,100
32,124
881
-
23,222
4,654
40,597
13,690
12,723
3,330
310
163
1,873
638
-
10,274
5,231
569
15,482
58,736
31,661
9
133
89,027
48
7
13,680
2,629

No. of Wells
t,
Total"
608
205
28
7,308
41,029
2,450
143
23,373
4,798
41,945
13,905
24,453
3,655
2,237
163
3,247
1,190
6
13,715
5,231a
1,994
16,611
71,516
31,661
38
172
160,603
1,323
7
13,680a
9,450

Stripper
% of Total
12.3
-
21.4
83.5
78.3
2.1
-
99.4
97.0
96.8
98.4
52.0
91.1
13.8
100.0
57.7
53.6
-
74.9
100.0
28.5
93.2
82.1
100.0
23.7
77.3
55.4
3.6
100.0
100.0
27.8

Average Daily Production Proved API
Per Well for Total and Reserves
Stripper Wells as of 12/31/75
1975 B/D
Stripper
B/D a
4.26
-
2.40
2.26
5.17
6.07
-
2.97
2.37
2.95
1.24
1.63
3.92
5.73
0.96
5.23
6.64
-
2.96
0.46
4.48
1.19
3.38
0.28
5.46
2.59
3.88
5.60
1.17
0.50
5.32

Total.
B/D °
62.1
947.2
65.7
6.1
21.7
45.1
822.4
3.0
2.8
3.9
1.5
72.9
17.0
56.9
1.0
28.3
14.5
42.0
19.3
0.5
32.2
1.6
6.2
0.3
37.5
11.5
20.9
96.6
1.6
0.5
41.1


(MB)
61,032
10,037,262
95,662
*
3,647,537
276,066
262,539
160,986
22,029
364,394
39,306
3,827,187
93,312
231,158
*
163,968
28,372
*
588,110
10,024
158,245
121,263
1,239,687
48,028
1,855
1,508
10,080,035
208,318
*
31,418
877,385
5,441
TOTAL U.S.
349,162.9
3,056,716
                                                11.4
367,872
496,804
                                                                                           74.5
                                                                                                         2.93
                                                                                                                     16.9
32,682,127
*Included in misc.
Interstate Oil Compact Commission National Shipper Well Survey. December 31. 1975.
 U.S. Bureau of Mines Petroleum Statement; except as noted for states containing only stripper wells where the appropriate state agency stated
 that the I.O.C.C. data was more accurate.
SOURCE:  Interstate Oil Compact Commission National Stripper Well Survey. December 31, 1975; U.S. Bureau of Mines Petroleum Statement, March 1976.

-------
                                      TABLE V-2
State

Louisiana
Onshore
Offshore
Texas
Onshore
Offshore
Wyoming
TOTAL
TEXAS, LOUISIANA, AND
Stripper Wells
Production No. of Wells
(1,000 bbls)

7,574 12,723
none none

126,018 89,027
none none
5,107 2,629
138,699 104,379
SOURCE: Petroleum Statement, March 1976, U.S.
WYOMING OIL PRODUCTION - 1975
Non-Stripper
Production No
(1,000 bbls)

282,214
361,052

1,095,132
779
130,836
1,870,013
Wells
Total
. of Wells Production No. of Wells


15,829
4,331

71,226
350
6,821
87,052
Bureau of Mines; National
(1,000 bbls)

289,788 23,403
361,052 1,050

1,221,150 160,253
779 350
135,943 9,450
2,008,712 191,431
Stripper Well Survey, December 31,
1975,  Interstate Oil Compact Commission;  Arthur D.  Little, Inc., estimates.

-------
                                              TABLE V-3

                PRODUCTIVITY OF ONSHORE WELLS IN TEXAS. LOUISIANA, AND WYOMING - 1975
State
    Stripper Wells
 Number
of Wells
  Average
Productivity
 (bbls/day)
                                                       Non-Stripper Wells
 Number
of Wells
  Average
Productivity
 (bbls/day)
                                                      All Wells
  Number
 of Wells
  Average
Productivity
 (bbls/day)
Louisiana
12,723
   1.63
15,829
     48.8
 23,403
    33.9
Texas
89,027
   3.88
71,226
     42.1
160,253
    20.9
Wyoming
 2,629
   5.32
 6,821
     52.6
  9,450
    39.5
SOURCE:   Petroleum Statement, March 1976, U.S. Bureau of Mines; Arthur D. Little, Inc., estimates.

-------
                                             TABLE  V-4
REINJECTION IN TEXAS, LOUISIANA, AND WYOMING (ONSHORE)



f
Ln
Oil
State Production
(MM bbls)
Louisiana 290
Texas 1,221
Wyoming 136
TOTAL 1,647
Water
Production
(MM bbls)
1,050
3,560
941
5,551
% Water
Reinjected

56%
94%
75%
84%
Number
of Wells

20,328
160,253
9,450
190,031
% Wells
Re injecting'
over 50%
over 90%
over 50%
over 85%
a.  Percent of wells whose formation water is reinjected.
SOURCE:  Petroleum Statement,  March 1976,  U.S.  Bureau of Mines;  Arthur D. Little, Inc., estimates.

