IH7S
ECONOMIC ANALYSIS
OF
PROPOSED AND INTERIM FINAL EFFLUENT GUIDELINES
OF
THE OFFSHORE OIL AND GAS PRODUCING INDUSTRY
QUANTITY
U.S. ENVIRONMENTAL PROTECTIONS7 AGENCY
Economic Analysis Section
Office of Water and Ha/ardous Materials
Washington. D.C. 20460
\
\
-------
This document will be available through the National
Technical Information Service. Springfield. \ irginia 22151.
-------
ECONOMIC ANALYSIS
OF
PROPOSED AND INTERIM FINAL EFFLUENT GUIDELINES
OF
THE OFFSHORE OIL AND GAS PRODUCING INDUSTRY
report to
U.S. Environmental Protection Agency
Economic Analysis Section
Office of Water and Hazardous Materials
Washington, D.C. 20460
Partial Fulfillment of
Contract No. 68-01-1541
Task 20
July 31, 1975
nta, protection Agency
Environmental rru
...-y'ift'V
-------
PREFACE
The attached document is a contractor's study prepared for the
Office of Water and Hazardous Materials, Economic Analysis Section, of
the Environmental Protection Agency ("EPA"). The purpose of the study
is to analyze the economic impact which could result from the applica-
tion of alternative effluent limitation guidelines and standards of
performance to be established under sections 304(b) and 306 of the
Federal Water Pollution Control Act, as amended.
The study supplements the technical study ("EPA Development Docu-
ment") supporting the issuance of international regulations under
sections 304(b) and 306. The Development Document surveys existing and
potential waste treatment control methods and technology within parti-
cular industrial source categories and supports the proposal based upon
an analysis of the feasibility of these guidelines and standards in
accordance with the requirements of sections 304(b) and 306 of the Act.
Presented in the Development Document are the investment and operating
costs associated with various alternative control and treatment techno-
logies. The attached document supplements this analysis by estimating
the broader economic effects which might result from the required appli-
cations of various control methods and technologies. This study
investigates the effect of alternative approaches in terms of product
price increases, effects upon employment and the continued viability of
affected plants, effects upon foreign trade and other competitive effects.
The study has been prepared with the supervision and review of the
Office of Water and Hazardous Materials, Economic Analysis Section of EPA.
-------
This report was submitted in partial fulfillment of Contract No. BOA
68-01-1541, Task Order No. 20, by Arthur D. Little, Inc., Cambridge,
Massachusetts. Work was completed as of July, 1975.
This report is being released and circulated at approximately the
same time as publication in the Federal Register of a notice of interim
final and proposed rule making under sections 304(b) and 306 of the Act for
the subject point source category. The study is not an official EPA publica-
tion. It will be considered along with the information contained in the
Development Document and any comments received by EPA on either document
before or during proposed rule making proceedings necessary to establish
final regulations. Prior to final promulgation of regulations, the
accompanying study shall have standing in any EPA proceeding or court
proceeding only to the extent that it represents the views of the con-
tractor who studied the subject industry. It cannot be cited, referenced,
or represented in any respect in any such proceeding as a statement of
EPA's views regarding the subject industry.
-------
TABLE OF CONTENTS
I. EXECUTIVE SUMMARY 1-1
I.I. SCOPE OF WORK 1-1
1.2. INDUSTRY DESCRIPTION 1-2
1.3. SUMMARY OF CONCLUSIONS 1-4
II. CHARACTERIZATION OF THE OFFSHORE OIL AND GAS II-1
EXTRACTION INDUSTRY
II.1. INDUSTRY STRUCTURE II-1
1.1. Industry Definition II-1
1.2. Offshore Oil and Gas Production II-l
1.3. Demand for Oil and Gas II-7
1.4. Oil and Gas Supply/Demand II-8
II.2. CHARACTERIZATION OF OFFSHORE OIL AND GAS PRODUCING 11-21
COMPANIES
II.3. OIL AND GAS PRICING 11-30
3.1. Crude Oil Pricing 11-30
• The Role of Crude Prices in the Economic 11-30
Impact Analysis
• Current Crude Oil Pricing Patterns 11-31
3.2. Pricing of Offshore Natural Gas at the Wellhead 11-41
• Introduction 11-41
• Regulation of Natural Gas Producers 11-47
• Nationwide Costs of Finding and Producing 11-51
Non-Associated Gas
• Successful Wells Cost 11-53
• Dry Holes 11-53
• Operating Expense 11-55
• Return on Investment 11-55
• Some Conclusions 11-57
-------
II.4. FINANCIAL CHARACTERISTICS 11-61
4.1. The Role of Financial Characteristics in the 11-61
Economic Impact Analysis
4.2. Income Statements and Profitability 11-62
4.3. Capital Requirements 11-71
4.4. Capital Structure 11-84
4.5. Cost of Capital 11-90
» Introduction 11-90
• Weighted Average Cost of Capital 11-90
• Estimate of the Cost of Debt 11-91
• Estimate of the Cost of Equity 11-91
• Estimate of the Cost of Capital for the 11-93
Petroleum Industry
III. PROPOSED EFFLUENT LIMITATION GUIDELINES III-l
III.l. PROPOSED EPA REGULATIONS III-l
III.2. CURRENT REGULATIONS III-8
• California State Waters III-9
• Alaska State Waters III-9
• Louisiana State Waters III-9
• Texas State Waters III-9
III.3. COST OF POLLUTION ABATEMENT SYSTEMS 111-10
IV. IMPACT ASSESSMENT METHODOLOGY IV-1
IV.1. INTRODUCTION IV-i
IV.2. GENERAL APPROACH IV-3
2.1. Producers Absorb All Costs IV-3
2.2. Producers Pass On All Costs IV-7
IV.3. PRODUCTION ECONOMICS IV-8
3.1. The Bureau of Mines Model Production Unit IV-8
3.2. Operating Costs IV-11
3.4. Investment Costs IV-22
-------
Page
IV.4. AFTER TAX CASH FLOWS FOR EACH PRODUCTION UNIT IV-24
IV.5. NO ALLOWANCE FOR COSTS OF TRANSPORTING OIL AND GAS IV-25
ONSHORE
IV.6. COMPUTER PROGRAM IV-27
V. ANALYSIS OF THE DATA BASE V-l
V.I. INTRODUCTION V-l
V.2. GEOGRAPHICAL SEGMENTATION OF OFFSHORE OIL AND GAS V-l
PRODUCTION
V.3. SOURCE OF DATA AND GENERALIZATION USED IN THE ANALYSIS V-4
3.1. Introduction V-4
3.2. The Size and Number of Production Units Present V-5
in Offshore Areas
3.3. Estimates of the Annual Volumes of Oil, Gas, and V-9
Water Produced and Estimates of the Annual Pro-
duction Decline Rates
3.4. Production Units in State Waters and Cook Inlet, V-17
Alaska
VI. ECONOMIC IMPACT ANALYSIS VI-1
VI.1. SUMMARY VI-1
VI.2. FEDERAL WATERS: BASE CASE RESULTS FOR OIL WELLS AND VI-9
GAS WELLS
• Federal Waters; Sensitivity Tests by Changes in VI-13
Base Case Parameters
• Average Cost Increases for Oil and Gas, Federal Waters VI-20
VI.3. STATE WATERS: BASE CASE RESULTS FOR OIL WELLS AND VI-22
GAS WELLS
• State Waters; Sensitivity Tests by Changes in Base VI-28
Case Parameters
• Likely Average Cost Increases for Oil and Gas, State VI-34
Waters
-------
Page
VI.4. ALASKA, RESULTS OF A PRELIMINARY IMPACT ANALYSIS VI-36
VI.5. CALIFORNIA VI-43
VI.6. INFERRED IMPACT, EXISTING SOURCES IN THE GULF OF VI-46
MEXICO
VI.7. INFERRED IMPACT, NEW SOURCES IN THE GULF OF VI-50
MEXICO
VI.8. DIRECT ENERGY EFFECTIVENESS OF TREATMENT EQUIPMENT VI-55
VI.9. ECONOMIC COST PER BARREL RECOVERED VI-59
-------
LIST OF TABLES
No. Page
1-1 Summary of Economic Impacts, The Offshore 1-8 & 1-9
Oil and Gas Extraction Industry
II-l Crude Oil and Condensate Production, II-4
Total Offshore "State" and "Federal OCS"
II-2 Natural Gas Production, Total Offshore II-5
"State" and "Federal OCS"
II-3 Total United States and Outer Continental II-6
Shelf Production of Crude Oil and Condensate,
and Natural Gas, Percentage of OCS Production
of Total U.S. Production
II-4 U.S. Energy Demand by Primary Source - 1972 II-9
and 1970
II-5 U.S. Energy Demand by Primary Source - 1985 11-13
II-6 U.S. Crude Oil Production - 1974 to 1985 11-15
II-7 Potential Rates of U.S. Oil Production 11-16
II-8 U.S. Natural Gas Supplies, 1972-1985 11-17
II-9 OCS Lease Acreage and Production, Through 11-22
September 1971
11-10 Louisiana Land and Exploration Co., Docket No. 11-23 & 11-24
C173-501, Joint Ownership of Federal Offshore
Producing Leases
11-11 Louisiana Land and Exploration Co., Docket No. 11-25
C173-501, Joint Ownership of State of
Louisiana Petroleum Leases by Large Major
Producers
11-12 Louisiana Land and Exploration Co., Docket No. 11-27
C173-501, Major Interstate Gas Pipelines and
Their Producing Affiliates
11-13 Participation by Interstate Pipeline Company 11-28
Affiliates in Offshore Louisiana Federal Oil
and Gas Lease Sale, September 12, 1972
-------
No. Page
11-14 Participation by Interstate Pipeline Company 11-29
Affiliates in Offshore Louisiana Federal Oil
and Gas Lease Sale, December 19, 1972
11-15 Historical Posted Crude Oil Prices 11-32
11-16 Representative Posted Prices and Actual Costs 11-35
Per Barrel of Foreign Equity Crudes and
U.S. Crudes
11-17 Delivered Prices of Foreign and Average 11-37
Mix Domestic Crude
11-18 Delivered Price of Foreign and Decontrolled 11-38
Domestic Crudes
11-19 Prices Received by Producers for Natural Gas 11-42
Sales, 1966-1975
11-20 Lower 48 State Net Reserve Additions, Inter- 11-43
state vs. Intrastate
11-21 Estimated New Long-Tera Contract Sales by Large 11-45
Producers, 1970-1973, Offshore Federal Domain
vs. All Areas
11-22 Gas Exploratory Footage 11-46
11-23 Gas Development Footage 11-46
11-24 Estimated Nationwide Cost of Finding and 11-52
Producing Non-Associated Gas
11-25 Income Statement of Chase Group for 1971, 1972, 11-63
and 1973
11-26 Net Income After Tax and the Rate of Return on 11-67
Equity of 22 U.S. Oil Companies (1963-73)
11-27 Rates of Return for Chase Group: 1971, 1972, 1973 11-68
11-28 1973 Financial Figures for Offshore Producers 11-69
11-29 Comparison of Capital Requirements Estimates: 11-72
Total Dollars, Cumulative 1975-1985
11-30 Estimates of Petroleum Industry Capital Require- 11-74
ments
11-31 Cash Flow of Chase Group for 1973 11-76
-------
No.
11-32 Source and Use of Capital for Chase Group in 11-77
1973
11-33 Estimated Capital and Exploration Expenditures 11-79
of U.S. Oil Industry
11-34 Estimated Capital and Exploration Expenditures 11-81
11-35 Exploration and Development Expenditures in the 11-82
U.S.: 1972 and 1973
11-36 Typical Yearly Capital Expenditures of Segments 11-83
of the Oil Industry in the U.S.
11-37 Balance Sheet of Chase Group, 1973, 1972, 1971 11-85
11-38 Petroleum Industry Capitalization, 1972 11-86
11-39 Example of Calculation of Cost of Capital for 11-94
1971-1974
11-40 Oil Stock Prices 11-96
III-l Applicability of Proposed Guidelines III-3
III-2 Proposed Effluent Guidelines III-4
III-3 - Distribution of Effluent Samples from Exemplary III-6
Treatment Systems
III-4 Pollution Abatement Equipment Costs: Offshore 111-12
Gulf of Mexico
III-5 Distribution of Different Treatment Tech- HI-15
nologies Currently Being Used Offshore
Louisiana in Federal and State Waters
IV-1 Possible Alternative Outcomes of an Investment IV-4
Analysis in New Treatment Facilities in 1977
for a Production Unit in State Waters
IV-2 Sample Operating Costs IV-13 •
IV-15
IV-3 Calculation of Annual Production for the BOM IV-18
Model Production Unit, Assuming a 15% Annual
Decline Rate
-------
No. Page
IV-4 Calculation of Operating Costs in $/B and IV-19
B/D per Completion
V-l Average Daily U.S. Offshore Oil and Lease V-2
Condensate Production in 1974
V-2 Number of Oil and Gas Platforms Considered V-6
and Total Number of Platforms Present in
Offshore Areas
V-3 Gulf of Mexico, Federal Waters; Distribution of V-8
Multi-Well Oil and Gas Producing Platforms
Over Leaseblocks
V-4 Louisiana Federal Waters, Number of Oil Pro- V-10
dueing Platforms Ranked by Total Average Daily
Water Production
V-5 Louisiana Federal Waters, Number of Gas Pro- V-ll
ducing Platforms Ranked by Total Average Daily
Gas and Daily Water Production
V-6 Actual Production in 1973/1974 Compared with the V-16
Production in 1973/1974 Implied by the Use of
Allowables in the Analysis
V-7 Size Distribution of Production Units in Gulf of V-18
Mexico Federal Waters and in Louisiana State
Waters
VI-1 Range of Likely Impact in the Gulf of Mexico, VI-3
Federal and State Waters
VI-2 Range of Average Cost Increases in the Gulf of VI-5
Mexico, Federal and State Waters
VI-3 Federal Waters - Oil, Producers Absorb All Costs VI-10
VI-4 Federal Waters - Gas, Producers Absorb All Costs VI-12
VI-5 Sensitivity of Results to Changes in Key VI-14
Variables - Oil
VI-6 Sensitivity of Results to Changes in Key VI-15
Variables - Gas
-------
No. Page
VI-7 Range of Likely Impact in the Gulf of Mexico, VI-19
Federal Waters
VI-8 Range for Likely Average Cost Increases in VI-21
1977 for Producers in Federal Waters,
Gulf of Mexico
VI-9 State Waters - Oil, Producers Absorb All Costs VI-24
VI-10 State Waters - Gas, Producers Absorb All Costs VI-25
VI-11 Reinjection Required in 1983, Range of Likely VI-29
Impact in Louisiana, State Waters
Vl-lla No Reinjection Required in 1983, Range of VI-30
Likely Impact in Louisiana, State Waters
VI-12 Sensitivity of Results to Changes in Key VI-32
Variables, State Waters, Reinjection Required,
Oil
VI-13 Sensitivity of Results to Changes in Key VI-33
Variables, State Waters, Reinjection Required,
Gas, Producers Absorb All Costs
VI-14 Likely Average Cost Increase in 1977 and 1983 VI-35
for Producers in State Waters
VI-15 1973 Statistics on Oil and Gas Fields Offshore VI-37
Alaska, Cook Inlet
VI-16 Alaska, Cook Inlet, Preliminary Estimate of VI-39
Likely Impact
VI-17 Alaska, Cook Inlet, Preliminary Estimates of VI-41
Likely Impact
VI-18 California; Platforms and Offshore Oil, Gas VI-44
and Water Production in 1973
VI-19 Total Inferred Impact for Existing Sources in VI-47
the Gulf of Mexico as Derived from the
Measured Impact
VI-20 Total Inferred Impact for New Sources in the VI-48
Gulf of Mexico
VI-21 Total Inferred Impact for New Sources Offshore VI-52
U.S.A.
-------
No. Page
VI-22 Economic Cost per Barrel of Oil Recovered, VI-61
Federal Waters
VI-23 Economic Cost per Barrel of Oil Recovered, Vl-62
State Waters
-------
LIST OF FIGURES
No. Page
II-l 1977 U.S. Petroleum Supply and Demand 11-19
Functions (Accelerated Development Scenario)
II-2 Non-Associated Gas Reserves Additions per 11-54
Foot Drilled in Wells Productive of Gas and
Condensate, United States Excluding Alaska,
1947-1972
II-3A New Contract Production 11-60
II-3B New Field Wildcats Drilled 11-60
II-3C New Contract Gas Price 11-60
II-4 After Tax Return on Net Worth, Petroleum vs. 11-66
Other Manufacturing Companies - 1960 to
1970
IV-1 Lease Plat Showing Platforms, Wells, and Flow IV-9
Lines in Model
IV-2 Scheme of Production Platform A, Model of a IV-10
Gulf of Mexico Operation
IV-3 Operating Costs (in $/B) Versus Average IV-20
Completion Productivity
IV-4 Age Distribution on Platforms in Louisiana IV-22
Gulf Coast (Federal and State Waters)
IV-5 Total Investment in Production Unit as a IV-23
Function of Number of Platforms in Unit,
Total Production Capacity of Unit
IV-6 Computer Flow Diagram, Federal Waters IV-28
IV-7 Computer Flow Diagram, State Waters IV-29
V-l Percentage of Gas and Oil Producing Platforms V-13
with Daily Water Production Less Than or
Equal to Water Production
-------
No. Page
VI-1 Sensitivity Tests, Gulf of Mexico, VI-17
Federal Waters
VI-2 Sensitivity Tests: Louisiana, State Waters; VI-27
Gulf of Mexico, Federal waters
VI-3 Power Requirements for Brine Treatment VI-57
Systems
-------
I. EXECUTIVE SUMMARY
I.I. SCOPE OF WORK
The U. S. Environmental Protection Agency (EPA) is issuing interim
final effluent guidelines for the 1977 Best Practicable Technology Currently
Available and .proposed effluent guidelines for the 1983 Best Available Tech-
nology and the New Source Performance Standards for offshore oil and gas
production. An economic impact analysis of the guidelines was performed by
Arthur D. Little, Inc. (ADL), under contract with the EPA and is reported
here.
The economic impact analysis evaluated how many well completions would
be shut in rather than brought into compliance, the investment required by
the operators to come into compliance, and how much oil and gas production
would be foregone as a result of the guidelines.
The impact analysis used costs of compliance developed by EPA and given
a general review by ADL. The capability of the assumed treatment technologies
to meet the effluent standard and the availability of platform space for
installing the equipment has not been evaluated by ADL.
Oil and gas is currently produced from three offshore U.S. areas: the
Gulf of Mexico, California, and Alaska's Cook Inlet. In 1973 the Gulf of
Mexico produced 74% of U.S. offshore oil and 97% of offshore gas. California
produced 15% and 1%, respectively, and Alaska produced 11% and 2% of offshore
oil and gas.
The economic impact analysis deals principally with the regulation's
effects in the Gulf of Mexico. This is the area with the majority of production
1-1
-------
and the area to experience the major impact. Over 95% of the production
from offshore California leases appears to be in compliance at this time
with the 1983 treatment requirement. The potential impact of the guidelines
on Cook Inlet production has not been possible to treat completely because
of a lack of relevant data on the costs of production and the costs of treat-
ment and reinjection. The potential impacts on Cook Inlet production have
been discussed qualitatively.
1.2. INDUSTRY DESCRIPTION
Beginning in the late 1940's, oil and gas have been produced from fields
off the U.S. coast. In 1973, 17% of total United States oil production and
17% of gas production was from offshore wells. While there was a small fall-
off in offshore oil production in the early 1970's, the offshore areas are
generally regarded as an increasingly important source of oil and gas
production.
Historically, offshore operations have been dominated by the larger oil
companies. In 1971, 63% of offshore oil production was from wells owned by
individual majors and another 34% was from wells owned by groups of majors.
The Department of the Interior has encouraged the participation by smaller
firms in recent years and the predominance of the majors is declining.
Revenues from offshore oil production amounted to $1.64 billion as
compared with total U.S. oil production revenues of $10.35 billion in 1973.
Revenues from offshore natural gas production were about $740 million in 1973.
1-2
-------
Prices of oil and gas are partially regulated. Oil sold without
price regulations has a price approximately corresponding to the world
market, while regulated oil is sold at $5.25 per barrel. Natural gas
sold in intrastate markets is selling at prices determined by supply and
demand; however, natural gas sold in interstate markets (the majority
of Gulf of Mexico production) is regulated to be $0.51 per thousand
cubic feet (MCF)).
The prices of both oil and natural gas are a subject of strong
debate. Serious proposals exist to deregulate both old oil and natural
gas in order to encourage more exploration and development of domestic
supplies. On the other hand, major groups, such as segments of the
Congress, believe oil prices in particular are too high and more controls
should be imposed. The economic impact analysis has tested a range of
potential prices since it is not possible to say with any certainty what
future price levels will be.
The profitability of the oil industry has also been a subject of con-
siderable debate. Historically, the industry has been about as profitable
as the average U.S. manufacturing sector. However, a shadow of uncertainty
exists because of pending decisions by Government agencies on a number of
proposals which would vitally affect the industry. Tax policies have
already been changed and may be changed again. Decisions on price controls
and the excess profits taxes are not resolved. The resolution of these
conflicting influences on the industry will be of far greater importance
to its profitability and financial structure than the proposed pollution
abatement regulations
1-3
-------
1.3. SUMMARY OF CONCLUSIONS
Based upon the assumptions stated in the body of this report, the
major conclusions of the economic impact analysis of the proposed
effluent guidelines on offshore U.S. oil and gas production and the
producing companies can be summarized as follows.
1. The capital investment required to bring wells producing in 1974 in
the Gulf of Mexico into compliance will be approximately $64-145
million in 1977 and $50-56 million in 1983 in 1974 dollars. Addi-
tional investment will be required for wells drilled in the Gulf after
1974.
2. Since almost all production from leases off the California coast is
now in compliance with the proposed regulations, additional required
investments will likely be very small, if any.
3. The required investment for bringing offshore Alaska production into
compliance has not been determined. The costs will be higher than
in the Gulf of Mexico on a per barrel of water treated basis.
4. The average costs including capital recovery of producing oil from wells
completed in or prior to 1974 in the Gulf of Mexico will be increased
by about 9-31 cents per barrel in federal waters and about 12-16 cents
per barrel in state waters in 1977. The production cost increase
in state waters in 1983 will
1-4
-------
be about $.77-$1.08 per barrel. The costs of producing natural
gas from gas wells in the Gulf will be increased by less than one-half
cent per MCF in federal waters and state waters in 1977. The estimated
increase in production costs in 1983 will be about one cent per MCF
in state waters. Production cost increases associated with California
wells are expected to be negligible.
5. For oil wells producing in 1974 in the Gulf of Mexico, and for which
no price increases are possible, the effluent guidelines will result
in 14-28 million barrels of oil and lease condensate not being ulti-
mately produced, due primarily to shortened well life after 1983
rather than well closures in 1977 or 1983. The foregone production
represents 0.6% to 1.2% of the total remaining potential production
from the wells from 1977 to the end of their economic life, which may
be beyond the year 2000, in the absence of the guidelines. Similarly,
the foregone production of non-associated and associated natural gas
will be 81 to 249 million MCF in the absence of price increases to
recover the costs which represent 03% to 1.0% of the total potential
production from 1977 on.
6. There will be no closures of companies as a direct result
of application of the guidelines.
7. There will be no significant effects on the profitability of the
industry as a whole. The profitability of firms operating primarily
in state waters might be affected.
1-5
-------
8. The added estimated investment in offshore treatment and reinjection
equipment for the Gulf of Mexico represents approximately 0.2-0.4%
of expected total industry capital investment in offshore production
($48 billion) during the 1976-1983 period. As such, the pollution
abatement-related investment should not materially alter investment
plans of the industry.
9. The guidelines are not expected to discourage the exploration for or
development of new oil or gas wells. However, the total lifetime
production of the new wells will be reduced. The 0.6% to 1.2% re-
duction in volume produced over the remaining lifetime in the absence
of price increases of existing oil wells in the Gulf of Mexico can
be regarded as an upper limit to the percentage reduction in total
lifetime production of oil from new wells. It's an upper limit because
the value of total lifetime production of the wells producing in 1977
is significantly larger than their remaining lifetime production value
as of 1977. The 0.3% to 1.0% loss of remaining gas production can
also be regarded as an upper limit for the foregone gas production
from new wells if price increases are not possible to recover the
pollution abatement costs for the same reason.
10. U.S. crude oil prices are now controlled (old oil) or move with the
world oil price (new or released oil). The higher production costs
resulting from compliance with the proposed regulations may be re-
coverable through allowed increases in old oil prices, though such an
allowance is not assured, nor are the procedures for allowing such
an increase well established. The higher production costs associated
1-6
-------
with uncontrolled oil already priced competitively with imported oil
will likely not be recovered through price increases directly resulting
from the added pollution control cost. The added operating costs of
pollution control would result primarily in reduced revenues for the
producer.
11. The increases in the costs of producing interstate natural gas (the
majority of Gulf of Mexico production) will probably be substantially
recovered by price increases approved by the FPC. The procedure for
allowing such cost recoveries is well established, though cumbersome,
and the pattern of recent FPC decisions indicates that the FPC would
rule favorably on price increases to recover increased operating costs
as a result of new government regulations.
12. The reduction in U.S. oil and gas production will be made up primarily
by imports. At $11 per barrel, the foregone oil production from wells
producing in 1974 represents $154 to $306 million in oil purchases
abroad which would not otherwise have been made over about 25 years.
The lost gas production from 1974 wells would require purchases of
$162-498 million of foreign natural gas at $2.00 per MCF also over
about 25 years. The required purchase of imported oil and gas
assumes the foregone domestic production will not be replaced by coal,
or nuclear power, and that U.S. domestic production will not equal
U.S. demand over the 25 year period.
1-7
-------
TABLE 1-1
SUMMARY OF ECONOMIC IMPACTS
THE OFFSHORE OIL AND GAS EXTRACTION INDUSTRY
(Portion of SIC 1311)
Industry Description
Number of Platforms
Number of Platforms
Directly Discharging
Number of Platforms with
BPCTCA in Place
Costs (1974 Dollars)
(Gulf of Mexico wells producing
in 1974)
Total for Industry
Average per Platform
Percent of Average Annual
Investment in Offshore
Production
Annual
Total for Industry
Average per Platform
Percent of Sales
Oil (Federal waters)
Gas (Federal waters)
Expected Price Increases
(due to added pollution
control costs)
Oil
Gas
Platform Closures
(rather than invest in
abatement equipment)
Gulf of Mexico
750
510
180
California
14
0
14
BPCTCA
$64-145 million
.11-.25 million
1-2%
$36-78 million
$71-153 thousand
1Z-3Z
none
< 0.5%
Alaska
14
14
NA
BATEA
$50-56 million
.09-.10 million
0.7%
$20 million
$40 thousand
none
none
none
27
1-8
-------
TABLE 1-1 (Con't)
BPCTCA
BATEA
Foregone Production
(between 1977 and 2000)
(from wells producing in 1974)
Oil
Gas
Jobs Lost
Community Effects
Impact on Industry Growth
Balance of Payment Effects
(Over 25 years)
14-28 million bbl's
(0.6v%-1.2% of potential)
80-250 million MCF
(0.3%-1.0% of potential)
none
none
none
$316 to $804 million
none
none
none
SOURCE; Arthur D. Little, Inc., estimates
1-9
-------
II. CHARACTERIZATION OF THE OFFSHORE OIL AND GAS EXTRACTION INDUSTRY
II.1. INDUSTRY STRUCTURE
1.1. Industry Definition
The activities of the oil and gas industry to be covered by the pro-
posed and interim final effluent limitation guidelines and the New Source
Performance Standards include production from offshore oil and gas wells.
