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
\
-------
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 --" ;,-&
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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 $11 per barrel price levels.
II-8
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TABLE 11-4
U.S. CRUDE OIL PRODUCTION - 1974 TO 198S
(million barrels per day)
"Business as Usual" Case
World Price ($/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
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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
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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
$15-21 billion per year
SOURCE: Arthur D. Little, Inc., estimates
11-39
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TABLE 11-21
CASH FLOW OF CHASE GROUP
1974
($ 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
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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
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4
1
r
>•
i
0
c
1;
r
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I
cf
1
0
u
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0
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1
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0
0
0
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n
0
"
'•<
1
(i
n
1
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-------
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
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H '•.'"'
r-
100
1 00
100
luo
100
100
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^ 3
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7
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59.9
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12. "3
10. fa
9.2
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4 * * -fr 4
*****
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• w
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ti . 0
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2.7
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*****
1*2
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*****
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• "* W
3,5
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2.9
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.
-------
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>
\
c
t\
I
0
0
r)
'J
(i
0
EPA *
13.
5
d
1
C!
i:
i
1
M
0
t
u
0
1
I!
i)
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
13.
0
•J
0
0
(i
0
i
(1
0
(1
0
f>
0
0
0
0
0
I)
p
u.
.»
I1.
,1
i!
• 1
,1
0
!)
l\
1
n
t!
I
"
r.
1!
(t
.1
?*?•
;.
fi
0
0
f
1
•J
0
0
f)
o
1
a
<)
0
0
0
n
^
0
0
0
I!
(i
U
,'•
fi
fl
.'1
f.
'1
0
0
0
t
0
(l
V
'
1 \
0
f;
(
1 '
>,
r>
.
"
..»
{)
(j
0
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
0
(i
ii
v
C)
0
0
0
1
1
0
o
J
0
f
0
u
II
11
I)
C>
U
t>
0
0
0
0
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
')
0
0
t)
II
(1
.)
0
0
0
0
0
(1
0
0
0
'.}
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
•i
s.
1
2
2
\
*,
t
t*
1
n
i
^
C
?
(,
('•
()
o
,1
<},
i
0
U
0
1
0
1
I
0
0
ft
0
t.
c
..
I'
U
U
t)
i3«
I
1
c
1
1
I
i
0
U
L>
i;
i'i
r
•.'
V
t'
C'
1
IB.
1
(i
)
0
(i
0
2
i
c
t '
i'
•
'•
:)
(I
c
0
0
25.
U
0
0
0
1
Q
0
0
0
(j
U
(,'
o
U
U
0
I/
0
J
*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
-------
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
-------
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
-------
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 $.06 per barrel.
VI-3
-------
SUMMARY OF RESULTS
RANGE OF LIKELY IMPACTS FOR SELECTED STATES'
~ Reinjectton
Min Likely
Number of Wells Shut In 290
Average Cost Increase
for Directly Impacted
Producers (c/BBL)
Required Investment
(Millions of 75$)
(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
-------
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
-------
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.
-------
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 $11.28 per barrel of stripper well
oil.
3. Sensitivity Tests -and Range of Impacts
There is considerable uncertainty about future crude oil prices, the
cost of capital and annual production decline rates. To understand these un-
certainties, sensitivity tests established the ranges within which the different
impacts can be expected to fall with a high confidence level.
The results of the sensitivity tests are shown in Table VI-6 for changes
in the annual production decline rate and in Table VI-7 for changes in the
cost of capital and future oil prices.
Graphing of the results of the sensitivity analysis displayed the minimum,
likely and maximum values for the six impact indicators measured. Figure VI-1
shows the reinjection requirement case and Figure VI-2 shows the alternative
disposal case. For both the reinjection requirement and the alternative dis-
posal case, it was found that:
• The regulation would result in a maximum impact if:
producers cannot pass on all costs;
future real upper tier and lower tier crude oil prices do not
change relative to 1976 values;
VI-9
-------
TABLE VI-6
SUMMARY OF SENSITIVITY TESTS FOR SELECTED STATES;
CHANGES IN DECLINE RATE
Number of Wells
Shut-in
Percent of Total
Producing Wells
Productive Capacity
Loss (bbls/day)
.SCENARIO 1
(Base Case)
Producers Absorb All Costs
-Reinjection-
8% 12% 15%
Alternative
-Disposal-
8% 12% 15%
SCENARIO 2
Producers Pass on All Costs
Alternative
-Reinjection- -Disposal-
8% 12% 15% 8% 12% 15%
0
400 456 493 178 290 371
0.47 0.53 0.58 0.21 0.34 0.43
5889 7157 7840 1851 3747 4686 0
0 0000
0000
0000
Percent of Total
Productive Capacity 0.14 0.18 0.19 0.04 0.09 0.11
Required Investment
(millions of 75$)
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 ($11.28/B) of 3%/yr.
c- Cost of capital of 15%/yr.
d. Includes offshore reserves.
SOURCE: Arthur D. Little, Inc., estimates
VI-11
-------
FIGURE VI-1.
Reinjection Requirement: Sensitivity Tests
c. Required Investment
120
100
millions of 75$
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
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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
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- 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
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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
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