-------
     State regulations in Texas and Louisiana allow discharge of produced




formation water to brackish and tidally affected surface water.   Most of the




surface discharges in Texas appear to he a.l ong the Gulf Coast on or adjacent




to bays and the Gulf.  There are some discharges to evaporation  pits.  Because




of the large number of bays, bayous,  and marsh areas in southern Louisiana,




a high percentage of the produced formation water is discharged  to surface




waters.  In Wyoming, much of the formation water has low salt (TDS) content




and the state has allowed its use in watering livestock.




     As part of the project by the engineering contractor to  estimate the  costs of




compliance with a reinjection requirement, production profiles were developed




of wells not currently reinjecting their formation water in the three states.




Tables V-5, V-6, V-7, V-8,  and V-9 are  the distributions in  the states  of pro-




duction units  over  average  productivity per  production well  and number  of




wells per production unit.  The well populations were compiled from  published




reports in  the states and have not been revised or updated by Arthur  D.




Little, Inc.   The numbers of wells and  their productivity are listed  on




Table V-10.  Table V-ll lists the total remaining production of the impacted




wells at current prices and production technology.  The well populations




were intended by the engineering contractor to include all of the wells in




each of the states not currently reinjecting, to the extent this information




could be determined from existing state records.  The Louisiana profile may




understate  the number of lower production wells, but such an understatement




has not been explicitly determined.




      All of the potentially impacted wells are classified  as "onshore" wells.




 However, some of the Texas and Louisiana wells are actually producing to




 platforms and are treated as a separate category.  Only the non-stripper well




 portions of the on-land well populations are affected by the proposed effluent
                                    V-6

-------
                                           TABLE V-5
 I-KUI.V I U-
(B/D)
  J US'


  1 '4 ! S •
  75. v;
 125.0J
 t75.0o
 375.00
 300,00

•>.
,-.
„ j
i l> i
*> \
'i !
,> i ;)
t / *'
a $ '»
1 1 i
'i 3
* -**
! i
1
6 1
t; J
'i C
« ; w
c
•> 0

^,
'4
1
1
0
.1
1
s
11
f>
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t\
I
0
0
r)
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(i
0
EPA *
13.
5
d
1
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i:
i
1
M
0
t
u
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l;
0
0
u
OHHAT
let
1 *

• •


'
u
1!
!
1
1
<\
\ •
t1
ii
ii
i
''
it
(# wells/producing unit)
 ^ 'j.     ^ ^«      *«' •
                                                                      t
                                                                      c
                                                                      i
                                                                      • i
            ')
            0
                                                                             0
                                                                             {
                                                                                       »lTNJtCTIQH
                                                                                          loo.
 SOURCE:   Jacobs Engineering, Inc.

-------
                                                       TABLE  V-6
                                                                    C/ISpOSAL
                                                                                                       T '•  H f T T
oo
 MHOO/^IU
(B/D)


  < i .S

  1 *>. S •>

  1 L"  s >
  i F . '.•> •:



  a "-"• .00
                                                                    PRODUCING  ;.J*!T
                                                                       (# wells/producing unit)
              ..Oo
              5.00
^.
.,>
I'

',
0
r.
('
I
1 '

1 1
',•
o
••)
i
n
0
0
0
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0
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0
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i
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,1
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;.

fi
0
0
f
1
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0
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0
0
0
n
^
0
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0
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(i
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fi
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'1
0
0
0
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V
'
1 \
0
f;
(
1 '
>,

r>
.
"

..»
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fl

0
 SOURCE:  Jacobs Engineering,  Inc.

-------
                 7.bD
f                H.V,

               1'J.V.
               11, •>','
               t 'i. .".-
               •?^.ur
               3 'i . I' i1
               4S..IO
               •jS.Uu
               oS.vH
               7^.v'C
               HS..'<
                5, u;
                S.UO
              300.uo
                                                   TABLE V-7
                                            (.DA FPRXATIO •  *ATtK  DISPOSAL  AMALVSISi  Rfc T N Jfc T-T I 0»
                                                             STAr_fc  UOYJSI.ANA OFF
                                                                 (# wells/producing unit)
                     t.ll                                 PWDDUCINR  UMT  CATfT,QRIFS
              B/D

                  .50
                 1,50
                 2,50
                 5,SO
                 'I, bO
l»
1 l>
0
i) 0
I!
V
,< o
! 0
:, ii
c r
0
• ^
i
0 0
'! 0
'I 0
f 0
i1
0
0 0
'» 1
0 U
n o
(I 0
0 0
p 1
e1 «
0 0
j "j
1 U
o
(1
0
I)
!)
0
n
0
0
0
(1
0
0
0
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(i
ii
v
C)
0
0
0
1
1
0
o
J
0
f
0
u
II
11
I)
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U
t>
0
0
0
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I 1
0
n
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11
.1

tl
0
(1
u
0
0
2
0
1
(L
0
0
G
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
A.
\
0
g
j
0
£
0
0
0
0
o
0
0
n
it
0
0
0
II
<)
0
0
0
"
'1
Ii
0
0
0
0
0
0
0
0
0
i
0
1
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0
0
t)
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(1
.)
0
0
0
0
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0
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'.}
it
0
0
0
0
0
0
0
u
2
0
I
0
ii C'
i' U
C
ii 0
i,1 C
k
. »
!» 0
ii 0
.•> 0
n o
r-
' i^
0
0 C
(.' r
1 ' \
n
'i C
11 0
II p
o 0
o 0
o 0
1 C
i) S
2 0
y o
o 0
o 0
                       SOURCE;  ^cobs Engineering,  Inc.