This report applies only to those offshore production facilities
physically attached to and an integral part of the production equipment.
Firms which are primarily engaged in contract exploration activities or
contract drilling of wells are not covered by the effluent guidelines.
The drilling and exploration activities of firms operating offshore wells
are also not covered by the regulations.
1.2. Offshore Oil and Gas Production
Following lease sales to interested parties, the first phase of off-
shore development begins with exploratory drilling from mobile drilling
rigs which are positioned over suitable geological features located pre-
viously by geophysical techniques. The purposes of exploratory drilling
are to define the existence of oil and/or gas fields. Results of explora-
tory drilling are used to establish a plan for the development of the
newly discovered accumulations. Several or more wells may be drilled to
confirm or deny the presence of hydrocarbons on any given oil and gas
prospect.
II-l
-------
The second phase of offshore development begins with the installa-
tion of fixed platforms from which a number of wells are directionally
drilled to tap the hydrocarbon pools existing in the oil and gas field.
Offshore drilling procedures are much the same as drilling on land,
except that marine drilling requires special equipment and considerable
logistical support with resulting higher costs/foot drilled than on on-
shore prospects.
The engineering, construction, and operation of fixed offshore
platforms has evolved gradually since the first well was drilled out of
sight of land off of the coast of Louisiana in 1947. As offshore development
activity has moved into deeper waters and increasingly hostile environments,
fixed platforms have become extremely large, self-contained facilities which
can support as many as 30 or 40 development wells. As the majority or all of
the development wells from a platform are completed, the platform begins
production of one or a combination of crude oil, natural gas and gas conden-
sate. Formation water — typically a salt brine — is usually produced in
conjunction with oil.
Typically, several producing platforms are linked by a pipeline
gathering system to a centrally located production processing platform.
If oil and gas are produced in association with each other (a common case),
the two are separated at the processing platform. When only gas is pro-
duced, it may require removal of associated water (dehydration). Formation
water produced with oil is separated and disposed of.
II-2
-------
The producing areas discussed in this report are located off the
coasts of Louisiana, Texas, California, and Alaska. Leases have also
been sold on acreage off Mississippi, Alabama, and Florida, and produc-
tion is expected in these areas. The offshore areas are divided into
those in state waters within the three mile limit and those beyond the
three mile limit in Federal waters. The Federal waters are called the
Outer Continental Shelf (DCS).
Table II-l lists the historical totals for offshore production of oil
and condensate. Table II-2 lists the natural gas production, and Table II-3
compares the offshore production with total U.S. production of oil and gas.
As shown in Table II-3, total oil production peaked in 1970 at 3.5
billion barrels and declined in 1973 to 3.4 billion barrels. While the DCS
has a large potential for new production, 1971 saw a peak DCS production
of 419 million barrels which declined to 395 million barrels in 1973. OCS
production accounted for about 12% of total U.S. oil production for 1971,
1972, and 1973, up from 4.4% in 1964. Total U.S. gas production only increased
from 20.7 trillion cubic feet in 1969 to 22.9 trillion cubic feet in 1973.
The percent of OCS gas production increased from 9.4% to 14% over the same
period.
In all of the states except Alaska, where there has been a jurisdic-
tional dispute, the relative importance of the producing areas has moved
from the state waters to the deeper OCS waters. Louisiana produced 429
million of the 583 million barrels of total offshore oil production and 3.6
trillion of the 3.9 trillion cubic feet of offshore gas production. Louisiana's
oil production is 87% from OCS waters, while 21% of California's is from the OCS.
II-3
-------
TABLE II-l
CRUDE OIL AND CONDENSATE PRODUCTION
TOTAL OFFSHORE "STATE" AND "FEDERAL CCS"
IN THOUSANDS OF BARRELS (M)
: : ALASKA
: Year :
PRIOR
1954
1955
1956
1957
1952
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Through
1973
SOURCE:
Barrels
(M)
_
_
_
-
—
_
_
_
_
6
30
2,650
15,937
52,530
60,887
70,007
66,152
63,749
61,715
393,663
Bureau
: Percent
: CALIFORNL4
: Barrels:
: State :OCS : (M) :
— —
^^ ••
_ _
_ —
_ —
_ —
— —
— —
-
_ _
100
100
100
100
100
100
100
100
100
100
100
of Mines,
H22,385
32,665
33,2^2
32,343
30,^61
28,363
26,737
28, 07l|
29,887
34,613
3S,346
40,526
42,772
53,29U
64,807
25,339
96,145
104,283
101,717
95,418
89,218
1,510,800
Percent
State
IOC
100
100
100
100
100
100
100
100
100
100
100
100
100
100
98
90
76
69
76
79
93
Alaska Scouting
:OCS
_
_
_
—
_
_
_
_
_
_
_
_
-
2
10
24
31
24
21
7
: LOUISIANA
: Barrels: Percent
: (M)
54,803
15,926
25,731
40,906
52,835
57,3Si
72,793
88,122
103,197
126,801
149,087
173,709
199,293
243,080
284,033
329,922
365,691
398,378
444,363
452,584
429,465
4,108,100
: State
98
79
y]|
73
70
57
51
32
29
30
29
27
23
23
20
IS
16
13
14
13
24
:OCS
2
21
26
C. 1
30
43
49
56
62
71
70
71
73
77
77
80
82
84
87
86
87
76
: TEXAS :
TOTAL
: Barrels-: Percent : Barrels
: (M)
_
10
156
140
2S6
470
4'J9
567
292
803
669
572
557
1,246
3,400
3,400
3,109
3,046
2,885
3,035
3,018
28,136
Service, Conservation Committee
: State
__
100
99
90
98
100
100
100
100
100
92
99
99
16
9
11
26
42
43
46
40
:OCS :
_
-
1
10
2
—
—
-
-
-
8
1
1
a
91
89
74
58
57
54
60 6,
of California,
(M)
477,188
Us, 601
59,139
73,394
83,652
86,214
100,079
116,763
133,376
162,217
188,102
214,819
242,652
300,270
368,177
471,191
525,232
575,714
615,117
614,786
583,416
040,699
: Percent
:state:ocs
100 -
93 7
89 11
SS lr>
81 19
71 29
6U 36
57 4^
52 48
45 5^
4l| So
43 57
\ f ~
Uo 60
37 fa
40 G()
43 57
ill |so
37 fa
32 r-p
33 67
32 68
46 54
, Louisiana State
Mineral Board, Louisiana Dept. of Conservation, Texas Railroad Commission.
Louisiana and Texas are estimated in part.
-------
TABLE II-2
NATURAL GAS PRODUCTION
TOTAL OFFSHORE "STATE" AND "FEDERAL OCS"
IN MILLIONS OF CUBIC FEET (MMCF)
M
M
I
: : ALASKA
: Year
: :
Percent
: •' MMCF : State :OCS
PRIOR
19S4
1955
1956
1957
195S
1959
1960
1961
1962
1963
1964
1965
1966
1967
iq6s
1969
1970
1971
19^2
1973
-
-
10
1,200
3,324
22,344
44,393
22,369
83,750
74,982
72,526
-
-
100 -
100 -
100 -
100 -
100 -
100 -
100 -
IOC -
100 -
: CALIFORNIA
• •
Percent
: LOUISIANA
• TEXAS *
: : Percent ' '•
: MMCF :State:OCS : MMCF :state
1,113
5,903
10,671
25,769
35,323
40,770
46,239
116,732
36,^65
31,326
71,225
60,4?4
44,830
37,581
100 -
100 -
100 -
100 -
100 -
100 -
100 -
100 -
99 1
94 6
33 17
71. 26
73 22
81 19
91,575
31,325
121,279
136,p27
160,472
233,967
329,230
402,333
453,431
53S,36l
706, ^5
733,47^
371,124
1,265,399
1,655,223
o oc;7 OGI
^-J^' ( t^-J*-
2,473,745
2,300,104
3,219,200
3,480,831
3,614,^92
7S
31
33
39
U9
45
37
33
31
23
20
21
26
24
34
31
26
19
18
17
15
:OCS
22
?
67
6l
51
55
63
67
69
77
20
79
74
76
66
69
7^
31
82
83
85
: TOTAL :
Percent : :
: MMCF : State
3,4UO
6,320
6,220
13,765
24,030
24,030
30,960
13,760
Ul, 230
30,960
30,960
27,520
59,259
127,473
154,631
240,212
264, '420
38^,245
156,772
15^,000
100
100
100
100
100
100
100
100
100
100
100
100
29
22
29
47
5C
6^
6
6
:OCS
-
_
_
71
73
71
53
50
33
94
Q4
: MMCF :
91,675
24,765
123,159
143,407
174,237
253,047
353,360
440, 46l
473,144
640,312
763,274
249,757
939,424
1,373,197
1,337,752
2,321,331
2,344,676
3,213,113
3,^50,6^9
3,757,415
3,833,999
Percent :
State: OCS :
72
&
&
53
si
41
33
33
29
26
27
31
27
35
^
31
25
26
19
17
22
66
63
58
47
Ho
59
62
67
71
7^
73
69
77
6s
56
f
;>.-.
7^
r4
81
~ o
Through
1973 390,398
100
595,131 91 9 25,543,0^3 23 7^ 1,803,577 48 52 28,332,189 2
73
SOURCE: Bureau of Mines, Alaska Scouting Service, Conservation Committee of California, Louisiana
State Mineral Board, Louisiana Dept. of Conservation, Texas Railroad Commission.
Louisiana and Texas are estimated in part.
-------
TABLE II-3
TOTAL UNITED STATES AND OUTER CONTINENTAL SHELF PRODUCTION
OF CRUDE OIL & CONDENSATE, AND NATURAL GAS
PERCENTAGE OF OCS PRODUCTION OF TOTAL U. S. PRODUCTION
: Year
1953
1954
1955
1956
1957
195S
1959
1960
1961
1962
1963
l§64
1965
1966
196^
1962
1969
1970
)9'/l
1972
1973
SOURCE:
: CRUDE OIL AND
: ("Thousands
: Total U.S. :
2,357,022
2,314,988
2,484,422
2,617,223
2,6l6,901
2,448,987
2,574,590
2,574,933
2,621,758
2,676,189
2,752,723
2,726,822
2,348,514
3,027,763
3,215,7l|2
3,329,042
3,371,751
3,51^,450
3,453,914
3,455,000
3,356,000
CONDENSATE
of Bbls.)
Total r»"
1,151
3,3^
6,705
11,015
16,070
24,769
35,698
49,666
64,330
104^79
122,500
144,969
188,714
221,262
268,996
312,260
36o,646
418,549
411,886
394,730
Total United States Production -
PRODUCTION :
: OCS V. :
Q : of U.S. :
.05 £
.14
.27
.42
.61
l,''.l
1.39
1.93
3*35
7,.20
Z ,4o
5.09
6.23
6.90
8 „ OS
9.22
10.?-
12.12
ll.c:2
11.^6
. MINERALS YEARBOOK
(Million
Total U.S.
5,796 ..516
,-,'^C'' ,"^51
10,OCi,923
10,680^252
11, 030. :/-}S
11,61^,951
12,771,038
13,254,025
13,276,622
1^,666,^59
15 '162 143
16 i [039) 753
17,206,622
12,17:1,32':
I9»3?2»1{oo
20,692,240
21,920,642
22,493,000
27,532,000
?2,°00,000
and Mineral
GAS PRODUCTION
s of Cu.Ft, ) :
: Total OCS :
19,281
56,325
21,279
32,574
127,693
£07,156
273,034
'-18,280
^51,953
r:^,353
621,731
645,539
1,007,447
1,127,216
1,524,172
2 1*! 18,677
2,777,043
3,038,555
3,211,588
Industry Surveys,
:
OCS •>, :
of U.S.:
.24 f
.64
.86
.82
.77
I.l6
1.73
'- •. 1'i
2.40
3.26
3-S5
4.02
4.03
5.86
6.ri^
7.89
9.44
11.03
1 ? . 5 *>
13. "49
14. or
Bur. i. M
1973 Total United States Production data are preliminary and subject to change.
Mines.
-------
1.3. Demand for Oil and Gas
It is not the intention of this report to analyze in detail future
energy demand or supply for the U.S. The report will draw from the work
of reputable sources to broadly sketch the likely demand for oil and gas
over the period of interest. The estimates will then be used as the
background for estimating the impact of the proposed pollution control
requirements on the offshore and onshore industry.
The principal conclusion coming from an examination of the U.S.
demand for crude oil and the available supply is that demand is and will
likely continue to exceed domestic production under most realistic
scenarios. The total demand for crude oil has grown at about 4.5% per
year over the period 1965-1973. This growth, combined with a slow
decline in U.S. production since 1970, has resulted in an increasing
reliance on imports of both crude oil and refined products. Growth in
domestic refining capacity has been less than the growth in U.S. con-
sumption of refined products. The difference has been made up by
importing products from foreign refineries; in 1973, product imports
approximated 17% of total product consumption and were also 46% of both
crude and product imports.
Domestic gas production has historically approximated consumption
and domestic supplies have not been sufficient for several years. As a
result, imports are expected to grow to over 10% of consumption by 1985.
Project Independence Blueprint, Final Task Force Report-Finance, p. 66,
FEA, November 1974.
11-7
-------
Note that the growth in natural gas usage averaged about 6.5% per year
from 1965 through 1970. Annual growth following 1970 has been about
2.5%. U.S. production increased by about 1% per year from 1970 through
1973. The difference has been made up by imports which accounted for
about 7% of consumption in 1974.
1.4. Oil and Gas Supply/Demand
Petroleum and natural gas are primarily consumed as fuels. Prior
to 1973, these energy forms and others were relatively inexpensive in
the United States. The combined effects of industry practices and
government tax and pricing measures served to keep energy prices low.
The measures encouraged gas consumption.
In the last 25 years, there has been a shift from a significant
dependence on coal to meet the U.S. energy demand to a predominant depen-
dence on oil and natural gas. Table II-4 lists the components of U.S.
energy demand for 1970 and 1972. Oil was the primary source of 45.5% of
energy consumed in 1972. Natural gas accounted for 32.3%. In 1950, coal
accounted for 37% of U.S. energy consumption, but coal's share had fallen
to 18% in 1974.
With energy prices low, energy consul Ttion has been regarded as
relatively price inelastic, particularly in the short run. However, the
1973-1974 oil embargo, the rise in imported petroleum prices, and current
interest in energy conservation have highlighted the complex nature of
the energy demand function. Energy consumption depends in a vital way
on a multitude of factors other than the short-run cost of producing the
II-8
-------
TABLE II- 4
U.S. ENERGY DEMAND BY PRIMARY SOURCE - 1972 and 1970
Energy Form 1972 1970
Oil
Quadrillion Btu /year 32.8 (45.5%) 29.6 (44.1%)
MM bbI/day 16.5 14.6
Gas
Quadrillion Btu /year 23.3 (32.3%) 22.0 (32.7%)
Trillion cubic feet/year 22.6 21.4
Coal
Quadrillion Btu/year 12.5 (17.2%) 12.7 (18.9%)
MM Tons /year 517 532
Nuclear
Quadrillion Btu /year 0.6 (0.8%) 0.2 (0.3%)
Hydro and Other
Quadrillion Btu /year 2.9 (4.2%) 2.7 (4.0%)
Total
Quadrillion Btu /year 72.1 (100%) 67.2 (100%)
SOURCE; U.S. Bureau of Mines , cited in Project Independence Blueprint,
Final Task Force Report - Finance, p. A-7, FEA, November 1974
II-9
-------
energy. Use of public transportation, living standards, building codes,
driving habits, land use planning, home heating habits, and industrial
processes are only a few of the factors affecting energy demand. Many
of these factors are a reflection of the long-run price of energy but are
not readily changed in the short run. It is also clear that political
considerations will be an important factor in determining both total
energy usage and the relative use of various energy forms.
Prior to the embargo, total energy consumption was growing at 4.3%
per year. This growth has since been reduced to 3.2% to 3.5% per year.
There was an actual decline of 2% in 1974, but there is no expectation
of a permanent decline trend in the foreseeable future. The growth rate
may be temporarily or permanently lower, but there will be a continuing
and growing demand for new energy.
In the case of petroleum, there is the potential for some substitu-
tion away from oil, such as the conversion of electric power plants to
coal. There is also some potential for an absolute reduction in petro-
leum/energy usage in transportation; smaller cars and public transportation
at least present this possibility. However, at best, the expectation is
for growth in oil demand to be held very low but not to decline. Since
1970, all of the growth in U.S. oil demand has been met by imported oil.
The Project Independence Report examined the potential for reducing the
level of oil imports and concluded that if there were strong government
action to accelerate domestic production and conservation and if world
oil prices were $11 per barrel, it would be possible to end imports by
about 1985. At lower prices and with less vigorous government action,
some level of imports would still be required in 1985.
11-10
-------
The continuing flow of imported oil at least to 1985 at prices
likely to be well in excess of production costs of all but marginal
domestic production will prevent even relatively large increases in the
costs of domestic production from acting to reduce demand for the domes-
tic crude below domestic production capacity. Either increases or
decreases in total U.S. petroleum demand will mean changes in the level
of imports, not the level of U.S. petroleum production. This pattern
will be particularly true for wells which are now in production. Some
individual wells which are now high cost producers will be made uneco-
nomical by the higher production cost resulting from pollution control
requirements. Short of domestic discoveries of unprecedented magnitude
and productivity, the demand for domestically produced oil will continue
to be well in excess of U.S. production capacity.
A similar situation is seen in the case of natural gas. There is
long-term potential for some substitution away from gas, for example, to
nuclear power and coal for electric power generation. Imports are not
yet as important a factor as in oil, since the volume is not as great.
Unlike oil, interstate gas is usually sold under long-term contracts
at regulated prices,which at present are low relative to the costs of
developing new gas wells or of close substitutes like oil. Interstate
natural gas prices were (1974) 1/3 to 1/4 of the price of fuel oil prices
per BTU in major natural gas consuming areas. Since the price of natural
gas is presently well below the next most expensive substitute, it is
unlikely that even relatively large pollution control costs, by themselves,
would have the effect of shifting demand away from gas to substitute
11-11
-------
products. The overall demand for natural gas will thus not be reduced
below U.S. supply capacity. However, the supply might be affected if
some individual wells were made uneconomical as a result of higher pol-
lution control costs.
Many estimates have been made of the future demand and supply of
oil and gas. For this study, the estimates made in the Project Indepen-
dence Blueprint Report, November 1974, have been used. The report
presents a series of estimates under different sets of assumptions. The
assumptions include different levels of government efforts to encourage
energy conservation, to accelerate domestic energy production, and the
level of OPEC oil prices. The report makes clear that there are both
choices and uncertainties. The oil and gas estimates are used in this
report in that light.
The report constructed a set of estimates for a "base case" and
"accelerated supply case" under both a $7 and $11 per barrel world oil
price. Table II- 5 lists the estimated U.S. energy demand by form, with
imported oil reported separately. The base case assumed that government
policy towards energy, and particularly petroleum production, will be
essentially unchanged. Leasing on the Outer Continental Shelf (OCS) will
remain at about 2-3 million acres per year. Government royalties for
Organization of Petroleum Exporting Countries, including Saudi Arabia,
Iran, Venezuela, Nigeria, Libya, Kuwait, Iraq, United Arab Emirates,
Algeria, Indonesia, Qatar, Ecuador and Gabon, which is an associate
member. The United Arab Emirates is a federation of Abu Dhabi, Dubai,
Sharjah, Ajman, Umm al Quwain, Ras Al Khaimah and Fujairah.
11-12
-------
TABLE II-5
U.S. ENERGY DEMAND BY PRIMARY SOURCE - 1985
(Quadrillion Btu's)
Total
72.1
1985
Energy Form
U.S. Oil
Imported Oil
Gas
Coal
Hydro & Geo.
Nuclear
Synthetics
1972
22.4
11.7
22.1
12.5
2.9
0.6
$7
Base Case
23.1
24.8
23.8
19.9
4.8
12.5
Oil
Accelerated
30.5
17.1
24.7
17.7
4.8
14.7
$11
Base Case
31.3
6.5
24.8
22.9
4.8
12.5
Oil
Accelerated
38.0
0.0
25.5
20.7
4.8
14.7
109.1
109.6
102.9
104.2
SOURCE: Project Independence Report, FEA, November 1974, p. 45
11-13
-------
the leases would remain at one-sixth. Natural gas for interstate sale
would be regulated at $0.89 per thousand cubic feet. Under the "accele-
rated development" case, leasing would be increased to 10 million acres
per year, and royalties would be reduced to one-eighth. Natural gas
price regulations would be ended, with prices rising to $1.75 per thousand
cubic feet by 1988. Development would also be allowed in the Naval
petroleum reserves.
The values in Table II-5 reflect FEA's estimate (based on $7/bbl
crude) of long-term growth rate of U.S. energy consumption (3.1%/year).
At oil prices of $11 per barrel, the annual energy growth rate was esti-
mated to be 2.9%. There is some shift away from oil to gas and coal,
but not a significant reduction in overall energy demand. The projection
of such reductions from the historic growth rate of 4.3% are an important
uncertainty in the analysis.
Table II-6 is a more detailed listing of U.S. oil production esti-
mates with the additional estimate of production levels if the world
price dropped to $4 per barrel. In all cases, domestic production would
continue to decline out to 1977. Table II-7 lists the estimated sources
of new U.S. oil production if the world oil price is $11 per barrel.
Offshore production amounts to 2.9 million barrels per day, or 19% of
the total U.S. production, under the "business as usual" (base case)
scenario in 1985. New DCS production is 4.8 million barrels per day
(24%) under the accelerated development case.
Table II-8 lists the estimated gas production assuming the $11 per
barrel world oil price and accelerated development. The report saw very
11-14
-------
TABLE II-6
U.S. CRUDE OIL PRODUCTION - 1974 TO 1985
(millions barrels per day)
"Business as Usual" Case
World Price ($/bbl) 1974 1977 1980 1985
4
7
11
4
7
11
10.5
10.5
10.5
9.0
9.5
9.9
9.3
11.1
12.2
9.8
11.9
15.0
"Accelerated Development" Case
10.5
10.5
10.5
9.7
10.2
10.3
11.1
12.9
13.5
11.6
16.6
20.0
SOURCE: Project Independence Report, FEA, November 1974, p. 81
II-15
-------
TABLE II- 7
Production Area
Onshore - Lower 48 States
- Conventional fie
primary fields
- New secondary
- New tertiary
- Natural gas liquids
- Naval Petroleum
Alaska
- North Slope
- Gulf of Mexico
- California DCS
- Atlantic DCS
4. Heavy Crude and Tar Sands
POTENTIAL RATES OF U.S. OIL PRODUCTION
if barrels per day, at $11 per barrel world prices)
"Business
1974 As Usual"
:ates 8.9 9.1
i and new
6.4 3.4
2.4
1.8
; 2.0 1.5
:erve #1
0.2 3.0
2.5
icluding DCS) 0.2 0.5
ierve #4 - -
Cental Shelf 1.4 2.6
1.3 2.1
0.1 0.5
-
lands - 0.3
1985
(change)
(1.2)
(-3.0)
(2.4)
(1.8)
(-0.5)
(2.8)
(2.5)
(0.3)
^
(1.2)
(0.8)
(0.4)
(0.3)
"Accelerated
Development"
9.9
3.5
2.4
2.3
1.6
0.2
5.3
2.5
0.8
2.0
4.3
2.5
1.3
0.5
0.5
(change)
(1.0)
(-2.9)
(2.4)
(2.3)
(-0.4)
(0.2)
(5.1)
(2.5)
(0.6)
(2.0)
(2.9)
(1.2)
(1.2)
(0.5)
(0.5)
Total Potential Production
10.5
15.0
(4.5)
20.0
(9.5)
SOURCE: Project Independence Report, FEA, November 1974, p. 83
11-16
-------
TABLE II-8
U.S. NATURAL GAS SUPPLIES, 1972-1985*
(trillions of cubic feet per year)
Source 1972 1977 1980 1985
Lower 48 States,Onshore 19.4 16.7 17.4 15.5
Lower 48 States, Offshore 3.0 4.4 6.1 8.2
Alaska (except North Slope) 0.08 0.02 0.03 0.1
Naval Petroleum Reserve #4 0.0 0.0 0.0 0.8
North Slope 0.0 0.0 0.8 2.5
Coal Conversion 0.0 0.0 0.0 0.2
TOTAL 22.5 21.1 24.3 27.3
*
Assumes $11 per barrel world oil prices and accelerated development scenario.
SOURCE; Project Independence Report, FEA, November 1974 , p. 48
11-17
-------
limited potential for U.S.-produced gas to maintain its present share
of energy consumption. Offshore production is estimated to account for
31% of gas production in 1985 under an accelerated development assump-
tion, as compared with 13% in 1972.
The essential conclusion from an examination of the supply and
demand forecasts for oil and gas out to 1985 is that even relatively
large increases in the cost of producing domestic crude and gas will not
result in a reduction of demand below the capacity of U.S. production at
$7 or $11 per barrel price levels.
To illustrate the role of imports in the relationship between U.S.
oil supply and demand, Figure II-1A was constructed from the crude oil
supply and demand estimates in the Project Independence Report. An
imports supply curve has been drawn showing that at $11 per barrel, at
least 5 MM bbl/day can be purchased but none can be purchased for less
than $11 per barrel. With a supply/demand relationship as shown in
Figure II-l , a shift in the U.S. supply curve as a result of an industry-
wide change in production economics, such as resulting from new pollution
control costs, will not change the intersection of the total U.S. supply
curve and the U.S. demand curve. The total quantity of oil consumed will
remain essentially unchanged, as would the price. The difference between
total demand and available U.S. supply would be made up by imports. Thus,
the demand for U.S. production at the equilibrium price of $11 per barrel
would remain both unchanged and greater than U.S. production capacity at
$11 per barrel.
11-18
-------
15 -
14
13
12
11
10
9
OJ*
£ 8
I!
o
a
a
CO
O
.C
CO
Total U.S. Petroleum
Demand Curve
U.S. Offshore Plus Onshore
Supply Curve,
Total U.S. Crude Oil
Supply Curve
6789
Demand/Production
(MM bbls/day)
10
11
12 13
14
15
FIGURE 11-1 1977 U.S. PETROLEUM SUPPLY AND DEMAND FUNCTIONS
(Accelerated Development Scenario)
SOURCE: Drawn from projected supply and demand values in Oil: Possible Levels
of Future Production, Project Independence Blueprint, FEA, Nov. 1974
11-19
-------
Figure II-l also shows the domestic supply curve to be almost ver-
tical above $9 per barrel. Increasing prices from $9 to $11 per barrel
will increase total U.S. production by only a small amount in 1977, accor-
ding to the Blueprint estimate shown in the figure. While a shift in the
U.S. supply curve as mentioned above will result in lower U.S. oil pro-
duction (to be made up by imports), the nearly vertical U.S. supply curve
suggests that the production losses will be small for production cost
increases as large as $2 per barrel.