-------
                                                   TABLE  V-8
M         bS.yo
o         -,,-.,.
          «s.oo

         17S.UO
         c'S'i.UO
                                                            FORMATION WATER 018*05*1

                                                                       STATE
            (B/D)                                                       (# wells/producing unit)
                                                                                            80.    100.
           i 1 ,!>0               ^       I        I        I        1        0        0        ..       •'        0
           I2.5n               '4       2        0        1        o        0        0        0       -*        0
           13. SO               S       2        0        <'        )        0        0        'I
           1 i.!>0               "       I        I'        1        <•'        0        0        0
             ,50               ^       ''        I        i        "        i        0        i'1
             ,UO
             .00              31!       r"        '        i        2        0        0        0
            5,00              n       t*        i        "        '        o        o        o
             .00               9       \        0        U        C        0        0        C
             .t'C
2,
2
n
5
^
•5
17
3l!
1 ^
V
t,
t>>
t
1
>•,

i
U
1
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s.
1
2
2
\

*,
t
t*
1
n
i
^
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?
(,
('•
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i
0
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0
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ft
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t.
c
..
I'
U
U
t)
i3«
I
1
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1
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i
0
U
L>
i;
i'i
r

•.'
V
t'
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1
IB.
1
(i
)
0
(i
0
2
i
c
t '
i'
•

'•
:)
(I
c
0
0
25.
U
0
0
0
1
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0
0
0
(j
U
(,'
o
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0
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0
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*s.
0
0
0
0
0
0
(1
0
0
0
"
I.I
1
11
I)
1
II
0
.'l
    SOURCE:  Jacobs  Engineering, Inc.

-------
                                             TABLE V-
                                         ?PA
                                                          n*,  *ATCR DISPOSAL ANALYSTS*

                                                              STATE TEXAS  OFFSHORE
A/C PhO,•;/»£ |. L
    (B/D)
        .sn
       1 . S ">
       'I.V;
       s.so

       7.bO
1 ' . S •

f A . S "
1 -I . S •••

t ",!>'.)

iO>o
'15.00
SS.no
       >. 00
    ^75.00
                                                                     USJT  C A nC^SJfS
                        IS
                                S.
.'!
^
r.
6
>j
f
H
n
s
L\
u'
P
1
1
'I
()
]
0
1
(1
1
0
0
0
1
1
0
S
1
0
i)
0
o
(1
(t
0
(1
fl
I
0
'J
0
n
0
                                                      (# wells/producing unit)
                                                        ?'J.     V>.   & S'%
A
r.
0
1!
t!
0
0
1)
(1
1)
0
''
(1
(1
1 )
)
o
ll
(1
0
0
0
(1
ll
II
• 1
1)
r
ll
(t
0
0
o
0
0
0
0
0
0
0
0
0
0
0
n
0
0
0
0
0
0
0
n
0
i1
0
0
o
o
0
0
u
(1
0
,)
u
0
0
0
0
0
0
I)
0
r J
n
0
o
0
1
0
0
0
o
o
'i
n
•i
(i
0
U i!
0 ''
(I
u
n M
0 <)
0 0
(1 0
0 (>
0 0
0
0 (1
0 't
0 (i
1
0
jl
!>.
C i'
0 • t
0 !>
0 n
•r [•
!'
"
i
c
;•
V1 f '
n
t
r


r
0
0
f.
0
0
r,


C
0
r
-.
?
r
0
n
0
c
r
0
r
r
,'
0
r
     SOURCE:  Jacobs Engineering, Inc.

-------
                                                          TABLE V-10
M
N)
State

Louisiana
  on land
  on platforms

Texas
  on land
  on platforms

Wyoming
Stripper
Number
of Wells
0
2
824
206
POTENTIALLY IMPACTED
PRODUCTION
Wells Non Stripper Wells
Production Number
(bbl's/day) of Wells
0 715
11 1,031
4,744 1,108
1,028 250
Production
(bbl's/day)
64,513
156,382
82,761
8,999
All
Number
of Wells
715
1,033
1,932
456
Wells
Production
(bbl's/day)
64,513
156,393
87,505
10,027
                               547
3,147
1,594
 89,853
2,141
 93,000
                TOTAL
                  1,579
8,930
4,698
402,508
6,277
411,438
            SOURCE;   Jacobs  Engineering, Inc.

-------
                              TABLE V-ll
Louisiana

  on land
             g
  on platform



Texas

  on land
             a
  on platform



Wyoming
POTENTIAL PRODUCTION OF
Number
of Wells

715
1,033
1,108
456
1,594
ted States 4,906
IMPACTED WELLS
1975
Production
(bbl's/day)
64,513
156,394
82,761
10,027
89,853
403,548
Remaining
Production
(MM bbl's)
281
683
360
41
385
1,750
a.  Platform guidelines cover stripper and non-stripper wells.
SOURCE:  Number of wells and production, Jacobs Engineering.  Remaining
         production, Arthur D. Little, Inc.
                                   V-13

-------
limitation.  Both the stripper and non-stripper platform wells are covered




by the platform effluent limitation.






2.  Production Cost Models




     No data was available for the impact analysis about the production




history and the production cost of the units found to be impacted by the




proposed regulation.  To make an estimate of the potential impact on these




specific production units, it would have been necessary to know:




     •  how long the production unit had been producing;




     •  what the initial investment had been in drilling costs and production




        equipment;




     •  how much of that investment still needed to be depreciated against




        future production;




     •  what the production decline rate had been in the past and what it




        could be expected to be in the future;




     •  what the annual operating costs are and how they are expected to




        change with declining production; and




     •  what the overhead charges are to the specific production unit.




     In the absence of this information, production cost models developed by




the Bureau of Mines for the states analyzed (Information Circular 8561, 1972)




were modified and updated to 1975.




     To assure a conservative analysis, the operating costs per producing




well were assumed not to decrease as the well's production declined.  In




reality, direct operating expenditures per well will be reduced as the pro-




duction unit's overall production declines.
                                 V-1A

-------
     The capital costs and operating costs for a 10-well production unit are




shown in Table V- 1/1.  The price and tax assumptions used in the economic




impact analysis are shown in Table V-13.   Given the uncertainty about future




oil prices, the analysis was done using what can be considered a high and low




price scenario.  The low price scenario, resulting in a high impact estimate,




assumed continued regulation of all oil produced from wells with more than




10 B/D at the lower tier wellhead price of $5.25 per barrel and all stripper




well oil (i.e., oil from wells producing at an average of less than 10 B/D




per well) at the wellhead price of $11.28 per barrel.




     Since stripper well oil may be deregulated and allowed to sell at world




prices close to $12.50 per barrel, this price scenario can be regarded as




potentially overstating the economic impacts.




     The high price scenario, resulting in  lower  impact  estimates,  assumed




continued price regulations with lower and upper tier prices, as under the




low price scenario, and an annual increase in real prices of 3% per year (the




so-called economic incentive factor which at present is intended to apply




until the end of 1979, the last year covered by present price regulations).




     In order to make the impact analysis conservative, none of the production




was assumed to qualify for depletion allowance, implying that all producers




are producing more than 2,000 barrels per day.  An investment credit of 7%




was assumed to apply to the investment in required pollution control equipment.




Depreciation of original capitalized investment and expenditures in lease




equipment and producing wells, and of the investment in the pollution control




equipment,was calculated using the unit of production method.
                                 V-15

-------
                                 TABLE V-12
               CAPITAL AND OPERATING COSTS  FOR  IP-WELL LEASES
                               (1975, $l,000's)
 State
     Total                Annual
Development Costs     Operating Costs
 Louisiana
   on  land
   near  shore platforms
     1,657.4
     2,094.2
 80.39
110.88
 Texas
   on land
   near  shore  platforms
     1,520.0
     1,956.7
 78.54
100.10
 Wyoming
     1,785.4
139.57
SOURCE:    Information Circular 8561.  U.S.  Bureau of Mines updated to
          1975 by Arthur D.  Little,  Inc.
                                     V-16

-------
                                                 TABLE V-13
Louisiana, on land
Louisiana, near shore
platforms
Texas, on land
Texas, near shore
"f platforms
-j
Wyoming
Price(1)
Old Oil
5.25
5.25
5.25
5.25
5.25
OIL PRICE
Price(1>
New Oil
11.28
11.28
11.28
11.28
11.28
AND TAX ASSUMPTIONS
(2)
Fed. Tax Investment
Rate Credit
0.48 0.07
0.48 0.07
0.48 0.07
0.48 0.07
0.48 0.07
Royalty
.125
.125
.125
.125
.125
Severance
and other
Taxes
.13
.13
0.091
0.091
0.067
 (1)  In the analysis it was, conservatively, assumed that all production  from wells with
     average production of more than 10 b/d qualified as old oil  ($5.25/8) and  that production
     from wells with an average of less than 10 b/d would be sold at a wellhead price  of  $11.28/B.

 (2)  An investment credit of 7% was assumed to apply to the investment in  the required  pollution
     abatement equipment.
SOURCE;  Arthur D. Little,  Inc.  estimates

-------
     The potentially impacted production units were assumed to continue using




the production equipment found in place in 1975.  In other words, it was




assumed that producers would not change to secondary or tertiary recovery




in the future and get higher  total production.  Production was assumed




to continue declining relative to 1975 levels at a constant annual decline




rate.  Values from 8%/year to 15%/year were used.




     No income credits were given for associated gas production,  and the




cost of capital was said to be the same for all producers..  A low estimate




of 10% and a high estimate of 15% were used in the analysis.  The analysis




was done in terms of constant 1975 dollars, with no relative cost inflation




allowed.
                                V-18

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                         VI.  ECONOMIC IMPACTS



1.  Summary

     The economic impact on oil production in Texas, Louisiana, and Wyoming of

the effluent limitations on produced formation water was estimated using the

methodology outlined in Chapter IV.  Table VI-1 shows that the states included

in the impact analysis have:

     •  Forty-two percent of the total estimated number of onshore  producing

        wells in 1975 producing more than 10 B/D per well;

     •  Seventy-one percent of the total estimated crude oil production

        onshore from wells in 1975 producing more than 10 B/D per well;

     •  Forty-seven percent of total proven U.S. resources in 1975 or

        sixty-seven percent of the U.S. reserves in 1975 exclusive of the

        10 billion barrels present in Prudhoe Bay, Alaska.