11-20
-------
II.2. CHARACTERIZATION OF OFFSHORE OIL AND GAS PRODUCING COMPANIES
Until the early 1970's, the vast majority of U.S. offshore oil and
gas production came from wells owned and operated by the large integrated
oil companies. The large "up front" costs of lease bonus payments and
the massive investments required for exploration, development, production,
and processing facilities tended to discourage all but the largest firms
from undertaking offshore projects. Table II-9 shows the participation
of the major oil companies in offshore production in 1971; in that year,
the major integrated companies operating independently or in groups
accounted for 97% of DCS oil production. Recent efforts have been made
by the Interior Department to allow more participation by smaller com-
panies. Since 1971, there has been an increased participation by the
independents in acquiring offshore acreage. For the three lease sales
of September and December 1972 and June 1973, single majors acquired 21%
of the acreage, groups of majors acquired 14%, single independents
acquired 17%, and groups of independents and majors acquired 47% of the
acreage.
The companies attempting to acquire offshore acreage for oil and gas
development bid either independently or in groups for the right to develop
and produce the fields. If a consortium of companies wins the bidding,
one of the firms will be responsible for drilling and operating the wells.
Table 11-10 lists, as an example, the ownership relationship of the firms
operating in Federal waters off Louisiana in 1973. Table 11-11 lists
major oil companies and their partners owning leases in Louisiana state
waters the same year.
11-21
-------
TABLE II-9
PCS LEASE ACREAGE AND PRODUCTION, THROUGH SEPT. 1971
Lessee Acreage (%) Production (%)
Individual Majors 46 63
Groups of Majors 35 34
Groups of Independents 17 2
Individual Independents 2 1
SOURCE: U.S. Department of the Interior, reported in Outer Continental
Shelf Policy Issues, p. 61, Committee on Interior and Insular
Affairs, U.S. Senate, 1972
11-22
-------
TABLE II-1Q
—LOUISIANA UNO & EXPLORATION CO., DOCKET NO CI73-501, JOINT OWNERSHIP OF FEDERAL
OFFSHORE PRODUCING LEASES
Number
Company
Thi majors:
Amerada-Hess
Atlantic-Rich field
Cities Service
Continental
Getty
Gulf
Marathon
Mobil
Ptiilhps
Shell
Chevron
Amoco
Exxon
Sun
Texaco
Union Oil
Number of Independently of joint
leases owned Major partners ventures >
15 0 Marathon
Signal
Louisiana Land
94 3 Cities
Getty
Continental
Tenneco '
Standard Oil of California
(Chevron)
El Paso»
101 1 Atlantic
Getty
Continental
Mobil
Tenneco'
Standard Oil of California
(Chevron).
119 1 Atlantic
Cities
Getty
Mobil
Tenneco'
Standard Oil of California
(Chevron).
Superior
Transocean
Southern Natural'
100 2 Atlantic
Cities
Continental
Mobil
Tenneco'
Standard Oil of California
(Chevron).
Phillips
Superior
Transocean
Southern Natural'
Allied Chemical
51 34 Mobil
Standard Oil of New Jersey
(Exxon).
Phillips...
Kerr-McGee
18 0 Amerada
Signal
Louisiana Land
Union
Sun
52 6 Continental
Cities
Getty
Gulf
Standard Oil of California
(Chevron).
Standard Oil of New Jersey
(Exxon).
Standard Oil of Indiana (Amoco).
Pennzoil'
16 3 Kerr-McGee
Gulf
Getty
Standard Oil of Indiana (Amoco).
Sun
Southern Natural'
Allied Chemical
68 64 Standard Oil of California
(Chevron).
105 86 Mobil
Getty
Atlantic
Cities..
Continental
60 3 Texaco
Union
Southern Natural'
Mobil
Kerr-McGee
Superior
Tenneco'
Phillips
Pennzoil'
Texas Eastern '
52 43 Gulf
' " Mobil
19 0 Burmah
Murphy
Kerr-McGee
Union... -
Phillips
Marathon
Cabot.
Diamond Shamrock
AnadarKo'
55 16 Standard Oil of Indiana (Amoco)
Tenneco'
37 18 Standard Oil of Indiana (Amoco).
Marathon
Superior —
Sun
Texas Eastern'
M
14
14
85
83
87
4
2
2
85
93
91
2
?
2
87
91
87
19
8
2
2
2
2
83
93
87
8
4
3
3
2
2
2
3
7
6
4
2
13
13
13
5
3
19
8
8
7
5
4
4
2
7
4
3
3
3
2
3
2
5
j
2
2
2
29
12
8
4
4
4
3
3
4
2
6
4
11
10
4
3
3
3
3
3
3
2»
9
12
4
3
2
11-23
-------
TABLE II-1Q (Con't)
-LOUISIANA LAND & EXPLORATION CO, DOCKET NO CI73-501, JOINT OWNERSHIP OF FEDERAL.
OFFSHORE PRODUCING LEASES—Continued
Number of Independently
Company
Selected medium sized firms.
Tenneco 0[\''
Kerr-McGee
Caoot Corp - - - - - - -
PennzoiU
Consolidated- ..
Columbia Gas * -
Texas Gas1
Forest Oil
Murphy-Ocean
Burmah
Signal
Louisiana Land & Exploration.
Superior
Transocean _
Hunt
Ashland
Southern Natural >
Allied Chemical
Anadarko' :
Diamond Shamrock.
Texas Eastern! _
El Paso'
Placid
leases
51
29
12
9
33
33
28
34
32
23
15
14
21
14
17
7
15
3
3
4
2
2
15
owned
24
0
0
1
0
0
0
0
1
0
1
0
10
0
3
0
0
0
0
0
0
0
0
Major partners
Texaco,
Continental
Cities
Consolidated >
Columbia Gas ! .
Forest
Phillips
Cabot -
Soutnerr Na: : . .
Sun ..- . . - . .
Kerr-McGee
S'andard 0.1 ot Indiana
Columbia Gas - .
Texas Gas Transmission-...
Forest ......
Tenneco ;.
Conso'idated :
Texas Gas •
Forest. - .-
Tenneco * .
Consolidated '
Columbia Gas -
Forest
Tenneco'
Consolidated '
Columbia Gas '
Texas Gas'
Tenneco1
Sun
Burmah
Sun
Murphy- Ocean
Amerada
Marathon
Louisiana Land -
Amerada
Marathon
Signal
Standard Oil ot 1 ndiana (Amoco).
Union
Transocean
Superior
Hunt
Placid...
Ashland
Transocean
Placid
Ashland
Transocean
Hunt
Placid
S'andard Oil of Indiana (Amoco).
Kerr-McGee
Getty
Phillips.
Sun
Diamond Shamrock
Sun
Anadarko :
Standard Oil of 1 ndiara (Amoco).
Union
Atlantic
Transocean
Hunt
Ashland
Number
of joint
venturts i
—
9
t
7
e
6
(
6
12
1
3
12
4
26
25
26
6
26
27
33
6
25
26
23
6
2«
37
26
1
10
21
11
21
14
13
14
14
13
14
4
4
7
7
7
7
7
7
9
7
7
7
7
I
1
3
3
3
3
3
3
2
2
2
7
9
7
' Mav add to more than total number of leases v*hen 3 or more firms participate in mdtvidua1 joint ventures.
: This company or an affiliate is a major interstate gas pipeline
SOU1CE: U.S. Dept. of the Interior, cited in Market Performance
and CoiiVpeuition in the Petroleum Industry, p. iito,
Committee on Interior and Insular Affairs, U.S. Senate, 1974
11-24
-------
TABLE 11-11
..—LOUISIANA LAND & EXPLORATION CO., DOCKET NO. CI73-501
JOINT OWNERSHIP OF STATE OF LOUISIANA PETROLEUM LEASES BY LARGE MAJOR PRODUCERS
Company, major partners, and jointly held
leases.
Amerada-Hess.
Phillips
Amoco
Sohio
Atlantic-Richfield
Cities
Continental
Getty
Marathon
Texaco
Tenneco
Amoco
Chevron
Sohio
Cities Service
Atlantic
Getty
Continental.
Atlantic
Cities
Getty
Mobil
Sun
Tenneco
Gulf
Getty.
Gulf
Atlantic
Cities
Continental
Exxon
Tenneco
Mobil
Shell
Texaco
Gulf
Getty
Sohio
Shell
Chevron
Sun
Phillips
Marathon.
Atlantic
Mobil
Continental
Gulf
Sun
Getty
Phillips:
Sun
Amoco
Gulf
Shell.
Gulf
U.S. Dept. of the
and Competition in
State
Number
36
10
2
27
28
26
10
7
4
4
3
. ... 2
2
27
27
31
2
28
27
27
. .. 16
13
11
11
3
3
51
26
31
27
27
4
- -. 4
4
3
3
2
2
62
51
13
12
7
6
6
5
5
3
3
2
2
7
3
16
8
5
4
4
3
3
2
36
7
3
2
12
8
Company, major partners, and jointly
leases-
Texaco
Getty
Chevron
Shell ... ..
Gulf
Atlantic
Amoco
Texaco . . ..
Continental
Mobil
Gulf
Shell
Sun
Exxon
Getty
Atlantic
Phillips
Union
Exxon
Gulf
Getty
Continental
Shell
Amoco
Chevron
Mobil
Cities
Sohio:
Gulf
Getty
Atlantic
Sun-
Continent 1
Phillips
Mobil
Getty
Gulf
Union -.
Tenneco.
Gulf
Atlantic
Getty
Mobil
Sun
Texaco
Gulf
Shell
Mobil
Atlantic
Chevron . - -
Getty
Union Oil.
Atlantic
Amoco
Sun .
Exxon
Texaco
Interior, cited in Market
the Petroleum Industry,
held State
Number
5
5
5
2
8
6
3
3
.. . 3
11
11
10
8
7
5
5
. . 5
4
4
3
3
3
62
27
13
11
5
5
4
3
2
2
2
13
4
2
2
. . . 11
7
5
4
3
3
3
3
5
5
5
4
4
3
. . .. 3
3
3
11
11
6
5
4
4
3
2
2
10
3
3
2
2
Performance
p. 1167, Comm
SOURCE:
on Interior and Insular Affairs, U.S. Senate, 1974
H-25
-------
Besides the major integrated oil companies, the largest group of
offshore participants are the interstate gas pipeline companies.
Tables 11-12, 11-13, and 11-14 list the major pipeline operators and
show their 1972 participation in the lease bidding. In the December 19,
1972, bidding on Federal OCS acreage off Louisiana, pipeline companies
participated in 51.7% of the successful bids and paid 19.5% of the bonuses.
On February 21, 1975, the Interior Department published a proposed
regulation in the Federal Register that no companies producing more than
1.6 million barrels a day of crude oil, natural gas (equivalent), and
natural gas liquids could jointly bid with other such companies on OCS
leases. The intent of the regulation is to further reduce the dominance
of the major oil companies in offshore production.
11-26
-------
TABLE II-12
-LOUISIANA LAND AND EXPLORATION CO., DOCKET NO. C173-501—MAJOR INTERSTATE GAS F.PELINES
AND THEIR PRODUCING AFFILIATES
Interstate pipeline companies Exploration, development, and producing affiliates
Arkansas Louisiana Gas Co Arkla Exploration Co.
Cities Service Gas Co ,... Cities Service Oil Co., Cities Service Gas Resources Co , Hydrocarbon Products-
CD., Inc
Colorado Interstate Gu Co Coastal States Gas Producing Co , LO-VACA Gathering Co , Colorado Oil and Gu
Corp., Nueces Industrial Gas Co.
Columbia Gas Transmission Corp Columbia Gas Development Corp
Consolidated Gas Supply Corp CNG Producing Co.
Ei Paso Natural Gas Co Odessa Natural Gasoline Co , Odessa Natural Corp, Trebol Drilling Co , PecosCo.
Florida Gas Transmission Co Florida Gas Exploration Co.
Lone Star Gas Co Lone Star Producing Co
Michigan Wisconsin Gas Co _ American Natural Gas Production Co.
Natural Gas Pipeline Co. ol America... Harper Oil Co.
Northern Natural Gas Co (Produces under its own name )
Panhandle Eastern Pipeline Co Anadarko Production Co., Pan Eastern Exploration Co . Panhandle Westerr Gas
Co.
Southern Natural Gas Co SONAT Exploration Co., The Offshore Co
Tennessee Gas Transmission Co Tenneco Oil Co.
Tennessee Gas Pipeline Co.. Tenneco Exploration, Ltd., Tenneco Offshore Co, Inc, Tenneco West, Inc.
Texas Eastern Transmission Corp La Gloria Oil and Gas Co , Texas Eastern Gas Supply Co , Texas Eastern Ma roc.
Inc., Texas Eastern Exploration Co , Texas Eastern Oil Co.
Texas Gas Transmission Corp Texas Gas Exploration Corp.
Transcontinental das Pipeline Corp Transcontinental Production Co., Trans-Gulf Transmission Corp.
Transwestern Pipeline Co ' Transwestern, Inc., Transwestern Gas Supply Co
Trunkhne Gas Co.J
United Gas Pipeline Co Pennzoil Producing Co., Pennzoil Petroleums, Ltd , Pennzoil Louisiana & Texts
Offshore, Inc., Pennzoil Offshore Gas Operator, Inc.
1 Subsidiary of Texas Eastern Transmission Corp.
1 Subsidiary of Panhandle Eastern Pipeline Co.
SOURCE: U.S. Dept. of the Interior, cited in Market Performance
and Competition in the Petroleum Industry, p. 1170,
Committee on Interior and Insular Affairs, U.S. Senate
1974
11-27
-------
TABLE 11-13
-PARTICIPATION BY INTERSTATE PIPELINE COMPANY AFFILIATES IN OFFSHORE LOUISIANA FEDERAL
OIL AND GAS LEASE SALE, SEPT 12, 1972
Successful
bids (number
Interstate pipeline affiliation/bidding group of leases)
Texas Eastern Transmission Corp . Texas Eastern Exploration
Co ' Amoco Production Co , Union Oil Co of California
Cities Service Gas Co.' Cities Service Oil Co ,< Tenneco Oil Co ,'
Continental Oil Co , Getty Oil Co
Tennessee Gas Pipeline Co Tenneco Oil Co ,' Cities Service Oil
Co ,' Texaco, Inc , Continental Oil Co
United Gas Pipe Line Co . Pennzoil Offshore Gas Operators,1 Penn-
zoil L i T. Offshore. Inc ,1 Gulf Oil Corp Mobil Oil Corp
United Gas Pipe Line Co Pennzoil Offshore Gas Operators,1 Penn-
zoil L & T. Offshore. Inc ,' Mesa Petroleum Co , Burmah Oil
Dev Inc Canadian Occidental Ca Inc
Florida Gas Transmission Co Florida Gas Explor Co ,' Shell Oil
Co., Sabine Explor Corp , Drillamex. Inc , Kirby Petroleum Co.,
Royal Gorge Co American Independent Oil Co
Consolidated Gas Supply Corp.. Consolidated Gas Supply Corp ,'
Aztec Oil and Gas Co ---
Total pipeline affiliates' successful bids
21
2
4
4
1
1
1
33
53.2
Pi pel lot
Bonuses paid affiliates'
by pipeline percent rt
affiliate bonuses paid
(dollars) (range)
19,523.520
1,993,685
6,568,143
30,039,200
4,532,792
747.600
191,925
63, 5%, 865
10.8
24-36
33-34
33-50
7-U
IS
12
„•*
_
i Corporate affiliate of interstate pipeline company.
Source. Bid recap sheets. Bureau of Land Management, Department of the Interior, oil and gas lease sale, ofirtort
Louisiana, Sept. 12, 1972.
cited in Market Performance and Competition in the
Petroleum Industry, p. 1170, Committee on Interior
and Insular Affairs, U.S. Senate, 1974
11-28
-------
TABLE 11-14
-PARTICIPATION BY INTERSTATE PIPELINE COMPANY AFFILIATES IN OFFSHORE LOUISIANA
FEDERAL OIL AND GAS LEASE SALE, DEC. 19, 1972
Interstate pipeline affiliation/bidding group
Bonuses paid
Successful by pipeline
bids (number affiliate
of leases) (dollars)
Pipeline
affiliates'
percent of
bonuses paid
(range)
Columbia Gas Transmission Co
Columbia Gas Development Corp.'
Forest Oil Corp.
Energy Ventures, Inc.
Consolidated Gas Supply Corp _
CNG Producing Co.1
Amoco Production Co.
The NW Mutual Life Ins. Co.
Cities Service Gas Co
Cities Service Oil Co.1
Getty Oil Co.
Continental Oil Co.
Atlantic Richfield Co.
Southern Natural Gas Co
Sonat— Exploration Co.1
The Offshore Co.
Midwest Oil Co.
Newmont Oil Co.
Southland Royalty Co.
Samedan Offshore Co.
Champlin Petroleum Co.
Trans Continental Gas Pipe Line Corp
Trans-Continental Prod. Co.]
Shell Oil Co.
Texas Eastern Transmission Corp
Texas Eastern Exploration Co.1
Louisiana Land and Explor. Co.
Signal Oil & Gas Co.
Marathon Oil Co.
United Gas Pipe Line Co
PennzoM Offshore Gas Operators >
Pennzoi! L. I T. Offshore, Inc.1
Mobil Oil Corp.
Chevron Oil Co.
Texas Production Co.
United Gas Pipe Line Co
Pennzoil Offshore Gas Operators >
Pennzoil L. & T. Offshore, Inc.'
Mesa Petroleum Co.
Burmah Oil Dev., Inc.
Texas Production Co.
Tennessee Gas Pipeline Co
Tenntco Exploration, Inc.1
Texaco, I nc.
Total—pipeline affiliates' successful bids.
Percent of total successful bids
16
80,015,311
24,321,180
47, 453, 678
1 7, 038, 899
13 53, 418, 570
6 20,582,750
3 15, 501, 506
1 20,903,880
6 55,147, 808
60 324,383, 582
51.7
19.5
40
25-34
25-50
28
19-25
14-33
7-27
7-27
50
1 Corporate affiliate of interstate pipeline company.
Source' Bid recap sheets. Bureau of Land Management, Department of the Interior, Oil and Gas Lease Sale—Offshore
Louisiana—December 19, 1972
cited in Market Performance and Competition in the
Petroleum Industry, p. 1171, Committee on Interior
and Insular Affairs, U.S. Senate, 1974
H-29
-------
II.3. OIL AND GAS PRICING
3.1. Crude Oil Pricing
The Role of Crude Prices in the Economic Impact Analysis
The price of crude oil and the factors and processes which determine
its price have undergone dramatic changes in the last few years. While
oil from different fields has distinct physical and chemical properties,
it can be characterized by and large as a world commodity product. As
such, its price should be subject to the movements of world supply and
demand. However, the political implications of crude prices and crude
sources have strongly distorted prices even before the recent embargo.
The price which operators of domestic oil wells can receive for their
crude is a critical element in determining the impact of the proposed
effluent limitation guidelines. At sufficiently high prices, there would
simply be no potential for the pollution control costs making an exist-
ing well unprofitable. Yet the uncertainty about U.S. crude prices over
the period when the guidelines will become effective, 1977-1983, is an
unresolvable unknown.
At present (January 1975), prices for U.S. "old" crude are frozen at
$5.25 per barrel while "new", released, and stripper well crude prices
are uncontrolled. However, there is a major public policy debate in pro-
gress concerning the pricing of domestic crude. The argument is being
made that all price controls should be removed in order to accelerate the
development of domestic oil resources. Since new oil is already deregulated,
the removal of controls from old oil would have the effect of providing
additional capital to the oil companies to undertake new exploration and
II-30
-------
production. The argument on the other side is that there are already
ample incentives for new exploration and development, that oil companies
could not effectively spend the added funds, and that the only effect of
deregulation would be to raise the price of petroleum products to consumers.
This debate is further complicated by serious proposals to impose excess
profits taxes, and break off the marketing segments of the producing com-
panies .
Most offshore and onshore production to which the effluent guidelines
would apply are now price controlled. Deregulation would increase these
prices to the level of imported crude. This impact analysis cannot even
speculate whether deregulation will occur. The limit of the analysis is
a statement about the impact of the proposed standards on production if
they occur after crude oil prices have been deregulated. Recent tax
legislation has effectively ended the depletion allowance for large pro-
ducers. This change in tax policy has been included in the impact analysis,
but other possible changes in tax policies or industry structure are beyond
the scope of this analysis, though they could have an important influence on
the industry.
Current Crude Oil Pricing Patterns
Domestic crude oil prices have fluctuated very little for 18 of the past
20 years. The years 1973 and 1974 broke this pattern. In 1955, a barrel of
crude oil sold for $2.77. By 1971, the price for the same barrel had risen
to $3.10. However, in 1973 most domestic crude prices had risen to $5.25 per
barrel and would probably have been higher except for a formula worked out by
the Federal Energy Agency (FEA) which imposed regulations on crude prices.
Table 11-15 lists crude prices for various sources for the last five years.
II-31
-------
TABLE 11-15
HISTORICAL POSTED CRUDE OIL PRICES
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 Texas sour
*Year's highest price given
1970
1 80
1-79
1.59
1.88
1.72
1.93
2.41
2.53
2.42
1.70
2.193
2.339
3.69
3 60
3.23
1971
2.285
2.274
2.187
2.341
2.259
2.387
3.211
3.447
3.212
2.21
2.722
2.782
3.69
3.60
3.29
1972
2.479
2.467
2.373
2.540
2.451
2.590
3.402
3.673
3.446
2.260
2.722
2.782
3.69
3.60
3.29
1973
5.036
5.254
4.82
5.944
4.978
5.737
7.10
9.061
8.339
6.00
7.762
8.004
5.29
5.20
5.29
1974*
11.651
11.875
11.545
12.636
11.672
12.414
15.768
14.691
10.80
14.356
14.876
5.29
5.20
5.29
, 1974 price effective Jan. 1.
-"''Official selling price for Sumatra, reference
all others are posted prices. Kirkuk priced
prices are representative postings for crude
SOURCE: Oil and Gas Journal
price for Venezuela ,
at Mediterranean; U.S.
oil.
11-32
-------
FEA price regulations are directed at each of the four levels of the
domestic petroleum marketing chain. As a result of current FEA regulations,
there exists a two-tiered wellhead pricing system for domestic crude.
"Old" oil is price controlled at $5.25 per barrel; however, the price of
new, released and stripper well crude is free to rise and fall with market
fluctuations.
Domestically produced oil which is not price controlled is the amount
of oil produced per well per producing property in excess of the crude pro-
duced in the corresponding month of 1972 (the excess is termed "new" oil),
an amount of oil equal to "new" oil (this equivalent amount is termed
"released" oil), and all oil produced from any lease whose average daily
production for the preceding calendar year didn't exceed 10 barrels per well.
For an example of new and released oil, assume that in March of 1972 a
property with 12 wells was producing 240 barrels of oil per day, or a daily
average of 20 barrels per well. If in March of 1974 the same property produced
a daily average of 264 barrels from the same 12 wells, or 22 barrels per
well, each well would be producing 2 barrels of new crude, 2 barrels of re-
leased crude and 18 barrels of old crude. If, because of some occurrence such
as water flooding on-nearby properties, the daily production per well on the
example property rose to 45 barrels per day in March of 1974, each well would
be producing 25 barrels of new crude and 20 barrels of released crude per day
and no old crude.
11-33
-------
By the end of 1974 the composition of total domestic crude was ap-
proximately 60% old and 40% new, released and stripper well crude. Actual
prices for domestic crude oil under the FEA categories are now $5.25 per
barrel for "old" oil and are over $11.00 per barrel for "new" oil. The
weighted average of old and new prices is about $7.50. If price controls
remain in effect, the average will rise as unregulated oil becomes a larger
proportion of total production.
Current U.S. concern with foreign, particularly Middle Eastern, oil
prices is that the prices are very high. Until 1973, the reverse was true.
As the cost of exploration, development, and production rose in the U.S.,
American oil companies developed fields abroad where the production costs
were much lower than in the U.S.
By the latter half of the 1960's, the Middle Eastern countries had
become more sophisticated in dealings with the large companies. An organi-
zation called the Organization of Petroleum Exporting Countries (OPEC) was
formed to specifically negotiate better deals for the member countries. A
double price system was effectively set up when the members of OPEC announced
they were going to guarantee their income by posting a price per barrel
that would be used to figure their royalty no matter what the real price
of crude oil was. That announcement was the beginning of political pricing.
The posted price became effective in the latter half of the 1960's with each
country posting separate prices. The other price of the double price system,
the real price, has historically been below posted price. Table 11-16 lists
representative posted and actual prices.
11-34
-------
TABLE 11-16
REPRESENTATIVE POSTED PRICES AND ACTUAL COSTS
'PER BARREL OF FOREIGN EQUITY CRUDES AND U.S. CRUPE
Algeria
Canada
Iran
Iraq
Kuwait
Libya
Nigeria
Qatar
Saudi Arabia
U.A. Emirates
Venezuela
U.S. Old Oil
U.S. New Oil
U.S. Composite**
Imported Composite
Total Composite
'Includes transportation
Posted Price
$16.21
6.68
11.87
11.67
11.54
15.76
14.69
12.01
11.65
12.63
14.87
- ...
- _ .
- _ -
_ _ .
- - .
**Domestic o
Aclnal Cost*
SOURCE: Platts Price News, June 26, 1974
11.08
9.35
9.23
9.12
10.95
10.26
9.70
9.20
9.82
10.95
5.25
10.20
7.15
10.42
8.01
11-35
-------
The movement upwards of the posted price of crude oil forced the
real price of crude oil up in order to pay the royalty and still produce
a profit. In the world market, oil is traded almost as a commodity, and
the price moves up and down according to demand. The effect of the rise
in price of foreign crude oil on the price of domestic crude oil has been
considerable. Early in the 1950's, the United States Government set up
an allowable policy on crude oil imports. The purpose was partly to protect
the domestic industry from competition from cheap foreign imports (parti-
cularly independents and non-foreign oil-producing companies, as this seg-
ment of the industry was in an over-production situation), partly to pre-
vent long-range dependence on foreign oil, and partly to use as a lever
against the oil industry to prevent price increases. The whole allowable
system was predicated upon foreign oil being cheaper than domestic oil.
The situation has now reversed itself. Foreign oil is now more ex-
pensive than domestic oil. However, even though the production costs of
most domestic oil is far below the price of imported oil, production cannot
meet demand.
The cost of crude includes a wellhead price plus tarrifs, plus cost
of delivery to a refinery. Tables 11-17 and 11-18 list crude price and trans-
portation costs to U.S. refining areas from several producing areas. Table
11-17 lists the costs for the average mix of new and old U.S. oil and typical
foreign oil. The U.S. oil has a strong competitive advantage in both the crude
price and the transportation costs. This advantage has actually grown in
recent months as foreign prices have increased faster than the average U.S.
price because of price controls. Table 11-18 compares U.S. new oil with
11-36
-------
TABLE 11-17
DELIVERED PRICES OF FOREIGN AND
AVERAGED. . MIX DOMESTIC CRUDE
West Texas
Sour 32'
*$7.38
$7.38
0.95
$8.33
0.25
$7.63
0.41
$7.79
U.S.
J Sour Ventura
0.20
}$7.33
Arabian TiaJuana
Light 34' Light 31°
$10.46 $11.10
0.18 0.18
$10.64 $11.28
I'HILAUtLPHIA '
1.40 0.34
$12.04 $11.62
U.S. GULF COAST
1.39 0.32
$12.03 $11.60
CHICAGO
1.58 0.51
$12.22 $11.79
WEST COAST (LOS ANGE
28°
1.16 0.73
$11.80 $12.01
S. Louisiana
Light 37°
*$7.63
$7.63
0.85
$8.48
0.25
17.88
0.32
$7.95
Lt!>)
Canadian
Sweet 39°
t$12.15
0.18
$12.33
0.50
$12.83
Nigerian
Light 34"
$11.75
0.18
$11.93
0.72
$12.65
0.83
$12.76
1.02
$12.95
F.o.b. 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
11-37
-------
TABLE 11-18
DELIVERED PRICE OF FOREIGN AND
DECONTROLLED DOMESTIC CRUDES
F.o.b. Price
License Fee
Sub-total
Transportation
Delivered Price
Transportation
Delivered Price
Transportation
Delivered Price
Transportation
Delivered Price
*For price control
and includes $5.20
West Texas
Sour 3 2°
»$10.89
$10.89
0.95
$11.84
0.25
$11.14
0.41
$11.30
Arabian
Light 34°
$10.46
0.18
Tia Juana
Light 31°
$11.10
0.18
$10.64 $11.28
0.97 0.31
$11.61 $11.59
0.96
$11.60
.P COAST
0.29
$11.57
LHICAUU "
1.15 0.48
$11.79 $11.76
S. Louisiana
Light 37°
*$11.14
$11.14
0.85
$11.99
0.25
$11.39
0.32
$11.46
Canadian
S»-eft39°
t$12.15
0.18
$12.33
0.50
$12.83
Nigerian
Light 34'
$11.75
0.18
$11.93
064
$12.57
0.73
$12.66
0.92
$12.85
\Sour Ventura 28°
0.20 0.54 0.68
*$10.83 $11.18 $11.96
•exempt, free market crude. tAllows for currency
Canadian export tax. JFree market f.o.b. price $10.
exchange differentials
63.
Note: Transportation costs are on a spot basis.
SOURCE: Petroleum Intelligence Weekly, December 9, 1974
11-38
-------
minimum foreign oil prices. One sees in the table that the price of the
new oil has risen to just about the same price as the foreign oil when trans-
portation costs are taken into consideration.
While this impact analysis will not attempt to specify crude prices
over the period of interest, the subject has been considered by reputable
analysts. The Project Independence study considered crude prices ranging
fr.om $4 to $11 per barrel. Since Arab prices are now established
for political reasons as well as economic, their prices could be reduced
conceivably to the $4 level again,though it is unlikely. However, if crude
prices were allowed to seek a level reflecting world supply and demand,
the Blueprint Report estimated that the long-term price would be about
$7 per barrel in 1973 dollars (almost $8 per barrel in 1974 dollars).
Former Secretary of the Treasury Schultz testified in February 1974:
It is reasonable to assume that after about 3 to 5 years,
and allowing for some inflation, if the price of oil
increases by about 50% from mid-1973 levels, to around
$7 per barrel, sufficient domestic oil supplies should
flow to satisfy about 85-90% of our demands.
Accordingly, we have for planning purposes estimated that
the "long-term supply price1' is about $7 per barrel.
But the $7 per barrel figure is an estimate and the
ultimate figure may be somewhat more or somewhat less.
While the $7 per barrel may be approximately the supply/demand equilibrium
price, the prices at the two ends of the spectrum are probably more relevant
as prices which may actually be seen. As was noted above, about 60% of
current production is frozen at $5.25 per barrel. The President has
proposed to remove these price controls, subject to
Congressional approval as provided by the Emergency Petroleum Allocation
Windfall" or Excess Profits Tax, Committee on Ways and Means,
U.S. House of Representatives, pp. 135, 1974.
11-39
-------
Act. On the other hand,there is a strong move in Congress to reimpose price
controls more generally on the economy rather than relaxing them.
If old crude prices are decontrolled, the resultant change in per barrel
revenues to the oil companies may not be equal to the increase in crude
prices. The combination of excise taxes on imports and the excess profits tax
as proposed by the President could result in an added net income of only $0.89
per barrel in pre-tax (corporate tax) revenues to the companies , based on
an analysis of the total tax and deregulation package which was reported in Platt
News of Jan. 20, 1975. This analysis showed that the weighted average U.S.
domestic price less severance tax was $6.97 based on price-less-tax levels of
$10.23 for new oil and $4.88 for old oil (39% to 61% ratio). If deregulated, U.S.
crude prices will rise to $14 per barrel, slightly less than the landed price of
foreign crude (including the proposed $3 excise tax). The taxes on the
domestic crude would include: $2 excise tax; 7% severance tax on the
$12; and $3.30 windfall profits tax. The net revenue to the firm would then
be $7.86 per barrel, an increase of $0.89 over present revenues. There is
of course no way to know at this point whether all, part, or none of the package
will be enacted.
The following analysis of potential oil production losses as a result
of the proposed effluent guidelines has used $5.25 and $11.00 crude prices
to test the range of potential impacts. They are intended to be represen-
tative of the price range producers could have experienced at the end of 1974.
H-40
-------
3.2. Pricing of Offshore Natural Gas at the Wellhead
Introduction
The price of natural gas is set at the time of production according
to its entry into either the intra- or interstate markets. Intrastate
prices are not regulated and respond freely to the fluctuation of supply
and demand. Interstate prices are controlled by the Federal Power Com-
mission which has jurisdiction over gas produced in federal offshore
areas, gas produced and sold across state lines and gas moving through
any segment of an interstate pipeline system.
Prior to 1973, the new, long-term contract prices received by
natural gas producers for intra- and interstate sales were not signifi-
cantly different. However, in late 1973, prices for intrastate gas began
to rise to levels occasionally tripling the fixed prices of interstate
gas, and in 1974 intrastate prices were in the range of $1.95 per thousand
cubic feet (MCF), roughly four times greater than the interstate price
of $0.51 per MCF (see Table 11-19). A consequence of the price disparity
has been the extreme shift to intrastate markets of the commitments of
natural gas reserve additions as early as 1969.
If it is assumed that all of the new reserves reported by AGA not
committed to the interstate pipelines are being committed to the intra-
state gas market, it appears that the intrastate market may well have
captured 99% of the 1970 net U.S. reserve additions, 30% of the 1971 net
reserve additions, 100% of the 1972 net additions, and 82% of the 1973
net reserve additions (see Table 11-20).
11-41
-------
TABLE 11-19
Prices Received by Producers Cm
Natural Gas Sales. 1966-1975
(cents per thousand cubic feet)
V w
New (ni'.f
Average Long-Term Cn-.ii
\\ellhead tntevstatc lntt..-.tate
Prices Contracts Con"jcis
15.7 17.7 15 t-ii! 5
16.0 1R.8 15.(-)-)6
16.4 19.6 16.1 20 2
16.7 19.9 1-M 21 5
17.1 22.3 1R5-230
18.2 24.8 20.t-2o2
18.6 35.! 23.5-^11.0
21.6 40.3 25 -1 25
26.7 43-51 125-195
35.0 17; 110
S.MII.V i i o-ter Associates: I'.S. Bureau of Mines. \,ii',ral
(,a< -\nnual. l')73: l-'ederal Power Commi^i'in;
I.Mison Assxiciates: and Arthur D. Little, In...
11-42
-------
TABLE 11-20
LOWER 48 STATE
NET RESERVE ADDITIONS
INTERSTATE VS . INTRASTATE
Year
Total Net AC/A.
Reserve Additions
Tcf
Net Interstate
Reserve Additions
(Form 15)
Tcf Percent
1964
1965
1966
1967
1968
1969
1970
1971
1972
1S73
20.1
21.2
19.2
21.1
12.0
8.3
11.1
9.4
9.4
6.5
10.7
13.3
14.1
14.8
9.5
6.0
0.1
1.9
(0.2)
1.2
53
63
73
70
79
72
1
20
0
18
Inferred Intrastate
Reserve Additions
Tcf Percent
1
9.4
7.9
5.1
6.3
2.5
2.3
11.0
7.5
9.6
5.3
47
37
27
30
21
28
99
80
100
82
Derived by as:.u:ning that intrastate reserve additions are equal to the
difference between total AGA reserve additions and the reserve additions
committed to the interstate market.
SOURCE: "The Oil and Gas Compact Bulletin", December 1974
11-43
-------
Prior to 1970, there were sufficient domestic supplies of gas; how-
ever, beginning in 1970, onshore gas procurement became difficult for the
interstate market. In 1970, the interstate pipelines procured 75% of
their long-term new gas from onshore sources; in 1971, the percentage
dropped to 54%; in 1972, it dropped to 41%; and in 1973, it dropped to
33% (Table 11-21 ) .
The increased dependence of interstate pipelines on offshore pur-
chases, or the inability of the interstate pipelines to buy gas onshore,
appears to be attributable to the FPC rate structure which makes it dif-
ficult for the interstate pipelines to compete for new supplies.
Because offshore areas are the most expensive to develop, offshore
gas exploratory footage has declined since 1970 (see Table 11-22). Since
1970 the percentage of footage of offshore development drilling relative
to total U.S. gas development footage has also declined (see Table 11-23).
While all natural gas produced in Federal waters is by definition
interstate gas, the gas produced in state waters can be either inter- or
intrastate depending on its transmission pipeline and the location of its
purchaser. Gas from Federal waters is 85% of the total natural gas pro-
duced in the Gulf of Mexico. Fourteen percent of the Gulf production is
from Louisiana state waters and the majority of this production also is
from older wells under interstate contracts. The Texas state waters pro-
duction is primarily dedicated to plants in Texas and is intrastate gas,
but it is only 0.3% of total offshore natural gas production.
Because natural gas from the Gulf of Mexico is primarily interstate
gas, the economic impact analysis has focused on interstate gas prices
as controlled by the FPC.
11-44
-------
TABLE 11-21
ESTIMATED NEW LONG-TERM CON TRACT
SALES ]>Y LARGE PRODUCERS 1970-1973
OFFSHORE FEDERAL DOMAIN vs. ALL AREAS
(Million Mcf)*
Year
1970
1971
1972
1973
All Area1
Sales
302.6
453.7
47-1.3
330.3
Sales
Offshore2
73.3
207.7
279.4
221.1
Offshore
Percent ^
24.2
45.8
58.9
66.9
Sales Onshore
Onshrce Percent
229.3 75.8
246.0 54.2
194.9 41.1
109.2 33.1
* Figures derived from applications filed with the Commission for new long-term
sales certificates .
FPC pricing areas and California (Federal domain)
Federal domain r.rc.is offshore Louisiana, Texas and California.
SOURCE: "The Oil and Gas Compact Bulletin", December 1974
11-45
-------
TABLE 11-22
1970
1971
1972
1973
1974 (1st half)
Total U. S. Gas
Exploratory Footage
(million feet)
3.7
3.3
4.6
6.2
3.8
Offshore Gas
Exploratory Footage
(million feet)
.26
.41
.14
.17
.08
Offshore
as Percentage
of total
7.0
12.4
3.0
2.7
2.1
* All figures taken from the latest publication of "Gas Supply Indicators
Office of Economics, issued October 25, 1974.
by the FPC
Gas development footage shows the same pattern. In 1971, offshore development footage was
8.8 percent of the national total. This dropped to 7.8 percent
-------
Regulation of Natural Gas Producers
In 1954 the U.S. Supreme Court held in Phillips Petroleum Co. versus
Wisconsin that the Federal Power Commission was responsible not only for the
regulation of the interstate pipeline companies but also for the regulation
of sales to those pipeline companies by natural gas producers in the field.
There had been up to this point a major controversy concerning the language
and intent of the Natural Gas Act of 1938 with respect to sales by producers.
When this Supreme Court decision was followed by an unsuccessful attempt to
exempt producers from regulation through Congressional legislation,
the Federal Power Commission began to grapple with the problem of how to
actually carry out its charge.
The first efforts involved attempts to determine for each producer his
costs of production, capital, etc. in order to apply the rather traditional
formula of rate of return regulation. In this framework, the producer would
be allowed to charge a price for his gas which would cover his costs of pro-
duction (including depreciation) and grant a return on his capital which would
be sufficient for him to cover his "cost of capital."
This summary is based on the history of FPC natural gas producer regulations
as detailed in Breyer and MacAvoy, Energy Regulation by the Federal Power
Commission, The Brookings Institution, Washington, D.C., 1974.
11-47
-------
There were several very difficult problems in implementing this regu-
latory scheme. For one, gas and oil are found together about 25% of the time,
but oil is not regulated. Thus, there are joint costs of exploration and pro-
duction which can by no existent economic theory be unambiguously assigned to
gas as opposed to oil. The same problem exists with allocating capital to gas
and oil. Besides this, to determine an appropriate cost of capital, one might
look at the rates of return in comparable companies in comparable industries.
Unfortunately for the FPC, such comparable companies were not to be found. The
final problem, however, was simply the enormity of the process. From 1954 to
1960 the FPC completed only ten out of nearly 3,000 cases before them. In 1960,
therefore, a new approach was decided upon — the area rate concept. The FPC
divided the Southwest into five regions and determined to set prices on a 2 tier
system — one price for gas on old contracts and a higher price for gas on new
contracts. The intent was to minimize windfall profits on already committed
gas while not unduly restricting future investment in gas exploration and
development. Because the decisions in the area rate proceedings were still
years away, the FPC decided to control prices during the interim through a two-
sided policy: (1) the producers would be compelled to refund to the pipeline
companies (and ultimately the consumers) any revenues made in excess of those
which would have been made at the price yet to be determined by the Commission;
and (2) new contracts had to be approved by the FPC. The effectiveness of
these deterrents to price increases is exemplified by the essentially constant
price of gas through the 1960's while the area rate proceedings were going on.
11-48
-------
The first area rate proceeding to be completed was the one for the Permian
Basin of West Texas and Southeast New Mexico. Prices were set at 16.5C/MCF,
only slightly higher than the 1960 rate. The initial decision of the Commission
in Southeast Louisiana was also issued in late 1968, but revisions, court cases,
and so forth dragged the "final" decision out to 1971. This decision was note-
worthy in thafc the procedures of the FPC were again dropped and in their place
the FPC substituted its acceptance of a "settlement" between the producers,
distributors, and other customers at about 2&C/MCF (new gas).
2
MacAvoy and Breyer , as well as many other economists/critics of the FPC,
have detailed the flaws in the FPC price setting schemes. For one thing, there
was an inherent bias in the cost estimates determined during the proceedings
because of the interim price ceilings. Producers would not attempt to produce
gas which would cost more than they could charge for it. The more risky ven-
tures were not attempted. Thus, the interim prices (at 1960 level) determined
producers' costs which determined final ceiling prices at little more than the
1960 level. The additional unexpected result was that the relative price of gas
to final consumers stayed so low during the '60's that a great deal of demand
was generated which would have gone to oil or coal had gas prices been allowed
to rise. At the same time, the low price discouraged investment in exploration
and development so that well drilling and subsequent discoveries fell well below
production until in the early 1970's production could not keep up with demand.
46 FPC 86 Opinion 598.
2
MacAvoy, P. and S. Breyer, ibid.
11-49
-------
The clamor over curtailments and other elements of the energy crisis brought
pressure on the FPC to review again its ceiling price decisions.
The FPC this time went one step further in simplifying its procedures:
it adopted in June 1974 a uniform national rate for wellhead prices on new
gas (produced after January 1, 1973). The new prices set were 42C/MCF (plus
taxes, royalties, etc. as applicable). In addition, in a notice of proposed
o
rulemaking , the FPC proposed that "small producers" would be allowed to
charge a price 50% higher than the larger producers, in order to allow them
to stay competitive with the larger producers.
Then in December 1974, the uniform national rate was increased to 50£/
3
MCF retroactive to June 21, 1974, subject to 1C/MCF annual increases . This
increase was primarily the result of the FPC's decision to use the discounted
cash flow (DCF) methodology for calculating producers' return on investment,
a method they had previously declined to use.
Before discussing the cost determinations which resulted in the 42C/MCF
and then the 50C/MCF price ceiling, one comment is in order. If it appears
that there is a certain amount of arbitrariness and instability in these
decisions, it is because there is. The FPC has been charged by the courts to
set "just and reasonable rates", but it has also been allowed to use whatever
1 FPC Opinion 699, 21 June 1974.
2
FPC Notice of Proposed Rulemaking, 9 September 1974.
3 FPC Opinion 699H, 4 December 1974.
11-50
-------
methods it deems reasonable to do so. No unambiguous "formula" has
been determined for this purpose. The methods chosen, then, attempt
to determine actual costs within a "zone of reasonableness" and to
base ceiling prices on this estimated range. But because both the
costs to the producers and the methodology for combining these costs
have repeatedly changed, the rate structure has undergone several
major changes in the last ten years.
Nationwide Costs of Finding and Producing Non-Associated Gas
In Table 11-24 are displayed eight different estimates used by
the FPC in June 1974 for the costs of various factors involved in the
production of natural gas. The only difference between the pairs
(c) and (d) and (e) and (f) is the assumed investment life (9 and 10.5
years respectively). Columns (g) and (h) are based on different
estimates of the expected productivity (in MCF/ft drilled) of future
drilling. As will be seen below, this is by far the most important
variable in these cost determinations.
"""FPC Opinion 699.
11-51
-------
TABLE 11-24
Docket No. R-389-B
.me
No.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
LI.
Lla.
12.
13.
14,
15.
16.
17.
Cost Component
Productivity Assumption (mcf/ft)
Successful Wells
Recorap. & Deeper Drilling
Lease Acquisitions
Other Production Facilities
Subtotal
Dry Holes
Other Exploration
Exploration Overhead
Subtotal
Operating Expense
Return @ 157. & 9 years
Return @ 157. & 10^5 years
Return on Working Capital
Net Liquid Credit
R'/Mlatory Expense
Subtotal
Royalty @ 167.
Total (? 14.73 psia
ed Nationwide Cost of Finding
oducing Non-Associated Gas
(14.73 psia)
(Cents Per Mcf)
Update
Low
559
4.93
.20
3.32
1.11
'975S
3.27
2.27
.71
5725
3.10
12.77
1.00
(3.89)
.20
2F79~?
5.52
34.51
Update
W-
485
5.68
.20
3.83
1.28
10.99
3.77
2.62
.82
772T
3.10
14.70
1.14
(3.89)
.20
33.45
6.37
39.82
Revised
Update
Low
(e)
559
4.93
.20
3.32
1.11
9T56"
3.27
2.27
.71
572T
3.10
14.90
1.00
(3.89)
.20
3T7TI
5.93
37.05
Revised
Update
Hish
(£)
485
5.68
.20
3.83
1.28
10.99
3.77
2.62
.82
772T
3.10
17.15
1.14
(3.89)
.20
35.90
6.84
42.74
10 Year
Estimate
(8)
552
4.99
.20
3.36
1.13
9TF8"
3.32
2.30
.72
F73T
3.10
15.09
1.01
(3.89)
.20
31.33
6.01
37.54
4 Year
Estimate
(HI
336
8.20
.20
5.13
1.85
15.38
5.45
3.68
1.16
10.29
3.10
24.07
1.51
(3.89)
.20
50". 66
9.65
60.31
SOURCE: FPC Opinion 699
-------
Successful Wells Cost
The successful wells cost was determined by taking the average cost of
drilling (in this case, the 1972 Joint Association Survey ; and dividing it
by the expected productivity of successful wells in MCF/ft drilled. A great
deal of controversy was involved in determining the productivity, as it is
the single most important factor in determining total costs. Figure II-2 presents
a history of the productivity from 1947 to 1972. As can be seen, there is a
tremendous variance in this curve, though since the mid-60's the trend has
been steadily downward. In the face of a great deal of conflicting evidence
presented by industry analysts, public utility associations, etc., the FPC
decided that a "zone of reasonableness" was between 485 and 559 MCF/ft drilled
for the productivity. From this and the JAS figures, a successful wells cost
between 4.93 and 5.68C/MCF was decided upon.(See columns (e) and (f) of Table
11-24.) Pew differing opinions were expressed to the FPC
concerning other costs involved in setting up production in successful wells
(items 2, 3, and 4). Line 5 is a total of these costs (1-4).
Dry Holes
An allowance was made for exploration and drilling costs associated with un-
successful wells or "dry holes". Factors which account for differences in the costs
of successful and unsuccessful wells, their relative numbers, etc. were included in
the determination of lines 6, 7, 8, and their total (line 9) in Table 11-24.
Joint Association Survey of the U.S. Oil and Gas Producing Industry; API,
IPAA, MCOGA; 1972.
II-53
-------
FIGURE II- 2
NON-ASSOCIATED GAS RESERVES ADDITIONS PER FOOT DRILLED
IN WELLS PRODUCTIVE OF GAS AND CONDENSATE
UNITED STATES EXCLUDING ALASKA, 1947 - 1972
Mcf/f'
800
700
600
500
400
300
200
47 48 50 52 54 56 58 60 62 64
66 68 70 72
SOURCE: Federal Power Commission, Opinion 699
11-54
-------
Operating Expense
Operating expense, an item not argued about by the respondents, was
determined to be 3.1C/MCF.
Return on Investment
Historically, several points of controversy have surrounded this item.
First, what is the base on which it is determined? Producers have argued that
their investment in exploration which results in dry holes should be counted
equally with their successful well costs in the determination of their rate
base. The FPC in June 1974 disagreed, citing the "value to the public of the
services they perform is measured by the quantity and character of the
natural gas they produce, and not by the resources they have expended in its
search ..." In December 1974, however, the FPC decided to include a dry
hole cost in their new discounted cash flow (DCF) approach.
The rate of return was set by the FPC as 15%, the upper end of the
"zone of reasonableness" of 12% to 15% they determined to be applicable for
natural gas producers. The investment life was set to be 9 years based on an
18 year depletion time. In addition, a lag period of 1.5 years was added to
account for the time between lease acquisition and the commencement of actual
production.
The total return in the June 1974 decision was then calculated by multi-
plying the production costs (line 5, Table 11-24) by the rate of return (15%)
FPC versus Hope Natural Gas Co., 320 US 591, 649.
11-55
-------
and the investment life (10.5 years) to get a range of 14.9 and 17.15C/MCF
(line lla).
In addition to the factors discussed above, the unargued items in lines
12, 13, 14, and 16 were added to come up with a total (line 17) which ranged
between 37.05C and 42.74C/MCF. The FPC, in order to encourage exploration
and development investment, decided to set the price ceiling at the upper
edge of this range with a small (lc/year) escalation to account for future
cost increases.
The one remaining point of contention concerned whether Federal income
taxes were an acceptable cost item. The FPC took the stance that a blanket
nationwide figure would not be adequate for this item because "the complex
nature of the Federal tax laws negate any simple calculation of a Federal tax
liability and require consideration of the producer's tax returns in order to
consider the timing relationships between investment expenditure, the ex-
pensing of intangible drilling costs, and jurisdictional sales." The FPC
decided, therefore, not to include this item at all in its cost computations.
In December 1974 the FPC revised its earlier methodology by using a dis-
counted cash flow approach. This approach led to a range of between 48c and
52C/MCF for the "economic cost" of natural gas, including a 15% DCF rate of
return to the producer. Thus, the value of 50C/MCF was decided upon with
increments to be added yearly.
FPC Opinion 699
11-56
-------
Some Conclusions
The FPC is under considerable continuing pressure from economists,
industry spokesmen, and Congressional critics to revamp its price setting
policies to effect further deregulation of natural gas producers in order
to cope with the growing demand and slackening production of natural gas.
It well recognizes the decline in the late 60's and early 70's of explora-
tion and development activities brought about by an abnormally low relative
price for gas and is attempting to rectify the situation while yet carrying
out its Congressional and judicially affirmed mandate to keep price at a
"just and reasonable rate." The trend in FPC regulation has definitely been
in the direction, however, of a phased deregulation over a number of years.
In the cost determinations the FPC has made in the past, there has been a
concerted effort to account fairly for the costs that are actually incurred in
producing natural gas. On the basis of previous FPC opinions in this regard,
it appears that additional costs due to equipment required by law would be
included by the FPC in line 4 (other production facilities), and would,
therefore, be passed on to the pipeline company (and to the ultimate consumer)
in the form of higher prices. This opinion is supported by a conversation
with Lundy Wright, Chief of Producer and Pipeline Rights Division of the FPC ,
who made it clear, however, that it was the Commissioners and not himself who
made such decisions. Assistant General Counsel Robert W. Purdue of the FPC
2
agreed also , pointing out that under FPC Order No. 481 (18 CFR 2.76),
1
Personal conversation, 8 November 1974.
2
Personal conversation, 15 November 1974.
11-57
-------
producers may file for relief from special costs such as this. He gave
as a current example the case of the Sun Oil Company in the Hugoton field
in Oklahoma which has been granted price increases to account for the
added costs of reinjection wells drilled in compliance with Oklahoma
standards on salt water disposal. He suggested that in many cases the
state regulations may be more stringent than what the EPA will propose.
Thus, he expressed confidence that the FPC would grant special allowances
on legitimate additional required equipment costs.
The one question which remains is whether the FPC would continue
to grant relief to individual producers according to Order No. 481 or
whether they would adjust the nationwide ceiling prices to account for
these added costs. In addition to these special allowances, the FPC has
recognized that the costs of small producers are often both higher and
more difficult to bear than those of the larger producers. As stated
earlier, the FPC's intention is to allow small producers to charge a
50% higher rate for new contract gas. It is true, therefore, that the
small producers are more protected against increasing costs due to new
required equipment than if they were limited by the 50c ceiling. Whether
this will be sufficient without special relief via Order 481 will depend
on the individual case, though from a superficial view, it appears that
they would certainly be protected by both these factors.
11-58
-------
Figures II-3A, B, & C show the histories of new contract production, new
field wildcat drillings, and new contract price for offshore Louisiana gas.
One can clearly see that the price of gas remained essentially at or below
the 1960 level throughout the entire decade of the 60's. During that time,
new field wildcats (and the resulting discoveries) peaked out and then fell
to two-thirds of their highest (1966) point. New contract production rose
steadily until it peaked in 1968 and fell sharply in 1970 as reserves con-
tinued to decline and producers were forced to curtail previously contracted
sales to interstate pipeline companies. As new contract price rose sharply
during the first years of the 70's, new contract production and new field
wildcats rose dramatically as well. These graphs indicate that the price
level is an important factor in investment in exploration and production of
natural gas in the 1970's.
Unfortunately, these production increases on new contracts have not been
sufficient to keep curtailments of production on older contracts from
occurring. According to FPC News Release No. 20849, these curtailments
amounted to over 218 billion cubic feet from September 73 to September 74
and are expected to rise to 266 billion cubic feet between September 74
and September 75.