     The three impact states may have as many as 24,000 wells whose formation

water is not currently reinjecting, including stripper wells.  These wells may

be 70% of the currently non-reinjecting wells in the 17 largest oil-producing

states, excluding Illinois, which has predominantly stripper wells.  Their

non-stripper production whose brine is not currently reinjected is estimated

to be 72% of the total U.S. onshore non-stripper production whose brine is not

reinjected.
 Including wells producing from platforms located within the coastal zone,
 such as platforms in coastal marshes and estuaries in Louisiana and Texas.
                                  VI-1

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                                TABLE VI-1



                          PRODUCTIVE CAPACITY,

        API PROVEN  RESERVES AND NUMBER OF ONSHORE NON-STRIPPER HELLS

                       COVERED BY THE IMPACT ANALYSIS
                      Number  of Onshore     Onshore Non-Strip-         API
                      Non-Stripper Wells    per  Production3      Proven  Reserves
                           (Thousands)      (Millions bbl's)     (Billions of  Barrels)
 Louisiana                     7.6               282.2                   3.8

 Texas                         71.2             1,095.1                  10.1

 Wyoming                       6.8               130.8                   0.9

 Total, Impact States         85.6             1,508.1                  14.8


 Total  U.S.                   130.5             2,206.3                  32.7
a: As of December 31,  1975.

b. Includes offshore reserves.
 SOURCES:  API and BOM statistics  for 1975 oil reserves,  producing wells and
           production, Arthur D. Little,  Inc., estimates.
                                   VI-2

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     The sum of the estimated impacts on oil productLon in the three states




is shown on Table VI-2, while the state estimates are shown on Tables VT-3,




VI-4, and VI-5.  The primary results are summarized as follows:




     •  A requirement to re inject formation w.-iler from existing near-shore




        platforms would result in the closure of about 2% of the Louisiana




        platforms and 64% of the Texas platforms.  An effluent treatment




        rather than a reinjection requirement would substantially reduce the




        number of well closures.




     •  The reinjection requirement is not expected to close any on-land,




        non-stripper wells in Louisiana and Texas, but could close as many




        as 144 wells in Wyoming.




     •  The investment required to install reinjection equipment in the three




        states, including platforms, is $80 million.  It is estimated that




        the total U.S. requirement is roughly $110 million.  This level of




        investment spread over several years is modest compared to $3-5 billion




        projected as yearly capital expenditures by the industry on onshore oil




        and gas production.




     •  The reinjection requirement would result in approximately 32 million




        barrels of foregone production in the three states as a result of well




        closures in 1977 and shorter well lives as a result of higher operating




        costs.  The foregone production is 1.8% of the projected remaining life-




        time production of the impacted wells, assuming a 12% decline rate and




        current price regulations.  The total is 0.2% of 1975 API proven




        reserve estimates for the three states.




     •  The average increase in production costs for the three states would




        be $.34 per barrel of affected oil as a result of the reinjection




        requirement.  Operating costs would increase by about $.06 per barrel.
                                  VI-3

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                                      SUMMARY OF RESULTS
                          RANGE  OF  LIKELY  IMPACTS  FOR SELECTED STATES'
                         	~ Reinjectton

                         Min     Likely
Number of Wells Shut In   290
Average Cost Increase
for Directly Impacted
Producers (c/BBL)

Required Investment
(Millions of 75$)

(Total U.S.)b

Percent of State Pro-
ducing Wells Forced
to Shut In °

Percent of State Pro-c
ductive Capacity Lost
Percent of  State API
Proven Reserves Lost
                c,d
  28


75.0
(105)



  0.0


  0.0

  0.0
456



  34


 80.0
(110)



0.53


0.18

0.22
Max


493



 65


140.0

(190)



 0.58


 0.22


 0.39
                                                      —Alternative Disposal
                                                      Min     Likely    Max
120



 18


35.0
(50)



 0.0


 0.0

 0.0
                                                                290



                                                                 21


                                                                40.0
                                                                (55)
        377



         30


        50.0
        (70)
                                                                 0.34     0.58
                                                                 0.09     0.15
0.14    0.24
a.
b.
c.
d.
Texas, Louisiana, Wyoming
Based upon the estimated ratio of non-stripper oil production in  selected  states
whose brine is not reinjected to total U.S. onshore non-striuoer  nrnduci-ion
whose brine is not reinjected:  72%.
Impacts relative to total number of wells, production,  and  reserves  in the
states covered by the regulation.
Offshore reserves included in state total.
SOURCE:  Arthur D. Little, Inc., estimates
                                     VI-4

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2.   Base Case Results for Selected States




     The impact of the proposed regulation is significantly different for each




of the three states.  The differences are explained by differences in the




average number of wells per production unit, the average daily production per




well of the production units, the production costs and the compliance costs in




each state.




     For example, a relatively large number of the Texas platform production




units have wells with a low average well productivity.  Given the relatively




high production costs for these units and the relatively high compliance costs,




a very high percentage of nan-complying wells will have to be shut in (64% in




the case of reinjection and 24% in the alternative disposal case) and average




costs per barrel for those production units, which will not have to shut in,




will increase significantly (by $1.42/B in the case of reinjection and by




$0.94/B in the alternative disposal case).




     The projected well closures for on-land wells are higher for Louisiana




and Texas, given the treatment requirement, than the reinjection requirement.




These results reflect the engineering contractor's estimate that the capital




costs for the treatment system are higher than the reinjection system for




smaller leases.  For larger producers, the reinjection system was estimated




to be more expensive and, thus, the total capital costs for compliance with




the reinjection requirement were higher than the treatment requirement




(Table VI-4).




     An estimate was made of the capital investment necessary to bring all




impacted wells into compliance under the assumption that the producers raised
                                   VI-5

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                                                  TABLE  VI-3
                                 ESTIMATED WELL CLOSURES AND  PRODUCTION LOSSES
<
f—i
I



Number
of Wells
Closed
(Base


Percent
of Impacted
Wells Closed3
Case)
Wells
Closed as a
Percent of All
Wells Covered
by Regulation

Foregone

Production
As a Percent
Production of Potential
Foregone Production by ,
(MM bbl's) Impacted Wells
Foregone
Production
As a Percent
of Total
State API
c
Reserves
Well Shortened
Closure Well Life
0
4
23
0
0
30
291
110
144
144
456
290
0.0%
0.6
2.2
0.2
0.0
2.7
64
24
9
9
9
6
0.0%
0.03
0.1
0.01
0
0.004
0.4
0.15
2.1
2.1
0.5
0.3
0
0.1
1.2
0
0
0.9
10.5
1.3
6.2
6.2
17.9
8.5
1.1
0.8
5.1
1.4
1.9
1.8
0.6 2
0.5
5.2
5.7
14.0
10.2
0.4%
0.3
0.9
0.2
0.5
0.8
7
4.4
3.0
3.0
1.8
1.1
0.03%
0.02
0.2
0.04
0.02
0.03
0.1
0.02
1.3
1.3
0.2
0.1
Louisiana, on land
  Reinjection
  Treatment
Louisiana, on platform
  Reinjection
  Treatment
Texas, on land
  Reinjection
  Treatment
Texas, on platform
  Reinjection
  Treatment
Wyoming
  Reinjection
  Treatment
Total
  Reinjection
  Treatment
a.  Wells closed rather than brought into compliance with a reinjection requirement.
b.  Production lost by immediate well closures plus shorter well life due to higher operating costs.
c.  Offshore reserves excluded.
SOURCE:  Arthur D. Little, Inc.

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TABLE VI-4
ESTIMATED COST OF

COMPLIANCE WITH REINJECTION
(Base
Investment
Requirement
($MM)
Louisiana, on land
Reinjection
Treatment
Louisiana, on platform
Reinjection
Treatment
Texas, on land
Reinjection
Treatment
Texas, on platform
Reinjection
Treatment
Wyoming
Reinjection
Treatment
Total
Reinjection
Treatment
a. Present value of compliance
SOURCE: Arthur D. Little, Inc.

6.05
3.72

38.4
8.6

11.5
10.5

5.3
4.5

18.2
11.2

80
39
costs averaged over

Case)
AND TREATMENT REQUIREMENTS

Increased
Operating Cost
($MM)

.82
.79

2.89
1.15

2.03
2.18

.35
.63

1.99
2.27

8.1
7.0
($/bbl)

.04
.04

.05
.02

.07
.08

.19
.20

.07
.08

.06
.05

Increase in Total
Production Costs
($/bbl)

.22
.16

.48
.12

.31
.31

1.43
.94

.34
.28

.34
.21
total remaining production.




-------
                                                        TABLE VI-5
                                      COST OF COMPLIANCE IF PRODUCERS PASS ON COSTS
I
oo
Louisiana, on land
  Reinjection
  Treatment
Louisiana, on platform

  Reinjection
  Treatment

Texas, on land

  Reinjection
  Treatment

Texas, on platform

  Reinjection
  Treatment

Wyoming

  Reinjection
  Treatment

Total

  Reinjection
  Treatment
(Base Case)
Required
Investment
($MM)
6.1
3.8
41.3
8.7
11.5
11.5
50.1
7.2
23.6
15.7
132.5
46.8

Increased
Operating Cost
($/bbl)
0.4
0.4
.06
.02
.07
.07
.96
.30
.08
.10
NA
NA
                                                                                         Average Required
                                                                                          Price Increase
                                                                                            ($/bbl)
                                                                                               .20
                                                                                               .17
                                                                                               .44
                                                                                               .12
,32
 34
                                                                                              6.89
                                                                                              1.32
                                                                                               .51
                                                                                               .43
                                                                                               NA
                                                                                               NA
                SOURCE;   Arthur D. Little, Inc.

-------
prices sufficient to pay for the abatement equipment and no wells were shut in.




The total capital requirement for reinjection facilities in the three states




is about $130 million and $45 million for treatment equipment (Table VI-5).




     The impact analysis results presented in Tables VI-3, VI-A, and VI-5 are




for the "Base Case" set of assumptions.   These included a production decline




rate of 12% per year, a cost of capital of 10%, and continued price regulation




at $5.25 per barrel of non-stripper oil and $11.28 per barrel of stripper well




oil.




3.   Sensitivity Tests -and Range of Impacts




     There is considerable uncertainty about future crude oil prices, the




cost of capital and annual production decline rates.  To understand these un-




certainties, sensitivity tests established the ranges within which the different




impacts can be expected to fall with a high confidence level.




     The results of the sensitivity tests are shown in Table VI-6 for changes




in the annual production decline rate and in Table VI-7 for changes in the




cost of capital and future oil prices.