-------
RCF
230
260 .
240
220
200
180
160
140
120
100
30 4
60
40
20
WELLS
New Contract
Production
FIGURE 11-3 A
360
330
300
270
240
210
180
150
120
90
60 4
30
$/MCF
New Field Wildcats Drilled
FIGURE II-3B
18
New Contract Gas Price
1960 61
SOURCE: Foster Associates, Washington, D^C^and MIT Energy Lab, Cambridge, Mass.
-------
II.4. FINANCIAL CHARACTERISTICS
4.1. The Role of Financial Characteristics in the Economic Impact Analysis
The oil and gas production industry has many unusual financial
characteristics reflective of the risks of the business, its special tax
status, and its special cash flow patterns. In examining the financial
characteristics as part of this economic impact analysis, three issues
are important:
• Are firms in the industry constrained in their access to the
required capital for pollution control so they may be forced
to close by the proposed effluent guidelines?
• What are the profitability levels and patterns in the industry
and will they be changed by the pollution control requirements?
• What is the cost of capital for the industry?
These issues are addressed in the following section. In the earlier
characterization of firms in the industry, the predominance of the major
oil companies in offshore operations was noted. The examination of the
financial characteristics of offshore operations thus primarily concerns
the impact of the capital costs of pollution control on capital budgets
of the major oil companies and the proper definition of the cost of
capital for these investments.
11-61
-------
4.2. Income Statements and Profitability
The profitability of the oil and gas industry is a subject of heated
debate between the industry and its critics and within the Congress.
High profitability is argued by the industry to be necessary to
compensate for low profitability in earlier years and to generate funds
for finding and developing new reserves and building new processing facilities.
Price controls, proposed "windfall profits" taxes, and the recent end of
depletion allowances are expressions of widespread belief that the industry's
profits are or will be excessive.
The Chase Manhattan Bank publishes a compilation of the financial reports
of 30 major oil and gas companies, including four foreign companies called the
Chase Group. These firms account for 71% of total U.S. crude oil production
and 83% of Gulf DCS production. Table 11-25 displays the total income state-
ments for the Chase Group from their worldwide operations for 1971, 1972, and
1973. The Group's net income on revenues was 8.7%'in 1973, 6.5% in 1972, and
7.4% in 1971. The portion of net earnings attributed to operations in the U.S.
were 35.4% in 1973, 53.4% in 1972, and 48% in 1971.
The interpretation of oil industry profitability has been particularly
controversial because of several important tax privileges. Provisions such
as the percentage depletion allowance, foreign tax credits, and the expensing
of intangible drilling costs are argued to have led in the past to an under-
stating of true industry profitability. The magnitude of these allowances are
discussed later. But in understanding the industry and the impact of added
costs of operations such as pollution control costs, one must appreciate the
industry's very unusual situation, particularly regarding U.S. operations. At
present, the per barrel revenues which a company receives for oil is largely
11-62
-------
TABLE_11-25
INCOME STATEMENT OF CHASE GROUP FOR 1971, 1972, AND 1973
1973 1972 1971
($ million) ($ million) ($ million)
Gross Operating Revenue 130,948 104,159 95,104
Non-Operating Revenue 2,961 2,119 2,756
Total Revenue 133,909 106,278 97,860
Operating Costs & Expenses . 90,298 74,413 68,805
Taxes - Other than Income Taxes 6,241 5,138 4,413
Write-Offs (incl. depreciation & depletion) 8,345 7,514 7,079
Interest Expenses 2,008 1,774 1,597
Other Charges 3_7_ 22^ 23
Total Deductions 106.929 88.861 81,917
Net Income before Income Taxes 26,980 17,417 15,943
Estimated Income Taxes 14,889 10,301 8,409
Income Applicable to Minority Interests 413 256 265
Net Income (a) 11,678 (b) 6,860 7,269
(a) Includes earnings from operations outside U.S.: 1973-$7,544 million;
1972-$3,204 million; 1971-$3,779 million.
(b) Excludes $84 million of extraordinary gains primarily from the sale
of assets.
SOURCE: "Financial Analysis of a Group of Petroleum Companies, 1972 and 1973,"
The Chase Manhattan Bank
11-63
-------
unrelated to either the cost of producing the oil or the demand for oil.
"Old" U.S. oil is price controlled at $5.25 per barrel and "new", uncon-
trolled oil is floating above the OPEC established world price because
of U.S. tariffs on imported oil. If old oil were decontrolled, as has
been proposed, its price would rise to the world level or above as well.
While there is a wide variation in the cost of producing oil, in fact
most current U.S. production has been operating at cost levels low enough
to make $5.25 prices profitable. Further price rises will make produc-
tion economical in higher cost wells, but it will also mean substantial
increases in profits for most wells now producing at $5.25 prices, about
60% of U.S. production. The level of profitability actually experienced
by the industry will be determined to a significant degree by Federal tax
policies. The issue with which the Congress, FEA, the Treasury Department
and the industry have been contending is what profit level is needed to
provide a fair return on the industry's investment and thereby provide a
necessary incentive for expanding domestic production. After that pro-
fitability level is determined, if it can be, profits will probably be
fixed by controlling prices and/or the additional profits will be taxed
away. The central point is that profitability for the industry, parti-
cularly the larger companies, will be determined more by Federal tax and
pricing policies than the economics of production. Until the specific
policies and regulations are established, there will be a considerable
uncertainty (perceived risk) on the part of the companies and investors
as to the industry's future.
11-64
-------
The currently existing tax laws have encouraged the oil companies to
spend funds generated by current operations on exploration and development of
new wells. Most of these expenditures can be charged against revenues rather
than capitalized. The level of spending is such that U.S. tax liabilities
will be very small or zero. In addition, the after tax profit on net worth
has been kept generally in line with other industries, so the industry
will continue to have access to equity markets. Figure II-4 shows the return
on net worth of the petroleum industry and other manufacturing industries over
the last 13 years.
Table 11-26 lists a compilation of net income after tax and the rate of
return on equity for 22 U.S. oil companies for the years 1963 through 1973.
Table 11-27 lists the rates of return by various measures for the Chase Group for
1971, 1972, and 1973.
A survey was conducted of the net incomes and cash flow of the signifi-
cant offshore producers. Table 11-28 displays these values for 1973.
The concept of oil industry profitability being set by government tax
policy is reflected in the windfall profits tax proposals by former President
Nixon and President Ford. In testimony by former Secretary of the Treasury,
George Shultz, on February 4, 1974, before the House Ways and Means Committee,
the rationale advanced for a windfall profits tax was that the $9.50 per barrel
price of U.S. new oil (at that time) was substantially in excess of the price
necessary to satisfactorily increase U.S. oil production.
11-65
-------
18
16
14
12
10
8
FIGURE 11-4
AFTER TAX RETURN ON NET WORTH
PETROLEUM VS. OTHER MANUFACTURING COMPANIES - 1960 TO 1970
(Percentages)
18
16
14
12
10
8
I
OTHER MANUFACTURING
I
I
I
I
I
I
I
I
1960 '61 '62 '63 '64 '65 '66 '67 '68 '69 '70 '71 '72 '73
SOURCE; "Energy Memo," January 1975, First National City Bank, NY
-------
TABLE 11-26
Net income after tax and the rate of return on equity of 22 U.S. oil companies (1963-73)
Company
Amerada Hesst
Ashl.md
•Atlantic Richfield
'Cities Service
Clark . .
-Continental , . .
•Exxon Corp
Getty
•Guilt .. .
'•Kerr-McCeet
Marathon ....
•Mobil
r/urphy
Phillips
»Shell
SVelly
• Standard of Calif.
••Standard (InrJ) . ,
S'inrJard '(Ohio) . .
•Sun
oTeraco
•Union of Calif. .
Totals
M.ijiir.y as of Sept
Source: Compiled
F.xchnnge
, 1973 «
Net %
income return*
. 1518 235
933 173
. . 270 2 89
.. 1356 98
30 5 29 9
2427 140
.. 2,4400 185
.. 1350 88
.. 7600 140
58 8 108
. 1294 152
, . 8428 157
536 244
. .. 2304 121
3327 109
440 75
8-136 !44
... 5!!2 124
74 1 66
2300 123
. ,. 1,2924 250
.. 1802 106
9,087.3 15.1
1372 , , 1971 , , 1970 ,
Net Net Net
income % Income % income %
462 8.3 1333 240 114.0 25.7
680 135 405 88 520 11.7
1925 65 210.5 7.3 209.5. 7.5
991 69 1045 7.7 1186 89
83 98 36 4.7 108 140
1702 104 1401 9.1 1603 10.7
1,5318 125 1,5166 131 1,3095 120
761 52 1201 8.5 1032 7.8
4470 8.3 551.0 102 5500 104
506 101 407 108 35.9 103
798 102 887 117 865 118
5742 109 5408 109 482.7 10.4
143 76 11.1 62 93 65
1484 81 1323 76 132.3 7.8
2605 89 244.5 87 2372 86
376 68 383 70 36.1 7.0
547.1 105 511 1 104 4548 98
3747 100 3406 9.6 3140 93
597 5.6 588 57 644 63
1547 88 151.6 89 1391 84
8890 12.4 9039 134 8220 13.1
1219 76 1147 7.4 114.5 7.6
5,951.7 9.7 6.0073 102 5.556.7 104
. 1969
Net
income
865
569
2301
1272
130
1464
1,24? 6
1058
6106
336
894
45G5
62
1278
291 2
384
4538
3210
5! 9
1523
7698
1389
5.5-19 9
. 30, 1971 tlnill ycnrs income estimated on llic tmis of income reported for
by Office of Tax Analysis, Department of Treasury, from Stand ml and 1
Commission (io Q Porms^ cited in Windfall or Excess
237
133
8.5
100
187
98
123
83
121
103
12 1
104
4.5
7.7
109
77
103
100
53
94
131
9.5
10.9
, 1963 ,
Ne!
income %
898 198
536 146
1058 78
1213 99
12.1 204
1500 106
1,2767 130
983 83
6266 132
354 120
833 127
430.7 10.3
73 54
1299 80
312.1 123
403 8.5
4518 107
3095 101
701 130
164.4 10.9
8196 145
1498 109
5.5394 11.8
1967 ,
Net
income %
768 222
484 155
1300 10.2
1278 109
115 234
136.1 10.1
1,1550 123
1182 10.5
5G83 12.9
321 115
739 123
385 4 98
82 62
1640 11.0
284.9 13.8
420 93
4094 103
280 9 96
671 145
1562 152
7544 148
1450 11.2
5.1756 12.0
i"
/ — 1966— r- Ne(
. Net , income
inrrjmc % '
— ^n~rrri w
/ J J tt. O I ?c O
450 176 i5?
1135 9.4 SU'
1201 110 10°6
9.6 24'.2> qjU
1156 103 p
1,090, HI,'-0?,}
923 9.0 I',?,?
5018 12.3 ^
330 12.9; H\
Do 8 1 L O H o^n i
356 1 9.5 IV •"" '
81 7.6 I." ,2J}
1334 10 3 \. i^n
2552 13.4 1
370 88fr -jnlo
4012 10.8 fir 2 19 3
2559 9.1 j' "JJ
569 13 3 i HI
100 6 108: ,°^
61? 1 15 Oj ,,5 o
13-12 ll.Z .
i
%
222
155
81
10.2
278
119
146
11.3
9.1
6 1
88
12.7
101
Ihc fir'l 9 inonllis of 1973.
. , . , _ .quarterly financial
'ours s Iiiiiiislri.il .Survey, Moody s Industrial Manual,
Profits Tax, Committee on Ways and Means,
_..
, 1964 ,
Ne!
income %
594 230
237 140
471 73
84 5 91
2.1 89
1001 111
1,0505 126
430 56
3951 1!0
20 1 147
694 11 g
2942 88
43 49
1150 93
1982 123
257 71
3453 105
194.9 75
438 120
68 5 88
5774 146
92.9 14 7
3,846.9 108
St.ilCincnU dlcil
, 1953
Net
income
524
18!
4-1.0
775
15
87.4
1,0195
-130
3714
1SS
49 1
2719
48
1031
1759
242
3?? !
183 1
33.9
6! 2
5'!/6
552
3.5797
o/
22 ;
il 1
70
86
66
10.5
123
6 !
153
102
8S
57
89
120
70
105
73
1! 1
8 1
99
11.0
wiili the Sccmiiy
U.S. House of Representatives, 1974.
Leading offshore producers accounting for 90.6% of total oil production in the Gulf of Mexico.
-------
TABLE 11-27
RATES OF RETURN FOR CHASE GROUP: 1971, 1972, 1973
1973 1972 1971
($ million) ($ million) ($ million
1) Average Borrowed & Invested Capital (a) 101,010 94,912 89,912
Earnings (b) 14,099 8,889 9,086
Return 14.0% 9.4% 10.I?
2) Average Invested Capital (c) 75,546 71,730 67,849
Earnings (d) 11,678 6,860 7,269
Return 15.8% 9.7% 10.7%
3) Average Total Assets 141,297 128,552 119,962
Earnings (e) 12,091 7,116 7,534
Return 8.6% 5.5% 6.3%
4) Average Gross Fixed Assets 139,649 132,545 126,109
Gross Operating Profit (f) 34,409 24,608 21,885
Return 24.6% 18.6% 17.4%
(a) Includes long-term debt, preferred stock, common stock, surplus and equity of
minority interests.
(b) Represents net income plus interest charges and income applicable to minority
interests.
(c) Includes preferred stock, common stock and surplus.
(d) Represents net income.
(e) Represents net income plus income applicable to minority interests.
(f) Represents gross operating revenue less operating costs and expenses and
taxes - other than income taxes.
SOURCE; "Financial Analysis of a Group of Petroleum Companies, 1972, 1973,"
Chase Manhattan Bank
11-68
-------
TABLE 11-28
Shell Oil Co.
Continental
Exxon Co.
Chevron (subsidiary of SOCAL)3
Gulf Oil Corp.
Arco
Union Oil of Calif.
Texaco Inc.
Placid Oil Co. (1972)
Kerr-McGee
ODECO^
Mobil Oil Corp.
Pennzoil
Signal (subsidiary of Burmah)
Tenneco
Amoco (subsidiary of Standard of
Forest
Southern Natural Gas
Citgo
Sun Oil
Superior
1973 FINANCIAL FIGURES FOR OFFSHORE PRODUCERS1
(millions of
Assets
6,836
3,690
25,079
8,650
10,074
5,964
2,909
14,761
162
867
284
10,690
2,001
227.2
5,230
Indiana)6 7,018
291
891
2,659
3,690
660
dollars)
Revenues
4,884
4,510
28,508
7,762
10,007
3,983
2,962
11,835
70
728
89
12,756
1,062
277.1
3,910
6,468
33
453
2,034.6
2,286
173
Net
Income
333
243
2,443
844
800
270
180
1,292
15(approx
63
19
849
84
13.5
230
511
-.037
54
146.9
230
34
Depletion
Plus
Depreciation
442
230
1,136
406
610
256
269
551
. ) NA
54
16
493
103
-4.72
223
448
16
40
114.2
228
30
Cash Flow
from Depr + Depl
-1- Not Income
775
473
3,579
1,250
1,410
526
449
1,843
NA
117
35
I-* / 'i
, J'-ii.
137
8.8
453
959
16
94
261.1
458
64
1. Listed in descending order of offshore production (bbl/day)
2. Includes intangible development expense.
3. Chevron Oil (which conducts offshore production) is owned by Standard Oil of Calif, which are presented here.
4. Primarily offshore contract drilling company, owned 51% by Murphy Oil; its offshore production for its own
account resulted in revenues of $15.2 million and a net loss before extraordinary income and income taxes
of $5.6 million.
5. Tot^l operations; Tenneco's oil operations accounted for 17% of operating revenues + 32% of income before taxes.
6. Figures are for Standard Oil of Indiana which owns Amoco.
Source: Annual reports; Dun & Bradstreet; phone conversations with oil companies.
-------
Secretary Shultz's reasoning was that $7 per barrel of oil provides
sufficient profits to oil companies both to return an adequate profit on
current investments and to encourage and allow investments in new pro-
duction sufficient to substantially reduce U.S. dependence on imported
oil.
An analysis of President Ford's proposed windfall tax on crude
prices by Plants Oilgram (January 20, 1975) concluded that the tax com-
bined with deregulation of old oil prices would iucie^se the average
price of domestic oil from $6.97 to $7.86 per barrel, .e rationale
behind this price level was that "original government calculations
reportedly showed a real oil price of between $7-8/bbl which provides
all the incentives needed at this time for production and development
activities, including enhanced recovery projects."
The conclusion one should draw from this is that the U.S. Government
is attempting to decide what is the "correct" level of profits for the
oil industry and attempting to write its tax laws so as to bring about
this level of profits. The objective seems to be to keep profits high,
perhaps higher than in 1973 but not let them get "too high."
For the major companies and for the industry as a whole, profita-
bility should continue to be strong for the next few years. It is possible
that market conditions or government actions could change the picture,
but changes in these areas will probably not affect profitability in the
short run sufficiently for pollution control costs to be of significance
to overall production. The greatest potential danger from changes in the
current tax structure and the pollution control requirements is that
investments in future production will be curtailed.
"Windfall" or Excess Profits Tax, U.S. House Committee on Ways and Means,
1974, p. 135.
11-70
-------
4.3. Capital Requirements
The oil and gas industry will have to make investments in new exploration,
development, and production well in excess of historic yearly levels in order
to accelerate domestic production. These higher levels of capital expenditures
raise the question of whether the industry will have access to the financing
necessary to achieve the goals of increased domestic production. This issue
was examined by the FEA and Arthur D. Little, Inc., in the Project Indepen-
dence Report. As part of an analysis of the economic impact on the industry
of the proposed effluent limitation guidelines, one must consider whether the
added capital required for pollution control is of sufficient magnitude to
approach capital availability limitations for the industry as a whole or
for individual firms.
The FEA's analysis of the financial availability issue for the energy
industries covered two main points, among others. Since World War II, 20 to
25 percent of total yearly business fixed investments have gone to the energy
sectors. If the same percentage continued over the 11 year period 1975 to 1985,
between $379 and $474 billion (in 1973 dollars) would be available for invest-
ment in the energy industries. FEA's estimate of the total investment required
under an "Accelerated Supply" scenario was $454 billion, including investments
in projects to come on line after 1985. The breakdown of investments by
industry is shown in Table 11-29- This estimate did not include outlays in the
petroleum industry which are expensed for tax purposes such as intangible
drilling and exploratory overhead costs nor did it include lease bonuses.
They would amount to about $107.4 billion, according to FEA. For an energy
11-71
-------
TABLE 11-29
Comparison of Capital Requirements Estimates : Total Dollars
Cumulative 1975 - 1985
(Billions of 1973 Dollars)
FEA
Accelerated
Supply(Without
NPC NAE ADL Work in Progress)
ADL
M
Oil and Gas 133
(including refining)
Coal 8
Synthetic Fuels 10
Nuclear 7
Electric Power Plants 137
(excluding nuclear)
Electric Transmission 42
Transportation 43
Other (f)
Total 380
149
18
19
93
53
125
457
122
6
6
84
43
90
43
8
396
(d)
80.3
10.6
.6
105.3
50.5
92.1
25.5(e)
2.2
367
FEA
Accelerated
Supply
98.4
11.9
.6
138.5
60.3
116.2
25.5(e)
2.2
454
(a)U.S. Energy Outlook, a summary report of the National Petroleum Council,
Washington, D.C., December 1972 (Average of four supply cases)
(b) U.S. Energy Prospects, An Engineering Viewpoint, National Academy of
Engineering, Washington, D.C., 1974
(c) Arthur D. Little estimates based upon an energy conservation scenario
(d) Assumes that imported oil price is $ll/8_. This column is considered
roughly comparable to the NPC, NAE, and ADL estimates with the exception of
oil and gas capital. The FEA estimates for oil, gas and refining do not
include lease bonus payments, and outlays that are expensed for tax purposes
(dry hole, intangible drilling and exploratory overhead costs); in order
to make the FEA oil and gas figures comparable to the other estimates,
$107.4 billion should be added to the FEA oil and gas estimates. Work in
progress consists of investment spending made prior to 1985 for new plant
and equipment which will not come on line until after 1985
(e) Does not include investments required for tanker fleets, but does include
$5.5 billion targeted for Trans-Alaska oil pipeline
(f) Solar, Geothermal, Municipal Waste Treatment Plants, and Shale Oil
SOURCE: Project Independence Report, p. 282, FEA, November 1974
11-72
-------
conservation scenario, the total capital requirements were estimated to
be $396 billion, including expensable outlays. The conclusion was
drawn by the report that, as a whole, the energy industries would have
access to adequate capital, assuming a simple continuation of their
past share of investment funds.
For the oil and gas industry, including refining, FEA estimated
that $98 billion would be required over the 11 year period for the
Accelerated Supply case. Table 11-30 shows these estimates plus the
expensed items. FEA believes this level of investment can be entirely
financed from internal funds with additional funds available for pro-
jects outside the oil and gas industry.
This conclusion is disputed by many inside and outside the oil
industry. One of the major exceptions that is made to the FEA analysis
is the treatment of lease bonuses. In Table 11-29, FEA has not included
$34.1 billion that FEA expected to be paid for lease bonuses from 1975
to 1985. Moreover, this value is probably too low since payments in
1974 were $5.0 billion and are projected by the Oil and Gas Journal to
be $5.5 billion in 1975 (February 1975).
11-73
-------
TABLE 11-30
Estimates of Petroleum Industry Capital Requirements
(Billions of 1973 Dollars)
1975 to 1985
FEA
FEA Accelerated
Accelerated Supply
Supply Adjusted
Without Work- for Work-
in-Progress in-Progress
Oil & Gas (1) 80.3 98.4
Oil & Gas Capital
Outlays That
Are Expensed (2) 73.3 73.3
Transportation:
Oil & Product
Pipelines 11.9 11.9
Gas Transmission 5.5 5.5
Lease Bonus Payments 34.1 34.1
TOTAL $205.1 $223.2
TTJIncludes: Oil, Natural Gas, and Refinery Output Numbers.
(2) Includes: Dry hole, intangible drilling, and exploratory overhead costs.
SOURCE; Project Independence Report, p. 290, FEA, November 1974
11-74
-------
If the $34.1 billion lease bonus payments of Table 11-30 are added
into the total capital requirements in Table 11-29, the FEA Accelerated
Supply estimate rises to $488.1 billion. Geological and geophysical
expenses can add another $5 to $8 billion in capital requirements over
the period. The $493-496 billion is beyond the range of $379-474 billion
which FEA estimated would be available from traditional financing patterns
for the energy industries.
A definitive analysis of capital requirements or capital availability
for the oil and gas industry is beyond the scope of this study. For the
purposes of this analysis, one should note FEA's conclusion, but it
should be used with caution.
The Chase analysis of 30 major oil companies cited earlier compiled
the sources and uses of funds by the companies. Table 11-31 lists the
sources of cash earnings for 1973. Thirty-nine percent of the cash flow
is from various capital recovery mechanisms such as depreciation and
depletion. Table 11-32 lists all of the sources of capital and their
disposition for the year. The effective end of depletion allowances
for the large oil and gas companies has reportedly had a major impact on
cash generation for the companies. Industry-wide data, such as for the
Chase Group, is not yet available for the first quarter of 1975; however,
reports by individual firms have identified the end of the depletion
allowance as having a major effect on cash generation.
11-75
-------
TABLE 11-31
CASH FLOW OF CHASE GROUP FOR 1973
$ millions
Net income
Write-offs (incl. depreciation
and depletion;
Other non-cash charges (net)
11,678 (55%)
8,345 (39%)
1,207 (6%)
Total Cash Flow
21,230 (100%)
SOURCE: "Financial Analysis of a Group of Petroleum Companies, 1973",
The Chase Manhattan Bank
11-76
-------
TABLE 11-32
SOURCE AND USE OF CAPITAL FOR CHASE GROUP IN 1973
$ million (%)
Funds Available From:
Cash flow 21,230 (73.4)
Long-term debt issued 4,381 (15.2)
Preferred and common stock issued 432 (1-5)
Sales of assets and other transactions 2,867 (9.9)
Total 28,910 (100.0)
Funds Used For:
Capital expenditures 14,637 (50.6)
Investments and advances 382 (1.3)
Dividends to company shareholders 3,965 (13.7)
Dividends to minority interests 157 (0.6)
Long-term debt repaid 3,698 (12.8)
Preferred and common stock retired 570 (2.0)
Total 23,409 (81.0)
Change in Working Capital 5,501 (19.0)
SOURCE: "Financial Analysis of a Group of Petroleum Companies, 1973",
The Chase Manhattan Bank
11-77
-------
Looking ahead to the next ten years, one sees conflicting currents.
Higher crude and natural gas prices have allowed large increases in
profits per barrel. On the other hand, the high prices will dampen
demand and also raise public concern about excess oil company profits.
One must also consider that 1973 and 1974 saw foreign operations gene-
rating the largest earnings. This, combined with price controls and
excess profits taxes in the U.S., may discourage investment in U.S.
operations rather than even a continuation of historic patterns.
As has now been said several times, it is very difficult to project
profitability or capital expenditures patterns for the industry over an
extended period of time, given the economic and political uncertainties
of the next few years. While it is probably inaccurate to simply pro-
ject trends from the last ten years into the next ten, it is equally
wrong to extrapolate the trends of the last year or two which saw the
devaluation of -the dollar and large inventory profits. The Oil and Gas
Journal collects capital expenditure statistics each year from 150 firms
which are then proportionately projected to the whole industry on the
basis of the companies' portion of total industry crude production.
Table 11-33 lists the results for 1972, 1973, and 1974 plus a projection
for 1975. The Journal does not make a clear distinction between
expenditures which companies capitalize and those they do not. The
drilling and exploration expenditures probably include significant funds
which are normally expensed by the companies.
11-78
-------
TABLE 11-33
ESTIMATED CAPITAL AND
EXPLORATION
EXPENDITURES
OF U.S. OIL
INDUSTRY
(1972-1975)
Exploration and Production
Drilling and Exploration
Production
OCS lease bonus
Total
Other Expenditures
Refining
Petrochemicals
Marketing
Natural Gas Pipelines
Crude Products Pipelines
Other Transportation
Miscellaneous
Total
1975
(budgeted)
($ million)
8,034.0
2,104.1
5,500.0
15,138.1
3,127.8
1,643.1
1,106.0
988.0
2,318.0
240.4
1,684.0
11,106.9
1974
(estimated)
($ million)
7,657.0
2,005.5
5,024.0
14,686.5
1,974.7
816.3
780.7
541.0
1,096.0
148.7
1,073.3
6,430.7
1973
($ million)
6,660.8
1,734.8
3,082.0
11,477.6
1,103.8
269.1
914.5
600.0
150.0
152.9
646.9
3,837.2
1972
($ million)
5,717.6
942.4
2,258.8
8,918.8
946.6
300.6
1,148.9
578.0
94.0
175.0
570.0
3,813.1
Total Expenditures
26,245.4
21,117.2 15,314.8
12,731.9
SOURCE: Oil and Gas Journal, Feb. 3, 1975
11-79
-------
As a comparison, Chase publishes a survey entitled "Capital
Investments of the World Petroleum Industry" each year. The most
recent year covered is 1973. Table 11-34 lists the capital expen-
ditures for the U.S. and for the world for 1962 through 1973.