     Graphing of the results of the sensitivity analysis displayed the minimum,




likely and maximum values for the six impact indicators measured.  Figure VI-1




shows the reinjection  requirement case and Figure VI-2 shows the alternative




disposal case.  For both the reinjection requirement and the alternative dis-




posal case,  it was found that:




     •  The  regulation would result in a maximum  impact if:




             producers cannot pass on all costs;




             future real upper  tier and  lower  tier  crude oil prices do not




             change relative to 1976 values;
                                    VI-9

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                                           TABLE VI-6

                       SUMMARY OF SENSITIVITY TESTS FOR SELECTED STATES;

                                   CHANGES IN DECLINE RATE
Number of Wells
Shut-in

Percent of Total
Producing Wells

Productive Capacity
Loss (bbls/day)
                                .SCENARIO 1
                                (Base Case)
                         Producers Absorb All Costs
                       -Reinjection-
                       8%    12%  15%
                  Alternative
                  -Disposal-
                  8%   12%   15%
                                                SCENARIO 2

                                        Producers Pass on All Costs
                                                         Alternative
                                     -Reinjection-       -Disposal-
                                     8%    12%    15%    8%   12%   15%
                                     0
400   456  493   178   290   371
0.47  0.53 0.58  0.21 0.34  0.43
5889  7157 7840  1851  3747  4686    0
0      0000
                                                   0000
                                                   0000
Percent of Total
Productive Capacity    0.14  0.18 0.19  0.04 0.09  0.11
Required Investment
(millions of 75$)
                                     0
Potential Production
Loss (million of bbls) 46.8  32.4 26.7  27.6  20.9  17.6    0

Percent of 1975
API Proven Reserves    0.30 0.22  0.17  0.18  0.14  0.11    0
                                                   0000
                                                   0000
                                                   0000
85.3  82.2 80.1  44.0  40.2  39.0  136.1  135.5  134.9  49.4  49.3   49.1
Average Increase of
Production Cost
(C/bbl)
 30    34   37    19    21    22    43     49     54      22     25     27
  SOURCE:   Arthur D.  Little,  Inc.,  estimates
                                             VI-10

-------
                                          TABLE VI-7

                       SUMMARY OF SENSITIVITY TESTS FOR SELECTED STATES;

              BASE CASE (BC) *>   HIGH PRICE (HP)  .   HIGH COST OF CAPITAL (CC)C
                                  SCENARIO 1
                          Producers Absorb All Costs
                                          Alternative
                        —Reinjection—    — Disposal —
                                                SCENARIO 2
                                        Producers Pass on All Costs
                                     —Reinjection—
        Alternative
       — Disposal—
                        BC   HP    CC    BC   HP    CC     BC     HP     CC     BC
                                                                HP   CC
Number of Wells
Shut-in

Percent of Total
Producing Wells
 456   390    475    290   120    377      0


0.53  0.46  0.55  0.34 0.14  0.44     0
Productive Capacity
Loss (bbls/day)        7157  5531 7733  3747  890  4827     0

Percent of 1975
Productive Capacity   0.18  0.13  0.19  0.09 0.02  0.12     °
0000


0000


0000
                                            0
0
0     0
                                                                     0
Required Investment
(Millions of 75$)      80.0  85.9 79.1  38.5  42.5 37.0   132.6  133.3  133.3  46.9  47.4  47.4


Average Increase of
Production Cost        34 0  35 Q 38 0  21.0  25.0 22.0    49.0   50.0   57.0  25.0  27.0  27.0
(C/bbl)a
Potential Production
Lost  (MMB)             31.5  18.5 32.9  18.7   5.6 21.1     0

Percent of 1975     ,
API Proven Reserves    0.21  0.13 0.22  0.13  0.04 0.14     0
                                                         0     0
                                                   0000
 a-  $5.25/BBL for non-stripper well oil, $11.28/BBL for stripper well oil, cost of
     capital of 10%/yr., production decline rate of 12%/yr.

 b-  Real annual increase in lower ($5.25/B) and upper tier  ($11.28/B) of  3%/yr.

 c-  Cost of capital of 15%/yr.

 d.  Includes offshore reserves.
  SOURCE:   Arthur D.  Little, Inc., estimates
                                                VI-11

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         FIGURE VI-1.
Reinjection Requirement:  Sensitivity Tests
   c.  Required  Investment
120
100

       millions of 75$

                 D
10    12
I     i
                       14
  b.  Impacted Producers'
      Cost Increase
                               40
           10    12    14
                                                   a.  Average  Crude Oil
                                                      Cost  Increase
                                                             2.0
                                   o
                                                             Legend:

                                                         Base Case:  Pass on
                                                                     all costs

                                                         Base Case:  Absorb
                                                                     all costs

                                                         High Price Scenario


                                                         High Cost of Capital


       Percent of Producing
       Wells Shut-in
0.70
-0. 60
  e.  Percent of Productive
      Capacity Lost
                               0. 20
                                                    f.   Percent of Reserves
                                                        Lost
                                                             0.32
                              0.15,
                                                            •0.15
                              0.10
      8    10    12    14
     J	1	I	L_
       8    10    12    14
      _I	1	1	L_
                                                       8    10    12
                                      Decline Rate   (%/yr.)