Table 11-35 is a breakdown of exploration and development expen-
ditures in the U.S. for 1972 and 1973.
Chase lists in Table 11-34 the sum from Table II-35 of expen-
ditures for lease acquisition, producing wells, and dry holes. The
remaining items were not counted as being capitalized. This pattern
may not always hold true, particularly for dry holes and geological
and geophysical expenses.
The estimates of expenditures by the Journal and by Chase are
significantly different for the exploration and production categories.
However, they give general guidance as to the level of expenditures
one should use as a point of comparison with the pollution control
capital expenditures. Table 11-36 lists the general comparison values
which can be used in the impact analysis.
There are three points one should conclude from this discussion
of oil industry financial resources:
• The profitability of the oil industry, its tax liability, and
its ability to finance itself are critically dependent on
government policy and actions. Powerful political groups
are keenly interested in changing government policies to make
the industry more or less profitable. These influences are
11-80
-------
TABLE II- 34
ESTIMATED CAPITAL AND EXPLORATION EXPENDITURES
1967
1968
1969
1970
1971
1972
1973
I
oo
WORLD
Crude Oil and Natural Gas
Natural Gas Liquids Plants
Pipe Lines.
Tankers
Refineries
Chemical Plants
Marketing ....
Other
Total Capital Expenditures
Geological & Geophysical
Expense & Lease Rentals .
COMB/NED
UNITED STATES
Crude Oil and Natural Gas
Natural Gas Liquids Plants.
Pipe Lines
Tjnkers
Refineries
Chemical Plants
Marketing
Other ... . ' '
Total Capita/ Expenditures
Geological & Geophysical
Expense & Lease Rentals .
COMBINED
Million Dollars
5,595
405
860
1,255
2,585
1,565
2,705
605
15,575
1,190
16,765
3,750
275
360
40
775
825
1,250
375
7,650
615
8,265
6,875
585
1,080
1,650
2,950
1,480
2,665
615
17,900
1,330
19,230
4,675
250
425
50
800
650
1,150
350
8,350
715
9,065
7,075
465
910
2,050
3,210
1,310
2,805
550
13,375
1,380
19,755
4,525
225
300
100
950
575
1,250
250
8,175
725
8,900
6,650
580
850
2,575
4,000
1,525
3,220
725
20,125
1,340
21,465
4,1 10
225
450
100
1,075
550
1,450
265
8,225
665
8,890
6,520
695
1,200
2,875
4,755
1,535
3,380
840
21,800
1 ,395
23,195
3,185
200
550
125
1,050
500
1,350
290
7,250
715
7,965
9, 590
515
1,230
3,775
4,955
1,350
2,825
710
24,950
1,540
26,490
5,740
1/5
300
125
900
450
1,100
260
9,050
740
9,790
12,415
510
1,230
6,550
4,865
1,175
2,480
770
29,995
1,700
31,695
7,290
150
450
100
1,050
425
850
325
10,640
850
1 1 ,490
SOURCE:
"Capital Investments of the World Petroleum Industry, 1973," Chase Manhattan Bank
-------
TABLE 11-35
EXPLORATION AND DEVELOPMENT EXPENDITURES
IN THE U.S.: 1972 AND 1973
1973 1972
($ million) ($ million)
Expenditure
Lease acquisition
Onshore 500 200
Offshore 3,100 2,275
Producing wells 2,705 2,330
Dry holes 985 935
Geological and geophysical
expense 675 575
Lease rentals 175 165
Total 8,140 6,480
SOURCE; "Capital Investments in the World Petroleum
Industry, 1973", Chase Manhattan Bank
11-82
-------
TABLE 11-36
TYPICAL YEARLY CAPITAL EXPENDITURES
OF SEGMENTS OF THE OIL INDUSTRY IN THE U.S.
Offshore Oil and Gas Production $6-$7 billion per year
Onshore Oil and Gas Production
$3-$4 billion per year
Other Capital Expenditures
(refineries, pipelines,
marketing, etc.)
$6-$7 billion per year
Total
$14-$18 billion per year
SOURCE: Arthur D. Little, Inc., estimates
11-83
-------
far more important to the overall profitability and access to
capital of the industry than the proposed pollution control
standards.
• While FEA has said that the industry can reasonably be expected
to finance itself, knowledgeable people have questioned the
conclusion, and it should be used here with caution.
• Over the period 1977-1983, the oil and gas industry will make
capital investments of approximately $6-$7 billion per year on
the exploration, development, and production of offshore oil
and gas. Total industry capital investment during the period
will be about $14-$18 billion per year.
4.4. Capital Structure
The petroleum industry has historically depended primarily on
internally generated funds rather than borrowed capital. Table 11-37
is the balance sheet for the Chase Group for 1971, 1972, and 1973.
Long-term debt plus deferred credits and minority interests makes up
22%-23% of total capitalization for the three years and is about 40% of
the value of equity. The portion of total capitalization which is longer-
term debt has been gradually rising since 1964, when it was about 13%.
Although long-term lease arrangements and production payments do not
appear on the balance sheet, they are sources of additional capital.
If they were regarded as debt, the Group's debt in relation to capital
employed would have been 33% in 1973 and 22% in 1964. Table 11-38 lists
11-84
-------
TABLE II- 37
oo
(M
Assets
Current Assets
Investments and Advances
Property, Plant and Equipment (a)
Other Assets
Total Assets
Liabilities and Net Worth
Current Liabilities
Long-Term Debt
Deferred Credits
Other Reserves
Minority Interests
Net Worth:
Preferred Stock
Common Stock
Capital Surplus
Earnings Reinvested in Business
Shareholders' Equity
Total Liabilities and Net Worth
? CHASE GROUP, 1973, 1972, 1971
12/31/73
($ million)
56,149
10,386
79,613
4,268
150,416
36,502
22,727
5,711
2,821
3,274
315
10,455
8,597 -
60,014
79,381
150,416
37.3%
6.9
52.9
2.9
100.0
24.2
15.1
3.8
1.9
2.2
0.2
7.0
5.7
39.9
52.8
100.0
12/31/72
($ million)
42,686
10,266
75,097
4,134
132,183
28,540
21,858
4,587
2,411
3,031
404
10,511
9,061
51,780
71,756
1J2,183
32.3%
7.8
56.8
3.1
100.0
21.6
16.5
3.5
1.8
2.3
0.3
7.9
6.9
39.2
54.3
100.0
12/31/71
($ million)
39,586
9,900
71,740
3,673
124,899
25,656
20,523
3,804
2,078
2,941
429
10,530
8,800
50,138
69,897
124,899
31.7%
7.9
57.4
3.0
100.0
20.5
16.4
3.0
1.7
2.4
0.3
8.4
7.1
40.2
56.0
100.0
(a) After deducting accumulated reserves of $64,060 million in 1973, $60,530 million in 1972,
and $58,562 million in 1971.
SOURCE: "Financial Analysis of a Group of Petroleum Companies, 1973, 1972",
The Chase Manhattan Bank
-------
TABT1' 11-38
PETROLEUM INDUSTRY CAPITALIZATION, 1972
CAPITAL STRUCTURE
I)ebt Equity 0' her L
Penn zo i 1 - Co . 55.6% 35,7 % 8 . 77.
Apco Oil Corp. 44.0 54,9 1.1
Amerada- Hess Corp. 44.1 55.2 .7
Ashland Oil, Inc. :-'. 1 53.4 10.5
Atlantic Richfield Co. . /> 77,3 1.3
Bel co Petroleum Corp. 40,, ! 59.7
British Petroleum Co. 37 . ^9.8 .\1
Cities Service 27.9 ':: . 3 2.8
Clark Oil and Refining 34.7 • 0 4.3
C otnmo awe a 1 1 h 0 i L 44.2 4 -. 9,0
Covirinent-al Oil 28.6 0' ' 4.7
Fxxon Cory. 17.0 }" .. 3,4
Gen. Am. Oil of: Texas .5 99.'"
G.- l:ty Oi 1 Co . 6,3 8«» . .- • >. 2
" f'
Corp. 25.5
CM If Oil C mad a 18.7
Holmerich and Payne 48,0
Impcri.riL Oil, Ltd, !4»b
5'
L'-uis- 'n,:> land and Ex p. I. '30,5 o' j
Marathon Oil Co, ?8,8 ' . 1":
M o s a I • e t r o 1 e LHP c, 8,5 41. i . 4
» Mob i 1 0 i 1 Cor p „ 16,8 7 9 .9 3.3
Mv::plv/03l Corp, '» 3 . Q 42.1 22,9
0 c c- i d cntal Pe t r o 1 euro 5 4 . 0 4 4 „ 7 1 , 3
Pacific Petroleums Ltd. 32,4 (•,;.
* Phillips Petroleum Co, iN » o 6o,v/ 2,4
Quak o r S t a t e 0 i 1 25, -> 6 ^ . f-- , 2.
Royal Dutch Petroleum 20,4 68. h U.O
» Snell Oil Co. 26.0 1', .''."
Shell Transport and Trad, 2 1 . ?: 66,'' 11,8
• Ske 1 i y Oil Co . 11. 1 8 P- . ' .=
* Standard Oil (Calif,; 16,5 83,1.
• Standard Oil (Ind.) 20,7 73,9 5.4
Standard Oil (Ohio) 2.6.9 68, 8 V,3
® Sun Oil Co, 22.8 69,8 7.4
* Superior Oil Co. 22.3 77.7
Tesoro Petroleum 24 . 8 71.7 3,5
Texaco, Inc. 13.9 73.
Union Oil of Calif. 26.3 68.2
United Refining Co. 36.9 63.1
2 12.9
Average 28.4 66.8 6,5
1. Includes: Preferred Stock, Deferred Taxes, and Minority Interest.
• Leading offshore producers (representing 92.2% of total offshore production)
SOURCE: "Value Line", cited in Opinion 699, Appendix E, Federal Power
Commission, 1974
11-86
-------
the debt and equity percentages for 41 petroleum companies for 1972.
On the average, equity accounts for 66.8% of total capitalization. One
also sees in Table 11-37 the predominance of retained earnings in net
worth. About 75% of shareholders' equity is retained earnings. In
1964, the retained earnings were 62% of equity.
Although the ratio of long-term debt to equity has been rising
to its present level of about 28%, it is below what one would reasonably
expect to be an upper limit of debt capacity for a profitable industry.
Each year Dun's Review publishes financial ratios for 71 categories of
manufacturing firms. For 1973, the average of the ratios of total debt
to net tangible worth for these firms was 103%. For the Chase Group of
petroleum companies, the comparable ratio was about 78%. The concept of
an "upper limit" is an abstraction referring to a range which is viewed
as meeting some set of criteria by the banking and investment community
and applicable to a particular industry. A firm which takes on signifi-
cantly more debt than other firms in its industry exposes its debtors to
higher risks than other firms in the industry. With such a high debt
portion of its capital structure, a company may face higher interest rates,
, problems of raising equity or possibly the non-availa-
bility of funds.
In 1973, the Chase Group had long-term debt of $22.7 billion. In
comparison, the Group's working capital was $19.6 billion and their net
fixed assets were $79.6 billion. Total net assets were $79.1 billion.
The ratio of debt to total capitalization is .47 as compared with about
.6 as characteristic of manufacturing industries. One can also look
at the interest coverage by before tax income. The calculation is before
tax income plus interest payments divided by the interest payments.
From the creditor's viewpoint, this ratio indicates how much the interest
11-87
-------
payments he is owed are covered by earnings. In 1972, which was the
lowest recent profit year, the interest coverage ratio was 10.7. In
1973, the ratio was 14.5. If long-term lease arrangements and produc-
tion payments are regarded as debt, the Chase Group's debt in relation
to capital employed would have been 33% in 1973. While the precise
figures are not reported by Chase, the interest coverage would fall to
9.3 in 1973 if the lease payments and production payments are regarded
as yearly payment obligations similar to interest with an equal claim
on revenues.
On the basis of their capital structure, the larger oil companies
must be regarded as financially strong. Though hard to quantify, the
companies seem to have the capacity for undertaking additional debt in
the coming years. Whether this capacity will be sufficient along with
other capital sources to meet the industry's needs or national energy
goals is open to some question and beyond the intent of this brief
discussion.
The role of the industry financial analysis in this economic -impact
study is to characterize the financial condition of the industry and report
reputable estimates of the capital burden which the industry is likely
to experience in the absence of the pollution abatement requirements.
Given the financial condition and the other capital demands, this report
should indicate whether the magnitude of capital expenditures required
by the effluent guidelines will significantly distort the total industry
capital demands or its financial condition.
11-88
-------
The oil industry now is in relatively strong financial condition.
It anticipates making capital investments between now and 1983 far in
excess of the investments required for compliance with the effluent
guidelines. Thus, the investments in offshore water treatment and
reinjection equipment cannot be regarded by themselves as being of
importance to the financial strength or the required capital investment
burden of the industry between 1975 and 1983.
Statements about the relative importance of a proposed regulation
on one activity of an industry neglect the cumulative effects of other
regulations, inflation rates, materials and labor costs, etc. When
judging the impact of the effluent guidelines, one is at best making
qualitative judgments about their importance relative to the total
capital demands on the industry at the same time.
11-89
-------
4.5. Cost of Capital
Introduction
One objective of a business organization is to maximize the market value
of the firm's equity. When evaluating investments with this objective one can
use the firm's cost of capital as a means of ranking investment alternatives.
The cost of capital is the rate of return on investment projects which leaves
unchanged the market price of the firm's stock. The cost of capital can b-
employed in a number of ways: 1) an investment project is accepted if its
net-present value is positive when cash flows are discounted at the cost-of-
capital rate; or 2) a project is accepted if its internal rate of return is
greater than the cost of capital. Thus, the cost of capital represents a
cut-off rate for the allocation of capital to investment projects.
The cost of capital is one of the most difficult and controversial topics
in finance. There is wide disagreement, both in practice and in the financial
literature, about how to calculate a firm's cost of capital.
Weighted Average Cost of Capital
There are a number of alternative sources of financing available to a
firm; they include long-term debt, preferred stock, common stock, and retained
earnings. If more than one type is present in the capital structure of the
firm, the weighted average cost of capital reflects the interdependencies among
the individual costs. For example, an increase in the proportion of debt
financing will cause an increase in the risk borne by the common shareholder.
The shareholder will then require a higher rate of return, implying a higher
cost of equity.
As indicated in Table 11-38, preferred stock does not represent a very
high proportion of the capital structure of the leading offshore producers.
11-90
-------
Thus, for the purposes of this analysis, the weighted average cost of capital
will consist of a factor for the cost of debt and a factor for the cost of
equity.
The mathematical expression generally used to calculate the weighted
average cost of capital is as follows:
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.
Estimate of the Cost of Debt
Approximating a firm's cost of debt is a fairly straightforward matter.
Assuming that recent bond issues are representative of the firm's normal
current and expected future debt costs, the cost of this recently acquired
debt can satisfactorily be used as a surrogate for k, in the cost of capital
calculations. Recent petroleum bond issues (rated AAA to A) have had yields
ranging from 9.0% to 9.5%. In this analysis, 9.5% is used as the cost of
debt financing.
Because the range in bond yields is so small, a separate cost of debt has
not been calculated for each firm in this sample of the petroleum industry.
Estimate of the Cost of Equity
Calculation of the cost of equity is the controversial element in a cost
of capital analysis. There are several methods which one can use. The cost
of equity is the rate of return which investors require on their money if they
11-91
-------
are to buy a stock.
One method ±s to calculate the actual rates of return achieved by share-
holders in the past, on the assumption that past rates of return are an accurate
indication of shareholder expectations. The principal weakness of this approach
lies in this very assumption. Given the increased uncertainties about oil
prices, taxation, and regulation, the risk factors of the petroleum industry may
seem to be changing, causing a corresponding change in expected rates of return.
Thus, this method did not seem appropriate for this analysis.
A second method involves deriving the cost of equity from expectations
about future dividends. This method is similar to the first one, but it
involves a much longer time horizon. The principal difficulty in this approach
is estimating future dividends. For a number of oil companies, the dividend
payout ratio has decreased from 54% in 1969 to about 40% in 1973 and about 30%
in 1974. Recent financial data show that for the first quarter of the years 1968-1975,
profits as a percent of gross operating revenue have been steadily decreasing,
with the exception of 1973 and 1974. In 1975, this percent was a record low.
Thus, due to the difficulty of estimating future dividends, this method was
not used.
A third method, which seemed most appropriate, involves calculation of a
risk-adjusted rate of return. By owning a portfolio of stocks, an investor
can partially eliminate the risk involved in owning one stock. That risk which
cannot be diversified away is the covariance of the stock with the total market.
This covariance is known as the firm's "beta" (@). For example, if a firm's
stock has a beta of 1.0, when the total market moves up or down by 10%, this
stock also moves up or down by 10%. If the beta were 0.5, the stock would move
up or down by 5%. The beta of a stock is a substantially complete measurement
11-92
-------
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:
where: k = cost of equity
r = risk-free rate; usually the U.S. Treasury Bill rate
r = total market return
m
@ = 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. The total market return from 1928 to 1965 averaged 9.3%. The
market return ranged from 10.9% in 1971 to 18.2% in 3974. 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
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 assets, total market value, total revenues,
•"and offshore production (barrels/day). The arithmetic mean was also calculated.
The estimated industry cost of the capital ranges from a low of 10.4% to a high of
14.4%, with an average of 12.4%. See Table 11-39 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 12% seems
reasonable.
11-93
-------
TABLE II- 39
EXAMPLE OF CALCULATION OF COST OF CAPITAL FOR 1971-19741
2 •
Firm Average Beta Cost of Equity Cost of Capital
( % )
Atlantic Richfield 1.10 13.9 11.8
Cities Service .90 12.5 10.0
Continental Oil 1.10 13.9 10.6
Exxon Corp. .95 12.8 11.0
Gulf Oil Corp. .90 12.5 10.1
Kerr-McGee Corp. 1.05 13.6 10.6
Mobil Oil Corp. .95 12.8 11.0
Pennzoil Co. 1.35 15.7 8.3
Shell Oil Co. .95 12.8 10.7
Standard Oil (Calif.) 1.05 13.6 12.1
Standard Oil (Ind.) .85 12.1 9.9
Sun Oil Co. .70 11.1 8.8
Texaco, Inc. .95 1-2.8 10.0
Union Oil of Calif. 1.10 13.9 10.7
During this period, the U«S. Treasury Bill rate averaged 6.05%, and
the market return averaged 13.2%.
2
Source, Value Line.
Cost of debt is assumed to be 9.5%. Capital structure taken from
Table 11-38.
11-94
-------
Several words of caution about the cost of capital for an industry should
be added at this point. Although 12% may be an appropriate general measure of
the cost of capital of the petroleum industry, each company has a different
capital structure and amount of risk associated with it. The cost of capital
for the individual firms ranges from 8.3% to 16.0%. Rather than saying that
the cost of capital of the industry is about 12.0%, it may be more appropriate
to state that the cost of capital in the industry ranges from 8.3% to 16.0%.
Furthermore, interest rates and stock prices have fluctuated widely in the
past 24 months. As shown in Table 11-40, common shares of many of the off-
shore producers had a price three to seven times earnings on December 31, 1974;
however, this P/E ratio fluctuated greatly during the year.
In addition, the gap between internally generated funds and needed capital
investments has widened considerably. Although gross revenues grew at an
average rate of 19.2% between 1969 and 1974, available cash flow grew by only
14.7%. In 1974, while revenues increased nearly 75% from 1973, cash flow rose
by only 31%. As a result, the petroleum industry must increasingly resort to
outside financing. This trend is already evident. Between 1967 and 1972, the
industry's ratio of long-term debt to total invested capital (long-term debt,
preferred stock, and common stock) has risen from 0.18 to 0.28. It is
expected to rise to 0.30 in the near future. Thus, one might also expect a
rise in the cost of equity and the cost of capital for the industry. Traditional
financial theory implies that the cost of capital is not independent of such
changes in the capital structure. If the industry has not yet reached the debt
limit, the increase in the cost of equity will be offset by the use of cheaper
debt funds, resulting in a lower over-all cost of capital. However,
11-95
-------
TABLE 11-40
Oil Stock Prices
Atlantic Richfield
Cities Service
Continental Oil
Exxon Corp.
Forest Oil Corp.
Gulf Oil Corp.
Kerr-McGee Corp.
Mobil Oil Corp.
ODECO (private?)
Pennzoil
Phillips Petroleum
Placid Oil Co. (private?)
Shell Oil Co.
Signal
Shelly Oil Co.
Southern Natural Gas — merged
into Southern Natural
Resources, Inc.
Standard Oil (Calif.)
Standard Oil (Ind.)
Sun Oil Co.
Superior Oil Co.
Texaco , Inc .
Union Oil (Calif.)
Tenneco
High
113 3/4
62 1/4
58 1/2
99 3/4
11 1/8
25 1/4
92 1/2
56 1/2
30 1/2
71 3/8
72 7/8
22 3/4
73
5/73
55 1/2
36 5/8
45 7/8
61 3/4
304
32 7/8
56 3/4
24 3/4
Low
73
32 3/4
29
54 7/8
(Bid)
16
47 1/8
30 5/8
12 3/4
31 5/8
30 1/4
12 3/4
44 1/4
27 1/8
20 1/8
39 7/8
33 3/4
134
20
27 1/4
16 3/4
12/31/74
P/E Ratio Closing
11
5
5
5
11
3
16
3
5
7
6
2
7
7
3
6
4
15
3
4
6
90
42 1/4
44
63 1/8
1/2 (Asked)
17 1/4
71
36 1/4
16 7/8
41 1/2
46
13 1/4
55 1/2
41 7/8
21 3/4
42 1/2
35 3/8
L72
20 7/8
38 1/2
23 L/4
11-96
-------
the industry is moving beyond the "optimal" capital structure, the cost of
capital will rise. furthermore, given the fact that interest rates have
been unusually high in 1973 and 1974, one might expect a decline in the cost
of debt in the near future and a rise later.
The cost of capital has been used in this report to help evaluate whether
firms will make the required investment to come into compliance with the
proposed produced water treatment and reinjection requirements. The revenue
stream resulting from making the investment and keeping the well in production
has been discounted at the rate of the cost of capital. If the net present value
of the investment in the treatment equipment is positive, the assumption has
been made that the firm will make the investment rather than close in the well.
If the industry cost of capital lies in the 10.4% to 12.0% range, theoretically,
more firms will be able to make the investment. If the industry cost of capital
lies in the 12.0% to 14.6% range, fewer firms can be expected to make the
investment.
While 12% seems to be a realistic cost of capital value, the impact
analysis has used 12%, 15%, and 20% to test the sensitivity of the results to
different assumed or actual cost of capital values. The high end of the range
has been chosen so that any possible errors in the analysis will be on the
conservative side. A high cost of capital places the greatest burden on
justification of investments which have a long time horizon.
11-97
-------
III. PROPOSED EFFLUENT LIMITATION GUIDELINES
III.l. PROPOSED EPA REGULATIONS
The U.S. Environmental Protection Agency is proposing a set of
effluent limitation guidelines for the offshore oil and gas production
industry. There are three sets of proposed effluent guidelines:
1. The Best Practicable Control Technology Currently
Available (BPCTCA) (1977 implementation)
2. The Best Available Technology Economically Achievable
(BATEA) (1983 implementation)
3. The New Source Performance Standard (NSPS)
(1977 implementation)
In November 1974, the EPA issued the Draft Development Document for
Effluent Limitations Guidelines and New Source Performance Standards for
the Oil and Gas Extraction Point Source Category. This report presented
an initial recommended set of guidelines based largely on a report by
Brown and Root, Inc., for the Offshore Operators Committee, an association
of companies operating offshore oil and gas wells.
Determination of Beat Practicable Control Technology Currently Available
To Remove Oil from Water Produced with Oil and Gas, March 1974.
III-l
-------
Based upon a preliminary economic impact assessment among other
factors, the initial guidelines were modified to the form reported here.
Table III-l lists the applicability of the guidelines to "new" and
"existing" sources of effluent discharge. Over 30 wells may produce to
one offshore platform. In most producing areas, the produced formation
water from the wells is now separated from the oil and gas, treated and
discharged to the ocean. Several producing platforms ran pipe their
production to one processing platform which discharges the formation
water after treatment. Each of the discharges from a platform is a
point source under the guidelines. In addition to the discharge of
produced formation water, the rain water runoff and sanitary waste must
be collected and treated on each platform. For these discharges, each
platform is a point source.
Table III-2 lists the proposed guideline requirements. The guide-
lines separate the offshore producing areas into what are called the
state and Federal waters. This is the jurisdictional distinction between
those oil and gas fields whose development and operations are the respon-
sibility of the contiguous states, as opposed to the U.S. Geological
Survey. The EPA has adopted the state and USGS jurisdiction boundary to
sub-categorize the offshore producing areas. The state and Federal waters
boundary is approximately three miles from the shoreline.
In 1977, the BPCTCA guidelines will require the formation water pro-
duced from offshore wells in both state and Federal waters to be treated
such that for any consecutive 30 days the averages of daily effluent
samples (four per day) will not exceed 48 parts per million (ppm) of oil
and grease 95% of the time. In 1983, the BATEA guideline requires
III-2
-------
TABLE III-l
I
u>
Wells Producing
Prior to 1977
Wells Beginning
Production in
1977 and later
APPLICABILITY
Guideline
Average of Daily
Effluent Values
for 30 Days Not
to Exceed^
Guideline
Average of Daily
OF PROPOSED GUIDELINES
1977
Federal
Waters
BPCTCA1
48 ppm
NSPS3
30 ppm
State
Waters
BPCTCA
48 ppm
NSPS
30 ppm
1983
Federal State
Waters Waters
2
BATEA BATEA
30 ppm no discharge
NSPS BATEA
30 ppm no discharge
Effluent Values
for 30 Days Not
to Exceed^
1. BPCTCA is the Best Practicable Control Technology Currently Available guideline.
2. BATEA is the Best Available Technology Economically Achievable guideline.
3. NSPS is the New Source Performance Standard guideline.
4. During any consecutive 30 days, the daily averages of four effluent samples shall not exceed
the specified value 95% of the time.
SOURCE: Environmental Protection Agency
-------
TABLE II1-2
PROPOSED EFFLUENT GUIDELINES
Guideline
Oil and Grease Limitations
Average of daily
values for 30
Maximum
for one day
ppnP
consecutive days
shall not exceed^
ppm
Residual
Chlorine
ppm
BPCTCA
state waters
produced water
deck drainage
sanitary waste
federal waters
produced water
deck drainage
sanitary waste
BATEA
state waters
produced water
deck drainage
sanitary waste
federal waters
produced water
deck drainage
sanitary waste
NSPS
state waters
produced water
deck drainage
sanitary waste
federal waters
produced water
deck drainage
sanitary waste
72
72
NA
72
72
NA
52
NA
52
52
NA
52
NA
52
52
NA
48
48
NA
48
48
NA
no discharge
no discharge
30
NA
30
30
NA
30
NA
30
30
NA
NA
NA
1
NA
NA
1
NA
NA
1
NA
NA
1
NA
NA
1
NA
NA
1
NOTE:
1. There shall be no discharge of free oil to the surface waters.
2. There shall be no discharge of floating solids as a result of sanitary
waste discharge.