 SOURCE: Arthur D. Little,  Inc., estimates
                                              VI-12

-------
         FIGURE  VI-2.   Alternative Disposal Requirement:   Sensitivity Tests
    c.  Required 'Investment
•60
       millions of 75$
      8    10    12    14
b.  Impacted(Producers'
    Cost Increase
    8    10    12    14
a.  Average Crude Oil
    Cost Increase
                                                            -2.0
  s\

  _
                                                                       Legend:

                                                                    Base Case:   Pass  on
                                    Base Case:
 as
all costs

Absorb
all costs
                                                                 Q  High Price Scenario


                                                                 A  High Cost of Capital
                                                             0.
                                                            a*o.25Oi	n	
  d.  Percent of Producing
      Wells Shut-in
0.30
 c.  Percent of Productive
     Capacity Lost
 f.   Percent uf Reserves
     Lost
*0.25
-0.20
•0.1
•O.K)
•0.05
                                                             0.22
                                                            -0.15
                                                            •0.05
                                                                            D.
           1     12    14
            I	I	L_
    8    10    12    U
                                      Decline Rate  (%/yr.)
SOURCE:  Arthur D. Little, Inc., estimates
                                            VI-13

-------
          -  production decline rates are 15%/year;  and




          -  the cost of capital is 15%/year.




     •  The regulation would result in a minimum impact  if:




             producers can pass on all costs;




             future real upper tier and lower  tier crude oil prices escalate




             at 3%/year relative to 1976 values;




             production decline rates are 8%/year; and




             the cost of capital is 10%/year.




     Figure VI-la,b and Figure VI-2a,b show that required cost increases are




more sensitive to changes in the cost of capital  (15% versus 10% for the base




case) than to changes in the assumed future values of oil prices (3% annual




escalation versus level lower and upper tier prices of respectively $5.25 and




$11.28 per barrel for the base case).




     However, well shut-ins, loss in productive capacity and loss of reserves




are more sensitive to changes in price than to changes in cost of capital (see




Figure VI-ld,e,f and Figure VI-2d,e,f).  Only the estimates of required invest-




ment turned out to be rather insensitive to changes in the production decline




rate.
                                         VI-14

-------
                     VII.   LIMITS OF THE ANALYSIS









1.  Data Limitations




     The relevance of the  economic impact analysis results is inherently




limited by data inputs to  the analysis.   The major data categories in which




problems could exist are the production costs,  the costs of compliance, and




the production profiles.




     Costs of Production




     The production cost models are based on Bureau of Mines models developed




four years ago.  The components of the models have been updated to 1975 using




various escalators.  Changes in production practices, technology, and inflation




can alter the representativeness of the models.   In addition, the models are




intended to be broadly representative of production in an area, but they are




being used to analyze specific leases and particularly less economical leases.




     Costs of Compliance




     The costs of compliance were developed by the EPA's engineering contractor.




The costs were based on a  field survey of reinjection and treatment costs in




the  three states.  While  the costs have not been reviewed in detail, some




potential problems have been noted.  There is great variability among the




sample costs,suggesting a  lack of consistent definition of treatment versus




production equipment and consistency among production characteristics.  In




addition, there were a limited number of smaller volume data points which made




the costs for the most vulnerable wells least reliable.




     Relative to other cost studies, the compliance costs for high volume




wells seems reasonable, while the costs for the low volume wells could be high




or low.
                               VII-1

-------
     Production Profiles




     EPA's engineering contractor compiled data on non-complying production




in the states under examination.   The profiles were developed from publicly




available records in the state oil and gas agencies.   There remains a question




as to the completeness of the Louisiana profile.  It  is possible that the




on-land population of wells not currently reinjecting formation water is




larger (perhaps substantially larger) than used in the analysis.  Initial




uncertainty on EPA's part about the definition of no  discharge and the possi-




bility that state records do not  accurately reflect formation water discharges




to ponds and brackish  waters is  the basis for the potentially understated




population.




     A primary uncertainty with the production profiles generally is the




degree to which producers not now reinjecting are treating their effluent and




therefore how much of the population would not be in compliance with a treat-




ment requirement.  The engineering contractor made the assumption that pro-




ducers not now reinjecting had no treatment equipment and thus faced the full




treatment compliance costs.  This assumption probably overstates the impact of




a treatment regulation.




2.  Methodology Limitations




     The main limitations of the methodology used in this analysis are:




     •  the assumption that all impacted producers will behave in the same




        manner;




     •  the assumption that producers will make their investments individually




        and not try to reduce their costs by combining in larger disposal units;
                                 VII-2

-------
     •  the use of uniform decline rates to project production from potentially




        impacted production units; and




     •  the use of average production economics to analyze the economic impact




        on economically marginal production units.




This latter limitation  is illustrated by Table VII-1,  where it is shown what




percentage of the number of potentially impacted units  would be uneconomical




to produce in 1975 according to the average production  costs assumed in the




analysis.
                                VII-3

-------
                                TABLE VII-1

                 PERCENT OF NON-COMPLYING WELLS WHICH

                ARE  SUBECONOMICAL ACCORDING TO PRODUCTION MODEL
   DATE DUE
                             Total number of              Number of
                             non-complying wells       "subeconomical"  wells
  Louisiana

    on-land                        715                      0     (0%)

    near  shore platforms         1,033                      0     (0%)



  Texas

    on-land                      1,932                     30    (1.60%)

    near  shore platforms           456                     29    (6.4%)



  Wyoming                        2,141                     67    (3.1%)
  (1)   Production units would immediately shut in if the average production
       costs used in the analysis are applied.   This indicates that at  least
       the average operating cost  estimates used in the analysis are  too  high
       for some non-complying production units and as such might result in an
       over-estimation of the potential impact.
   SOURCE:   Arthur D.  Little, Inc.
     6U.S.GOVERNMENTPRINTINGOFFICE: 1977- 241-037:26
•;     .  r,-.C)f i  -  "    ,./•••;•*;      Vii-4

-------