3. ppm (parts per million) is equivalent to a. milligrams per liter
(mg/1) concentration.
4. During the 30 days, 95% of the daily averages must not exceed the
ppm standard.
SOURCE; U.S. Environmental Protection Agency
111-4
-------
platforms in state waters to end all discharge of produced formation
water. The water can be piped ashore or reinjected into a subsea forma-
tion. In Federal waters, the BATEA requires that for any consecutive
30 days the averages of daily effluent samples not exceed 30 ppm 95% of
the time. The guidelines also require daily maximums, as shown on
Table III-2.
In addition to the BPCTCA and the BATEA guidelines, the EPA is pro-
posing a New Source Performance Standard (NSPS) guideline applicable to
all new wells in both state and Federal waters which is identical in its
requirements to the BATEA guidelines except that its applicability begins
in 1977.
New wells beginning production in state and Federal waters between
1977 and 1983 will have to comply with the NSPS guidelines. By 1983, all
wells in state waters, new and existing, will have to go to reinjection
of formation water. The new wells in Federal waters will continue to
have to meet the BATEA and NSPS requirements.
The EPA used the survey from the Brown & Root report of effluent
quality for different treatment systems now operating in the Gulf of
Mexico and similar data from other sources to identify an "exemplary"
abatement system. From the effluent samples the EPA structured a dis-
tribution of sample results from the exemplary treatment systems, as
shown in Table III-3 . While the Agency believes treatment systems will
produce effluent streams with a long-term average of 27 ppin of oil and
grease, the guideline is written in terms of the maximum value that 95%
of the averages of daily samples can have in any 30 days (48 ppm in 1977
and 30 ppm in 1983) and the maximum of 95% of the sample values during
any one day (72 ppm in 1977 and 52 ppm in 1983).
III-5
-------
TABLE III-3
DISTRIBUTION OF EFFLUENT SAMPLES FROM EXEMPLARY TREATMENT SYSTEMS
Long-Term Maximum for Averages Maximum of
Guidelines Average of Daily Values During 30 Days Values During One Day
1977 27 ppm 48 ppm (95% of Daily Averages) 72 ppm (95% of Daily Samples)
BPCTCA 57 ppm (99% of Daily Averages) 85 ppm (99% of Daily Samples)
1983 27 ppm 30 ppm (95% of Daily Averages) 52 ppm (95% of Daily Samples)
BATEA
SOURCE: U.S. Environmental Protection Agency
-------
This exemplary system was identified in the EPA's Draft Development
Document, but the guideline specifies the effluent quality the system
can achieve, not the system itself. If an offshore operator can achieve
the effluent standard with a less expensive treatment system, he is free
to do so.
The treatment system costs presented by EPA and updated by ADL are
the costs of installing and operating the exemplary system. Based upon
their analysis, the EPA has concluded that the exemplary treatment tech-
nology, separation by coalescence using flow equalization and dissolved
gas flotation, should be both the 1977 BPCTCA treatment system and the
1983 BATEA treatment system. The effluent limitations are specified
differently under the assumption that between 1977 and 1983 the operators
will be able to increase the performance of their facilities. This
assumption implies that the costs of complying with the 1977 and 1983
treatment requirements are identical. The operator in Federal waters
who installs the equipment in compliance with the 1977 standard has no
further capital cost as a result of the 1983 requirement. In state
waters, the operators will have to go to reinjection in 1983.
III-7
-------
III.2. CURRENT REGULATIONS
Offshore oil and gas operations are currently regulated by the con-
tiguous state in state waters and by the USGS in Federal waters.
The applicable USGS regulations for the Federal waters in the Gulf
of Mexico are the following:
Wastewater disposal systems shall be designed and main-
tained to reduce the oil content of the disposed water to an
average of not more than 50 ppm. . . On one day each mon." a, four
effluent samples shall be taken within a 24 hour period and
determination shall be made on the temperature, suspended
solids, settleable solids, pH, total oil content, and volumes
of sample obtained... No effluent containing an excess of oil
of 100 ppm of total oil content shall be discharged into the
Gulf of Mexico.
(PCS Orders 1 and 2, U.S. Dept. of the Interior,
USGS, 1969, pp. 8-6)
The applicable USGS regulations for the Pacific region are slightly
different:
(a) Water discharged shall not create conditions which
will adversely affect the public health or the use of the waters
for the propagation of aquatic life, recreation, navigation, or
other legitimate uses.
(b) Wastewater disposal systems shall be designed and
maintained to reduce the oil content of the disposed water to
not more than 50 ppm... On one day each month, the effluent
shall be sampled hourly for 8 hours and the following deter-
minations shall be made on the composite sample: suspended
solids, settleable solids, pH, total oil and grease content,
and volume of sample obtained. Also, the temperature of each
hourly sample shall be recorded.
-------
California State Waters
The California regulations applicable to offshore water disposal
from offshore oil and gas production are water quality regulations, as
opposed to uniform effluent quality regulations. The Regional Water
Quality Control Boards have the responsibility to establish rules to
protect underground and surface waters suitable for irrigation and domestic
purposes and the "best interests of the neighboring property owners and
the public" (California Laws for Conservation of Petroleum and Gas, 1973,
Resources Agency of California, Sacramento, Calif., 1973, p. 15).
Since many of the offshore producing areas are near public beaches
and recreation areas, the effluent standards which have been issued for
the platforms required treatment to 20 ppm long-term average of oil and
grease before discharge. Rather than treat to this level, most producers
are reinjecting their formation water.
Alaska State Waters
Specific information has not been obtained on the Alaska state
requirements for offshore formation water disposal.
Louisiana State Waters
Louisiana regulations of the offshore oil and gas platforms require
effluent to be treated to a long-term average of 30 ppm of oil and grease.
Texas State Waters
The Texas regulations of offshore oil and gas platforms call for the
issuance of permits for each platform based on the potential impact of
the effluent on the local water quality. Many of the permits which have
been issued have set the long-term average of oil and grease content in
the effluent stream as 25 ppm.
III-9
-------
III.3. COST OF POLLUTION ABATEMENT SYSTEMS
The investment and operating costs which are used in the economic
impact analysis were prepared by the EPA based upon the previously
referenced Brown & Root report. The EPA estimates, as presented in
their Draft Development Document , added to the Brown & Root costs the
additional costs of desanders and filters based on manufacturers' quotes
with an allowance for installation costs for system capacities of:
• 200 bbls/day of processed water
• 1,000 bbls/day of processed water
• 5,000 bbls/day of processed water
*• 10,000 bbls/day of processed water
• 40,000 bbls/day of processed water
The cost estimates were reviewed by ADL for consistency with the Brown
& Root estimates. Further, to allow for inflation between 1973 and 1974,
ADL multiplied the costs of all the treatment equipment by 1.24 using a
Nelson inflation index indicating an inflation of 24% for Miscellaneous
Equipment during that period. Estimates of operating costs had been made
as a percentage of the capital costs based on percentages specified in
the Brown & Root report. Consequently, operating costs were inflated by
24% as well.
EPA, October 1974: Draft Development Document for Effluent Limitations
Guidelines and New Source Performance Standards for the Oil and Gas
Extraction Point Source Category.
111-10
-------
The treatment systems considered to be the Best Practicable Control
Technology Currently Available (BPCTCA) were the following:
• Separation by coalescence, using flow equalization (surge
tanks), desanders and flotation, then discharge to surface water.
• Separation using flow equalization (surge tank), desanders and
filters with disposal by shallow well injection.
The EPA Draft Development Document presented energy requirements in
terms of annual costs only. To present these requirements in terms of
annual natural gas requirements, ADL calculated the horsepower require-
ments for the treatment equipment using Brown & Root's estimates and
expressed these horsepower requirements in terms of-MCF natural gas
equivalent. Horsepower requirements and resulting natural gas require-
ments for reinjection were calculated as well, using EPA's assumed average
depth for injection wells of 3,000 feet.
The derivation of these horsepower requirements are discussed in
Section 8, "Direct Energy Effectiveness of Treatment Equipment", of
Chapter VI. The energy costs were calculated for diesel oil at $10
per barrel and for gas at $0.50 per MCF. Comparing these costs shows
that energy costs will be about 3.5 times higher if diesel oil is used.
Throughout the analysis, the natural gas-based energy costs were used.
Table III- 4 summarizes the abatement costs.
In terms of BTU equivalents: 1 bbl of diesel oil = 6 MCF natural gas,
which @ $0.50/MCF would cost $3 or about 3.5 times less than 1 barrel
diesel oil of $10, when using end-1974 prices.
III-ll
-------
TABLE II1-4
POLLUTION ABATEMENT EQUIPMENT COSTS: OFFSHORE GULF OF MEXICO
(thousands of 1974 dollars per year)
(Energy costs based on natural gas @ $0.50/MCF)
Treatment '
Treatment0'' and Shallow Shallow Well
X3)
Treatment Technology Type
Maximum Capacity: 200 B/D
Inv. Costs: No extra space req'd.
Extra deck or platform (1)
Operating Costs
Energy Costs (2)
Max. Capacity: 1000 B/D
Inv. Costs: No extra space req'd.
Extra deek or platform
Operating Costs
Energy Costs
Maximum Capacity: 5000 B/D
Inv. Costs: No extra space req'd.
Extra deck or platform
Operating Costs
Energy Costs
Maximum Capacity: 10,000 B/D
Inv. Costs: No extra space req'd.
Extra deek or platform
Operating Costs
Energy Costs
Maximum Capacity: 40,000 B/D
Inv. Costs: No extra space req'd.
Extra deek or platform
Operating Costs
Energy Costs
'Extra deck space up to 1000 sq. ft.; extra platform space for area requirements larger than 1000 sq. ft.
Energy costs based on natural gas @ 0.50/MCF. ^BPCTCA in state & Federal waters. ^BATEA in state waters.
SOURCE: Brown & Root Inc., additions E.P.A. updating and inflation adjustment by ADL.
using Flota-
tion Unit
64.0
108.0
7.94
negl.
155.0
219.0
10.9
0.03
162.0
253.0
15.16
0.32
255.0
2016.0
23.97
0.63
555.0
2372.0
51.13
1.3
Well In-
jection
439.0
496.0
34.7
1.2
474.0
536.0
36.8
5.89
559.0
642.0
49.45
29.45
698.0
2445.0
64.65
58.9
1894.0
3876.0
111.05
117.8
Injection
Only
358.0
404.0
34.7
1.2
384.0
435.0
36.8
5.86
488.0
599.0
49.45
29.29
593.0
2340.0
64.65
58.6
1670.0
3340.0
111.05
117.2
-------
The EPA's estimates of the cost of drilling and equipping a 3,000
foot injection well in 1973 in the Gulf of Mexico were based on the
average cost of $200,000 for drilling and equipping an oil well in that
depth range.
These costs increased from 1973 to 1974 by 35.6% according to a
report by the Independent Petroleum Association of America's (IPAA) Cost
2
Study Committee. Using the IPAA index, the average cost of drilling and
equipping a 3,000 foot well was escalated to be $270,000 by ADL. The
maximum reinjection capacity of these wells was assumed to be 10,000
bbls/day based on the Brown & Root report. A 40,000 bbls/day reinjection
plant then would require four wells.
Estimates of the cost of the platform deck area required for addi-
tional treatment and injection facilities in the EPA report were also
based on Brown & Root's estimates. These estimates are applicable if an
additional deck is required because of a lack of space on the existing
platform and for situations where a new platform would be needed. Extra
space requirements exceeding 1,000 square feet were assumed by Brown &
Root to require a separate additional platform.
The economic impact analysis has assumed that all offshore production
units would need to install the additional treatment systems discussed
above. In reality, some production units will have treatment systems
capable of meeting the 1977 treatment standards. The EPA has made an
Joint Association Survey of the U.S. Oil and Gas Producing Industry,
Section I, Drilling Costs, 1973, American Petroleum Association, Feb. 1975.
2World Oil. Feb. 15, 1975.
111-13
-------
estimate of which types of technology are currently being used for treat-
ment of formation water produced in Louisiana Federal and state waters
(see Table III-5 ). According to their estimates, 24% of all the forma-
tion water produced in that offshore area is presently treated by flota-
tion systems, considered to be the "best practicable". It can also be
expected that not all of the other systems will have to be replaced by
flotation systems. Some of these systems, given favorable conditions,
will be able to meet the standards without any additional treatment
equipment. Other systems will require modification at a lesser cost
than the investment costs used in the impact analysis. It was not pos-
sible, however, to allow for all these factors in the analysis.
Therefore, the results of the analysis of the possible impact by the
new treatment standards in 1977 should be considered to present a high
cost estimate.
111-14
-------
TABLE II1-5
Distribution of Different Treatment Technologies
Currently Being Used Offshore Louisiana
in Federal and State Waters
Treatment
Technology
Pits and Sumps
Tanks
Plate
Flotation*
Filters
(2)
Volume of
Formation Water
As % of Total
% of Treated
% Needing Formation Water
New Units Needing New Units
32%
27%
9%
24%
8%
95%
90%
100%
0%
100%
30.4%
24.3%
9.0%
.0%
8.0%
100%
71.7%
(1)
<
(2)'
Source: by communication with the EPA.
I
Onshore treatment of offshore produced formation water.
Considered to be Best practicable technology.
111-15
-------
IV. IMPACT ASSESSMENT METHODOLOGY
IV.1. INTRODUCTION
This chapter describes the methodology whereby the economic impact
of requiring added offshore water treatment equipment and reinjection
facilities is assessed. As discussed in Chapter III, these
facilities are expected to be required to meet the EPA treatment standards
for 1977 and 1983 on offshore oil and gas producing installations.
Given the estimates of investment and operating costs for these
treatment and reinjection facilities discussed in the previous chapter,
and the estimates of the production economics prepared by ADL for the
offshore areas under analysis, the potential impact of these proposed
standards was evaluated in terms of:
• the loss of potential production due to premature abandon-
ment of production units in 1977 and 1983.
• the loss of potential production due to a decrease in
producing life of wells because of increased operating
costs.
• the total capital required for investment in treatment
and reinjection facilities.
• the average increase in costs per Bbl or MCF produced
resulting from additional investment and operating costs.
In order to cope with the uncertainty associated with various
factors in the analysis, "best estimates" of average values were made
and then tested to determine the effects on results of possible values around
this average by varying one parameter at a time. The results of the
IV-1
-------
analysis are presented as a range of possible values rather than as point
estimates.
It was not attempted to present future trends in costs and prices
for the period considered. However, the results of the analysis do
allow one to deduce how the estimated impact will change when costs
and prices will change relative to the levels assumed for the analysis
using 1974 cost levels and a range of prices.
IV-2
-------
IV.2. GENERAL APPROACH
2.1. Producers Absorb All Costs
If he has to absorb all additional investment and operating costs
in 1977 the operator of a production unit in Federal waters which
does not conform to the new standard will have to evaluate the following
alternatives:
• He can shut the operations of his production unit, or
• He can invest in treatment facilities required for
compliance with the 1977 standards.
The operator's decision to abandon his production unit or to
invest in these treatment facilities will likely be based on an estimate
as to whether or not production over the unit's remaining life will pay
for the investment. The estimate of the remaining producing life of the
unit will be based on a comparison of operating costs per unit produced
with revenue per unit produced.
The operator of a production unit in state waters in 1977 will
be faced with a larger number of possible decisions. He will have to
evaluate the following alternatives: (Table IV-1)
• He can shut down the operations of his production unit, or
• He can invest in facilities required for compliance with
1977 standards and delay until 1983 his decision whether
to invest in reinjection facilities, or
• He can invest in reinjection facilities immediately.
A production unit consists of one or more platforms each accommo-
dating gas and/or oil production from generally 5-20 wells, which is
treated to separate the oil, water,and gas before oil and/or gas
are transported to shore by pipeline.
IV-3
-------
TABLE IV-1
Possible Alternative Outcomes of an Investment Analysis
in New Treatment Facilities in 1977 for a
Production Unit in State Waters
Possible Outcome Of
Investment Analysis
Action In
Year Of Required Investment
1977 1983
Remaining production
will not pay for any
additional investment.
Remaining producing
life falls short of
1983.
Remaining production
will pay out invest-
ment in treatment
facilities only.
It is cheaper to
invest first in
treatment facil-
ities and then
in additional
injection facil-
ities.
It is cheaper to invest
in reinjection facilities
immediately.
Shut-in
Invest in treatment
Invest in treatment
No investment required
No investment required
Shut-in
Invest in treatment
Invest in reinjection
Invest in reinjection No investment required
IV-4
-------
To determine which alternative he should choose, the operator
will first have to establish whether and to what extent the remaining
producing life of the production unit will extend beyond 1983.
If the producing life does indeed extend beyond 1983, the operator
will then have to compare the net present values of the following cash
flows:
• First, the cash flow resulting from an investment in 1977
followed by another investment in 1983 and extending
over the producing life, where the producing life has
been estimated allowing for additional operating costs,
first for the new treatment facilities and later in 1983
for the injection facilities;
• Second, the cash flow resulting from an investment in
1977 in reinjection facilities and extending over the
estimated remaining producing life, which will be
shorter because of the additional operating costs for
the injection facilities.
IV-5
-------
He will choose that alternative which produces the highest net present
value of after-tax cash flow less the net present values of investments required.
If the expected producing life of the production unit falls short of
1983, the operator will simply decide whether to invest in facilities, which
are required to comply with the 1977 standards. He can be expected to shut
down his production unit in 1977 if he concludes that the investment in the
least expensive type of equipment, which will meet the EPA standards, will not
be paid for by the present value of after-tax revenues from the unit's
expected remaining production.
He will have to shut down in 1983 thereby foregoing some potential
production if his analysis shows that the producing life will indeed extend
beyond 1983, but that only the less expensive investment in treatment facilities,
required for compliance with 1977 standards, will be paid for.
The analysis which is presented on the following pages is based on
the assumption that all operators of production .units in state waters will appply
the above rationale in 1977 when deciding how to comply with the new standards.
The analysis then evaluates the loss of potential oil production, which can be
expected from:
• Immediate platform shut-downs in 1977 in state and federal
waters,
• Platform shut-downs in 1983 in state waters and
• A decrease in the producing life of those platforms in
state and federal waters which will not be shut down in 1977 or
1983, but whose ultimate productive lifetime will be foreshortened
by increased operating costs.
IV-6
-------
The analysis, using the decision rules described above, represents
a simplification of what may happen in reality. In the first place, many
individual operators have economic criteria different from the criteria
described above. In the second place, the decision to shut down a produc-
tion unit in a field will also have to consider the effect that the shut-
down may have on production from other units in the field, since shutdown
of a unit can be expected to change the field's production character-
istics.
2.2. Producers Pass On All Costs
It might well be that producers in federal waters will be able to
pass on some of the additional costs for treatment and reinjection facilities
by increasing their prices for oil and gas. Therefore a likely range
of the increase in average cost per Bbl or MCF produced, was calculated
assuming the following:
• Producers would like to recover their investment in facilities,
including a return on that investment within 15 years.
• The cost increase should reflect the increase in average after
tax cost levels over a period of fifteen years, allowing for
increases in depreciation charges.
The calculations used projections of aggregated oil and gas production
for the period of 15 years following 1977 and 1983 plus estimates of total
investment required in treatment and reinjection facilities, thus disregarding
differences between individual operators and individual production units.
IV-7
-------
IV.3. PRODUCTION ECONOMICS
The operating costs and investment costs used in the analysis were
derived from the estimates made for a model unit described in the Bureau of
Mines (BOM) Information Circular IC-8557. This model, as mentioned in the BOM
report, was intended to show "... the costs involved in exploring, acquiring,
developing, producing and abandoning a typical production unit in the Gulf of
Mexico." As such it presented a basis for estimating the investment and
operating costs of such a typical unit, which then was tested with the industry
and adjusted to allow for differences between the BOM model production unit and
the actual production units which were considered in this analysis.
3.1. The Bureau of Mines Model Production Unit
The model production unit consisted of three platforms, one main
platform with 12 wells, where most of the processing of oil, water and gas is
done and two satellite platforms each with 8 wells, where the processing is
limited to two-stage separation (See Figure IV-2).
IV-8
-------
LEGEND
• Oil wtll, dual
6o» and 0,1
Plotform
:»
44-^1
Plofform 8
'* *^
6i i ' '
v».vV
,0
*'' >'
o
Platform B
Platform A
8 Oil pipclint — *-
p
-
I
pipeline I
I
To >al«i
FIGURE IV-1 Lease Plat Showing Platforms, Wells, and Flow Lines in Model.
SOURCE: Bureau of Mines Circular 1C 8557/1972
IV-9
-------
DI
jo neajng
031X3^ JO j|nrj D JO
UOIpnpOJJ JO 9UJ3L|D5
Z~AI
O
-------
Most of the wells have more than one completion and as a result, a
total of 45 completions are producing oil and gas in the years of peak
production. The processing equipment on the platforms is sized to handle oil
and condensate production of 10,000 B/D and a peak gas production of 48 million
cubic feet/day.
Processing on the main platform consists of: three-phase separation
of natural gas, condensate and water; dehydration of the gas to sales
specification; water treatment and disposal; storage and transfer of oil
(See Figure IV-2). Note that the treatment technologies, which are considered
in this analysis have to be added to this processing equipment.
3.2. Operating Costs
Annual operating costs calculated in the BOM model consisted of the
following items:
Direct Costs
• labor costs,
• supervision,
• payroll overhead,
0 food expense,
• labor transport costs,
o surface equipment maintenance,
• workover expense,
• radio and telephone costs.
Interest and Fixed Costs
• administration and general overhead,
• insurance.
IV-11
-------
The estimates of these cost elements, expressed in 1974 dollars, are
shown in Table IV-2. They differ considerably from BOM estimated costs due
to changes in operating procedures and inflation.
Operating Costs Per Unit Produced Per Completion
The estimates of annual operating costs had to be put on a common
basis before they could be applied to the production units considered in the
analysis.
For analytical purposes, the average daily productivity per producing
completion at each stage of the producing life of the production unit was
chosen because the data base specified productivity by completion and not by
well.
IV-12
-------
TABLE IV-2
SAMPLE OPERATING COSTS
3 Platforms, 28 Wells, 45 Completions
Assuming shifts of 7 days on and 7 days off
DIRECT COSTS
1. LABOR
Contract Labor
1 Cook, 6.50 $/hr. x 12 h/d x 365 $28,470
1 Cook's Helper 6.00 x 12 x 365 26,280
1 Gang Leaderman 8.00 x 12 x 365 35,040
2 Roustabouts 6.50 x 12 x 365 56,940
1 Pumper 8.00 x 12 x 365 35,040
1 Electrician-Mechanic 12.50 x 12 x 365 54,750
Sub-Total Contract (Overhead Included) $236,520
Company Labor
2 Plant Operators @ $16,000/yr $32,000
Vacation Relief 3 wk/man x 6 x 16,000 1,846
52
Sub-Total Plant Operators $33,846
TOTAL LABOR $270,366
2. SUPERVISION
1 Foreman @ $20,000/yr $20,000
Vacation Relief 3 wk x 20,000 1,154
52
TOTAL SUPERVISION $ 21,154
3. PAYROLL OVERHEAD
$33,846 + $21,154 x .25 $ 13,750
4. FOOD EXPENSE
15 $/d x 9 x 1.15 (15% for special labor crews) x 365 $ 56,666
5. TRANSPORTATION—Labor, Equipment & Supplies
Assumes company has no adjacent or close-by field operations
Boats
1/2 Shore to Field, combination personnel & supply
475 $/d x 365 ' $86,687
1/2 Standby and Field transportation boat
450 $/d x 365 82,125
Sub-Total Boats $168,812
Source: ADL estimates based on information from industry sources.
IV-13
-------
TABLE IV-2 - Continued
Helicopter—To assure availability and reduce cost, helicopters are contracted
on a monthly basis.
Schedule: 6 hrs/wk for crew changes x 52 = 312 hr/yr
4 hrs/day for transportation of special crews x 1.5 days/wk
x 52 = 312 hr/yr
Special Crews: Contract personnel, wireline, machinery maintenance,
equipment modifications, painting, etc. Also flights
for hauling small equipment and parts for repair.
Monthly Avg. - 312^_312 = 52 hr/mo
Base Rental 1/2 x 8,500 $/mo x 12 = $51,000
52 hr/mo x $60 x 12 = 37.440
Sub-Total Helicopter $88,440
TOTAL TRANSPORTATION $257,252
6. SURFACE EQUIPMENT MAINTENANCE
0.05 x $2,419,800 (Production equipment cost) $120,990
7. OPERATING SUPPLIES
0.20 x $120,990 $ 24,198
8. WORKOVER EXPENSE $410,000
Over life of field:
15 Major Workovers @ 500,000 = $7,500,000
20 Minor Workovers @ 10,000 200,000
$25,000/yr wireline work x 20 yr 500,000
$8,200,000
=$410,000/yr
9. RADIO & TELEPHONE $ 10.335
10. TOTAL DIRECT COSTS $1,184,711
Source: ADL estimates based on information from industry sources.
IV-14
-------
TABLE IV-2 - Continued
INDIRECT COSTS
11. ADMINISTRATION & GENERAL OVERHEAD
.40 x (Co. Plant Operators + Line 2 and 7)
.40 x (33,846 + 21,154 + 24,198)
.40 x 79,360 = $ 31,744
FIXED COSTS
12 INSURANCE
283,500 (footage) x $1.41/ft + $221,665 (all risk) $621,400
TOTAL OPERATING COSTS, ANNUAL
(Excluding Depreciation) $1,837,855
Source: ADL estimates based on information from industry sources.
IV-15
-------
Total operating costs in a given year for a production unit with the
same number of completions as the model unit but with twice the average daily
productivity per completion will not be much different from the total operating
costs of the model unit. The only item which might be somewhat higher is
surface equipment maintenance (See Table IV-2).
If production unit has twice the number of completions, however,
operating costs can be expected to be much higher. Insurance and workover
expense, which (Table IV-2) together make up 56% of the operating costs,
would be twice as high and more labor will be required to operate the larger
number of wells.
Therefore in the analysis a linear relationship was used between the
number of completions and total operating costs for a production unit implying
that with twice the number of completion on a production unit operating costs
would be twice as high regardless the average completion productivity. As a
result operating costs per unit produced were assumed to be inversely related
with completion productivity, implying that a production units' per barrel or MCF
production costs would be twice as high, if average completion productivity
would be half and that per barrel or MCF production costs would be half as high
if completion productivity would be twice that of another production unit.
In order to establish the functional relationship between operating
costs per unit produced and completion productivity over time, a production
profile was calculated for the BOM model unit.
IV-16
-------
For these calculations it was assumed that the production profile
of each completion had a plateau of level production during the first four
years of the completion's life and declined at 15% per year during the
remaining life. This differed considerably from the production assumption
made in the BOM information ciruclar in 1972 wherein it was assumed that the
annual decline rate was close to 6% a year. This difference in decline rate
can be explained by the fact that since 1972 allowables have increased to the
extent that completions in federal waters in 1975 are produced at their
Maximum Efficient Rates.
The annual production resulting from these calculations is shown in
Table IV-3. Given the number of producing completions, total annual
production and total annual operating costs, the operating cost per barrel
produced and average completion productivity was calculated as shown in
Table IV-4. The relationship between cost per barrel produced and average
completion productivity is shown in Figure IV-3. The functional relationship
as shown in Figure IV-3 between operating costs per barrel produced and
average completion productivity was used throughout the analysis.
Levels of operating costs per completion for gas producing units
were assumed to be the same. Operating costs per completion within state
waters were estimated to be 10% lower on the average then operating costs with-
in federal waters, reflecting lower transportation costs for personnel and
materials.
IV-17
-------
TABLE IV-3
Calculation of Annual Production
for the BOM Model
Assuming a
No. of Compl. 9
Initial B/D 152
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
499.3
499.3
499.3
499.3
424.4
360.7
306.6
260.6
221.5
188.3
160.0
136.0
115.6
98.3
83.6
71.0
60.4
51.3
43.6
37.1
31.5
26.8
22.8
19.3
16.4
14.0
13
210
Production Unit,
15% Annual Decline Rate
8
240
6
182
4
154
Hi)
3
91
2
102
Annual Production Thousand bls/yr
996.4
996.4 700.8
996.4 700.8 398.6
996.4
847.0
720.0
612.0
520.1
442.1
375.8
319.4
271.5
230.8
196.2
166.7
141.7
120.5
102.4
87,0
74.0
62.9
53.5
45.4
38.6
32.8
700.8
700.8
595.7
506.3
430.4
365.8
310.9
264.3
224.7
190.9
162.3
138.0
117.3
99.7
84.7
72.0
61.2
52.0
44.2
37.5
32.0
27.2
398.6
398.6
398.6
338.8
288.0
245.0
208.1
176.8
150.3
127.8
108.6
92.3
78.5
66.7
56.7
48.2
40.9
34.8
29.6
25.2
21.4
18.2
224.8
224.8
224.8
224.8
191.1
162.4
138.1
117.4
99.8
84.8
72.1
61.3
52.1
44.3
37.6
32.0
27.2
23.1
19.6
16.7
14.2
12.1
99.6
99.6
99.6
99.6
84.7
72.0
61.2
52.0
44.2
37.6
31.9
27.1
23.1
19.6
16.7
14.2
12.0
10.2
8.7
7.4
6.3
75.0
75.0
75.0
75.0
63.7
54.2
46.1
39.2
33.3
28.3
24.0
20.4
17.4
14.8
12.6
10.7
9.1
7.7
6.6
5.6
Total
499.3
1495.8
2196.6
2595.2
2745.1
2631.6
2430.3
2117.2
1825.8
1563.2
1328.7
1129.4
960.0
816.0
693.6
589.5
501.1
426.0
362.1
307.7
261.6
222.3
189.0
160.6
136.5
116.2
(1) Number of completions and their initial productivity were
obtained from the BOM Model production unit discussed in
1C 8557/1972.
IV-18
-------
TABLE IV-4
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Calculation of Operating Costs in $/B and
B/D per Completion
B/Yr $/Yr
thousand bis thousand US$ $/B
499.3 367.6 .74
1495.8 898.5 .60
2196.6 1225.2 .56
2595.2 1470.2 .57
2745.1 1633.6 .59
2631.6 1756.1 .67
2430.3 1837.8 .76
2117.2 18.
1825.8
1563.2
1328.7
1129.4
960.0
816.0
693.6
589.5
501.1
426.0
362.1
307.7
261.6
222.3
189.0
160.6
37.8 .87
1.01
1.17
1.38
1.63
1.91
2.25
2.65
3.12
3.67
4.31
5.07
5.97
7.02
8.27
9.72
11.44
136.5 T 13.46
B/Comp.
152
186
200
237
209
180
155
129
111
95
81
69
58
50
42
36
30
26
22
19
16
13
11
10
8
(1)
Bis/completion
IV-19
-------
FIGURE iy-3
Operating Costs (in $/B) Versus
Average Completion Productivity
20
40
60 80 100
200
400
600
1000
Average Completion Productivity (B/D) —• < \ >
IV-20
-------
3.3. Investment Costs
Estimates of investment costs, which were required for the calculation
of depreciation charges, were again derive^ from the BOM model. In this case
the costs were not updated to allow for inflationary trends between 1969 and
1974 because most (about 75%) of existing platforms in the Louisiana OCS area
(See Figure IV-4) are more than five years old and because we want to know what
the past actual costs were for depreciation purposes.
Figure IV-5 shows what estimates were used for investment costs for
production units which consisted respectively of 1 platform, 2 platforms or
3 platforms. Allowance was made in these estimates for an increase in costs
with an increasing maximum capacity of the processing equipment.
In the calculation of depreciation charges corrections were made to
allow for the fact that the production units considered in the analysis
differed in size from the model production unit and that part of the investment
had already been depreciated over the past life of these units.
IV- 21
-------
// Platforms
AGE DISTRIBUTION ON PLATFORMS IN LOUISIANA GULF COAST (Federal and State Waters)
Note: 1974 total based on statistics for first 6 months of 1974.
52
48 ._ •_ . -
44
40
36
30
28
N3
20 — r
16
12
1935 1937 1939 1947 1943 1945 1947 1949 1951
Source: ADL
953 1955 1957 199 1961 1963 1965 1967
-------
"7 —••
10
20
30
IV-23
-------
IV.4. AFTER TAX CASH FLOWS FOR EACH PRODUCTION UNIT
The annual after-tax cash flows, which were needed for the present
value analysis of the investments required for the new water treatment
and/or injection facilities, were calculated in the following manner:
In the case that taxable income was positive:
Annual after-tax cash flows = gross revenue - royalty payments -
operating costs - taxes
In the case that taxable income was zero or negative:
Annual after tax cash flows = gross revenue - royalty payments -
operating costs.
• Gross Revenue = Annual Production of Oil x Wellhead Price +
Annual Production of Gas x FPC Gas Ceiling
Price (50C/MCF)
• Royalties = 16.7% of Gross Revenues
• Operating costs were calculated as described in the previous
section
• Taxes =48% of Taxable Income
IV-24
-------
• Taxable Income= Gross Revenues - Royalties - Operating Costs -
Depreciation
• Annual depreciation charges were calculated using the unit of
production method (1)
IV.5 NO ALLOWANCE FOR COSTS OF TRANSPORTING OIL AND GAS ONSHORE
The impact analysis was performed, assuming a wellhead price for oil as
well as for gas. This assumption can be criticized as being artificial in the
case of oil, where the producing company usually co-owns and co-operates the
pipeline to the point of sale onshore, thus incurring additional costs.
It was not possible to find a cost formula which would reflect the
considerable differences in transportation charges for the different production
units. These differences are the result of differences in distances, different
volumes transported and use of one pipeline for several production units. Also,
it was felt that the pipeline costs would not play an important role in the
decision of an operator to continue to produce a certain production unit or not.
(1) The unit of production method requires estimates of the total cumulative
production, QCUM, over the life of the production unit and calculates an
annual depreciation factor, DEPF, by dividing total investment, TI, by this
cumulative production:
DEPF = TI/QCUM
Annual depreciation charges, DCHARGE, are then calculated by multiplication
of the annual production, Q , by this factor:
DCHARGE = DEPF^' Q
IV-2 5
-------
Since most pipelinesusually transport the production of more than one production
unit.
The wellhead price used in the analysis therefore should be considered
as representing the price which the operator would get at the point of sale
decreased by the transportation costs between the production unit and that
point of sale.
The results of the impact analysis have been tested for their sensi-
tivity to changes in this "wellhead" price. Given the range — from $5.25 to
$11.00 — over which this "wellhead" price was changed in these sensitivity
tests, it can be assumed that any error by not allowing for a transportation
charge in the base case price of $7.50 lays well within the range of results
obtained by these sensitivity tests.
IV-26
-------
IV.6. COMPUTER PROGRAM
A computer program was developed to facilitate the calculations for
the numerous cases which needed to be evaluated.
The same program could be used for the impact analysis in state
waters and federal waters, in spite of a considerable difference in the
complexity- of the analysis required for those areas.
The general flow diagram presenting the different steps in the
calculations required for the federal waters and state waters are shown in
Figure IV-6 and Figure IV- 7 respectively. The program first reads the
data for a leaseblock, which consist of information on:
• the number of producing completions
• the number of platforms
o the total daily production of (1) oil, associated gas and water
or (2) gas, condensate and water.
Then the economic life is calculated for that leaseblock, using a parameter
value for the annual decline rate and the future crude oil or gas price.
The operating cost function, described in the previous pages, is
used to calculate the average annual per-barrel (or per-MCF) operating
cost, which then is used to determine the number of years over which the produc-
tion will decline until these per-barrel operating costs equate the going
"price" per barrel of crude or per MCF of gas.
Annual production volumes of oil and gas in 1977 are projected and
the average capacity for water treatment facilities on the production units
in the leaseblock are calculated. Based on that capacity estimate, invest-
ment costs and annual operating costs are estimated for these treatment
systems.
IV-27
-------
READ
INPUT
DATA
FIGURE IV-6
Computer Flow Diagram
Federal Waters
NEXT LEASE BLOCK 1974 DATA
CALC. NUMBER OF PROD. UNITS
CALC. ECONOMIC LIFE WITHOUT
ADD. OPERATING COSTS
OIL
AND
GAS
PROD.
IN
1977
CALC. CAPACITY REQUIRED FOR
WATER TREATMENT SYSTEM
CALC. CAPITAL AND ANNUAL
OPERATING COSTS FOR TREATMENT SYSTEM
CALC. ECONOMIC LIFE WITH
ADD. OPERATING COSTS
FOR THIS YEAR:
CALC. PROD., AFTER TAX CASHFLOW
WITH AND WITHOUT TREATMENT COSTS
CALC. LOSS IN AFTER TAX
CASHFLOW DUE TO ADDED OPERATING COSTS
FOR YEAR OF INVESTMENT (1977):
CALC. PV (AT* CASHFLOW)
END OF PRODUCING LIFE?
|R THIS YEAR CALC.
OIL, GAS, WATER PROD.
GROSS REVENUE FROM SALES
ROYALTY PAYMENTS
WORKING INTEREST ( = 2 - 3)
OPERATING COSTS
DEPRECIATION ALLOWANCE
TAXABLE INCOME (=4-5-6)
FEDERAL INCOME TAXES (FIT)
AFTER TAX INCOME (=7-8)
0. AFTER TAX CASHFLOW
4-5-8)
CALC. LOSS IN
POT. PROD. DUE
TO ABANDONMENT
IN 1977
NO
[
PV (AT CASHFLOW)
LARGER THAN INVESTMENT?
YES ^
CALC. LOSS IN POT. PROD.
DUE TO DECREASE IN PROD.
LIFE
.1
STORE INFO. ON
LOSS IN POT. PROD.
NUMBER OF COMPLE-
TIONS ABANDONED
STORE INFO. ON INVESTMENT,
LOSS IN POT. PROD.,
LOSS IN AT CASHFLOW.
*AT= After Tax
IV-28
-------
FIGURE IV-7
Computer Flow Diagram
State Waters
NEXT LL/CL bl-
197« DATA
CAIC. ECONOMIC LITE ML
WITHOUT ADD. OPERATING CCSTS
INVEST IN TREATMENT
EOUIPMENT IN 1977
IN 1977
•EXHJECTION IN 1983
CALC. FOR 1977:
HPVO • FV I AT CASHFLOW»
PV (INVESTMENT)
one.
»FV1
- PV
TV
TO* 1977:
[AT C&SKrtOWl-
(IUVZSTMEVT)
THEATXEST 1^ 19
CALC.
•TO -
FV
PV
FOR 1917:
(AT CASHFLOW! -
(IJIVESTKENT!
tcaaicnm IN 19T7
CALC.
BPV3 - PV
PV
FOR 1977:
(AT CASHFLQW1-
(INVESTKEVT)
SELTCT THE STPJ-.TLCV WIT
THE HICItEST fcPV
Will. OEVCSTKT.T BE PJLED FOR?
WV/0?
CALC. FOR THIS
LEASE BLOCK:
LOSS IN POT. PROD. DUE
TO fc&ANOONMEHT I« 1977
STKAZECY 3'
STBATECY 27
CALCW>TE:
I. LOSS in POT. PROD.
CLE TO DECPEASE IN
PROD. LIFE.
2. LOSS IM AT*CASHFLOW
DUE TO ADD. OPERATING
COSTS.
3. INVESTMENT IN 1977
STOKE 1. 2, And 3
CALCULATE:
l. LOSS ir; POT. ?ROD.
DIE TO SFCREASE IN
2. LOiS If* AT CASHFLOW
DUE TO ADD. OPERATING
COSTS.
3. INVCSTRCNT IN 1977
STORE I. 3, and )
ISTUATECY 1? I
CALCULATE:
lOf.S f; POT. PROD.
OL'E TO Cr CRKASC IN
P«OO. LIFE.
LOSS IN AT CASHFLOW
DUE TO A.OO. OPFRATINC
COSTS.
INVLST«C*JT IN 1977
STcnr i. 2. «nd l
^ I ALL Ll.^c!^
I FRJWT On< I'T IftMI.. s I
1
"AT- After T«*
-------
Adding the annual treatment cost to existing operating cost levels
the economic life of the leaseblock is again calculated and the decrease in
that economic life by the added operating costs is established.
To determine whether the investment will be paid for by the remaining
production the annual after tax cashflow is calculated for each of the
remaining years post 1977. If the present value of that after tax cash
flow happens to be smaller than the investment required in 1977, then the
loss in potential production due to early abandonment of the leaseblocks'
production units is calculated. Otherwise the loss in potential production
due to a decrease in the leaseblocks' producing life is calculated and is
stored together with the information on the required investment. When all
leaseblocks have been analyzed, output tables are printed out which show the
total annual production foregone for all leaseblocks by either early
abandonments in 1977 or by decreases in the producing life, plus information
on the total investment required in 1977.
For state waters the analysis performed by the program is
more complicated because of the reinjection requirement in 1983. Using
the same criteria as in federal waters, three possible investment strategies
are evaluated and compared.
First, however, it is determined whether the producing life of the
leaseblock extends beyond 1983. If this turns out not to be the case, then
the investment in treatment in 1977 is evaluated in exactly the same manner
as described above for federal waters.
If the producing life of the leaseblock extends beyond 1983, then
the after tax cashflows of the following three strategies are calculated
(See Figure IV-8):
IV-30
-------
• Investment in treatment systems in 1977 and in reinjection
system in 1983 (Strategy 1)
• Investment in treatment system in 1977 and abandonment in
1983 (Strategy 2)
• Investment in reinjection in 1977 (Strategy 3).
Having calculated the investment requirements and present values of net
after tax cash flows for these three different strategies, the strategy with the
highest net present value is selected. For that strategy the loss in potential
production is calculated and stored together with the investment for 1977
and 1983.
When all leaseblocks have been evaluated in this manner, the following
information is printed out:
• Total annual loss in potential production of oil and associated
gas and condensate by either early abandonments in 1977 and 1983
or by the decrease in producing life of production units.
• Cumulative total of potential production lost.
• Annual potential production and cumulative total potential
production.
• Maximum annual water production and cumulative total water
production.
• Total investment in 1977 and 1983.
• Percentage of total investment in 1977 in reinjection facilities.
• Average annual operating costs per barrel or per MCF produced
and average addition to operating costs per unit produced due to
treatment and/or reinjection.
The period covered in the analysis extended up to the year 2000.
IV-31
-------
V. ANALYSIS OF THE DATA BASE
V.I. INTRODUCTION
In the following sections the available data are analyzed to
justify certain generalizations which were made for the impact analysis
applying the methodology described in the previous chapter.
V.2.. GEOGRAPHICAL SEGMENTATION OF OFFSHORE OIL AND GAS PRODUCTION
Offshore oil and gas production is located in three
geographical areas: California, Alaska's Cook Inlet and the Gulf of
Mexico. (See Table V-l.)
The potential impact on California offshore oil and gas production
has not been analyzed in this study since an estimated 95% of the brine
produced offshore is thought to be reinjected as required by the 1983
standard. The potential impact for bringing the remaining 5% in compliance
is considered to be small.
Cook Inlet crude/condensate production was 11.5% of total U.S.
offshore crude and condensate production and 1.7% of total U.S. onshore and
offshore production in 1974. Gas production in Cook Inlet was only 1.7%
of total offshore and 0.3% of total U.S. production. None of the
approximately 13.6 million barrels of water produced annually in Cook
Inlet is reinjected at present. At present most of the water from 14
oil producing platforms is piped ashore for processing and discharge
into the Inlet.
V-l
-------
TABLE V-l
Average Daily U.S. Offshore
Oil and Lease CondeRsate Production
in 1974 (1)
Federal
State
Total
Oil Gas Oil Gas Oil G*-
MB/D MMCF/D MB/D MMCF/D MB/D !^MCF/D
% of U.S. % or U.S.
Offshore Total (2)
Oil Gas Oil Gas
California
Alaska
Louisiana
Texas
Total
47
0
938
4
989
15
0
9122
439
9576
177
153
13
1
344
68
200
1485
258
2011
224
153
951
5
1333
83
200
10607
697
11587
16.8 0.7 2.5 0.1
11.5 1.7 1.7 0.3
71.3 91.5 10.7 17.7
0.4 6.1 0.06 1.2
100. 100. 14.96 19.3
(1) Source: "Outer Continental Shelf Statistics, 1953-1974",
U.S. Department of the Interior, Geological Survey-
Conservation Division, June 1975.
(2) Total average daily production in the U.S. in 1974 was 8849 MB/D oil and
lease condensate and 60,000 MMCF/D gas.
V-2
-------
The Gulf of Mexico is the area of greatest offshore oil and gas
production. Offshore Louisiana and Texas produced 72% of the U.S. offshore
total oil and condensate and 11% of total U.S. onshore and offshore oil and
condensate production in 1974. Total gas production was 92% of U.S. offshore
and 18% of total U.S. onshore and offshore production. Gulf waters are
further divided into the operations conducted in state waters (out to the
three mile limit) and those conducted in Federal waters. Texas state and
Federal waters account for,0.7% of total Gulf crude oil and condensate
production and 4.2% of gas production with about half of the oil and all
of the gas coming from the Federal domain. Louisiana state and Federal
waters account for more than 99% of total Gulf crude/condensate production
and about 94% of total Gulf gas. Eighty-seven percent of the Louisiana oil
and 85% of the gas is from Federal waters.
The division between Gulf state and Federal waters is germane to the
impact analysis because E.P.A.'s proposed regulations discern between
production from state and Federal waters.
V-3
-------
V.3 SOURCE OF DATA AND GENERALIZATIONS USED IN THE ANALYSIS
3.1. Introduction
ADL does not have access to proprietary production and cost data
for all production units in offshore areas. Thus it became necessary to
make several generalizations before the available data could be used for the
analysis.
The data sources available for the purpose of the analysis were the
following:
• "Approved Maximum Efficient Rates for Reservoirs and Maximum
Production Rates for Well Completions," October 1974; the
United States Department of the Interior, Geological Sruvey,
Conservation Division, Gulf of Mexico Area O.C.S.
• "Summary Production Report of Oil, Gas, Water by O.C.S. Leases
and State Leases with U.S.G.S. Participation in Units from
Monthly Report of Operations (9-152) for Producing Leases,
June 1974;" United States Department of the Interior, Geological
Survey, Conservation Division, Gulf of Mexico Area - O.C.S.
• "Offshore Petroleum Studies. Composition of the Offshore United
States Petroleum Industry and Estimation of Costs of Producing
Petroleum in the Gulf of Mexico;" Bureau of Mines Information
Circular IC-8557, 1972.
• "Draft Development Document for Effluent Limitations, Guidelines
and New Source Performance Standards for the Oil and Gas
Extraction Point Source Category;" United States Environmental
Protection Agency, October 1974.
V-4
-------
• A list with multi-well platforms in the OCS area of the Gulf of
Mexico obtained from the Offshore Oil Scouts Association,
New Orleans, Louisiana.
• "Statistical Report for the Year 1973," State of Alaska Department
of Natural Resources, Division of Oil and Gas, Anchorage, Alaska.
• "Production and Proration Order;" State of Louisiana, Department of
Conservation, New Orleans, Louisiana, December 20, 1974.
o Personal Communication with EPA and oil industry sources.
Based on this information, estimates were made of:
• The size and number of production units present in offshore areas,
• The annual volumes of oil, gas and water produced from each of
these production units and the decline rates of the annual
production,
3.2 The Size and Number of Production Units Present in Offshore Areas
Table V-2 shows the numbers of platforms which were considered in
the analysis as compared with the actual number of platforms present in 1974
in the federal and state waters of the Gulf of Mexico and in the state waters
of Alaska. The sample of platforms used to estimate the possible impact in
the federal waters of the Gulf of Mexico was so large (>90%) that it can
safely be assumed that the results of the impact analysis based on that sample
apply to the total population of platforms in the federal waters.
In leaseblocks with more than one platform, it was necessary to make an
assumption of how these platforms were divided over various production units.
Some production units consist of more than one platform and in such cases one
platform will be the main processing platform where all the oil, water and
gas produced by the other platforms will be separated and treated. It is
V-5
-------
TABLE V-2
Number of Oil and Gas Platforms Considered and Total
Number of Platforms Present in Offshore Areas
State and Federal Waters
Louisiana
Texas
Gulf of Mexico
California
Alaska
Actual
Considered
Actual
Considered
Actual
Considered
Actual
Considered
Actual
Considered
Multi Well
644
581
23
20
667
601
22
none
14
14
Single Well
1858
1216
115
none
1973
1216
none
none
none
none
Based on 1973 data for Alaska and 1974 data for California and the
Gulf of Mexico.
V-6
-------
assumed that for such multi-platform production units the additional water
treatment facilities required in 1977 will be located on these main processing
platforms as well.
The number of applications for discharge permits filed by offshore
operators with the EPA provides an indication of the actual number of treatment
facilities in the Gulf of Mexico federal waters. By October, 1974 there had
been 327 applications for the Louisiana O.C.S. area. Based
on the distribution shown in Table V-3 and since there is no reason to assume
that operators in different lease blocks will or even can combine platforms
for water treatment or reinjection purposes, it was assumed that typical
production units consist of one platform. The effect of assuming that a
production unit consisted of three platforms was also evaluated.
V-7
-------
TABLE V-3
Gulf of Mexico, Federal Waters ,
(2)
Distribution of Multi-Well Oil and Gas Producing Platforms
Over Leaseblocks
Type cf Platform
Number of Platforms
per Leaseblock
1
2
3
4
5
6
7
8
9
Total Platforms
Oil
Gas
Number of Platforms
in Each Category:
111
44
25
14
7
6
2
2
1
112
18
3
1
none
none
none
none
none
440
601
(1)
Including Louisiana and Texas federal waters.
(2)
Platforms considered in the analysis - Refer to Table III-3.
V-8
-------
3.3 Estimates of the Annual Volumes of Oil, Gas and Water Produced and
Estimates of the Annual Production Decline Rates
For the Gulf of Mexico area information was available on total volumes
of oil, gas, condensate and water produced in each leaseblock for the month
of June 1974. Tables V-4 and V-5 were developed from this information to obtain
an idea of the distribution of different water/oil and water/gas ratios for
existing platforms in the Gulf of Mexico federal waters. The tables show
how the number of platforms with daily oil or gas production in a given range
are distributed over various ranges of water produced with that oil or gas. The
ranges for gas and oil production respectively have been chosen to be the same
(2)
on a thermal equivalence basis, so as to allow comparison of the distribution
of water oil ratios for oil producing platforms with the water gas ratios of
gas producing platforms.
Figure V-l, which shows the cumulative distributions of oil, gas,
and water production from oil and gas producing platforms, suggests
the following conclusions:
• Total gas production per platform is consistently higher than
total oil production per platform, if measured on a Btu
equivalent basis. Of the total of 199 gas producing platforms
in a sample, 99 or 49.8% had a production of more than
12,000 MCF/D (= 2000 B/d).
Source: USGS, Summary Report of Oil, Gas, Water by DCS Leases and
State Leases for Producing Leases, June 1974.
(2)
1 Bbl crude oil - 5850 cu. ft. natural gas in terms of Btu equivalents.
V-9
-------
TABLE V-4
Louisiana Federal Waters
Number of Oil Producing Platforms Ranked by
Total Average
Average
Daily Oil
Production
per Plat-
form (B/D)
0-
20-
50-
100-
200-
500- 1,
1,000- 2,
2,000- 5,
5,000-10,
10,000-15,
15,000-20,
TOTAL
% of Total
Average
0- 20-
20 50
20 2
50
100 7 1
200 9 3
500 16 7
000 9 5
000 10 13
000 10 6
000 3
000 1
000
67 35
15.2 7.9
Daily
50-
100
1
2
1
4
5
1
4
18
4.1
Daily Oil and Total Daily Water Production
Water Production per Platform (B/D)
100- 200- 500- 1,000- 2,000- 5,000-
200 500 1,000 2,000 5,000 10,000
1
1 1
2 2
112 2
7 11 4 2 1
15 18 6 11
39 26 31 16 5 2
13 9 23 16 23 5
2 12 9
1
5
84 68 68 48 40 8
19.1 15.5 15.5 10.9 9.1 1.8
(1)
10,000-
15,000 Total
4
2
12
20
49
59
147
106
4 34
2
5
4 440
0.9
Cum.
% of
Total
0.9
1.4
4.1
8.6
19,7
33.1
66.6
90.7
98-4
98-9
100%
Cumulative 23.1 27.2 46.3 61.8 77.3 88.2 97.3 99.1
(1) Sources: U.S.G.S. Conservation Division, Gulf of Mexico Area, O.C.S.:
1. Approved Maximum Production Rates for Well Completions, October 1, 1974
2. Summary Production Report of Oil, Gas, Water by O.C.S. Leases, June 1974
Oil Scouts Association:
Platforms in O.C.S. Leases, June 1974
V-10
-------
TABLE V-5
Louisiana Federal Waters
Number of Gas Producing Platforms Ranked by ,--,-,
Total Average
Average
Daily Gas
Production
per Platform
(MCF/day)
0-120
120-300
300-600
600-1200
1200-3000
3000-6000
6000-12,000
12,000-30,000
30,000-60,000
60,000-90,000
90,000-120,000
120,000-180,000
180,000-240,000
> 240, 000
TOTAL
% of Total
Cumulative
0-
20
3
4
1
1
17
24
20
24
9
5
1
2
1
112
56.4
Average
20- 50-
50 100
1
1
1
1 2
4 1
3 3
4 4
5 3
1
1
20 15
10.1 7.5
66.5 74
Daily Gas and Daily Water Production v~"'
Daily Water Production per Platform (E/D)
100- 200- 500- 1000- 2000-
200 500 1000 2000 5000
2 1
2
1 1
1311
3 10 3 1
34 111
2122
1 1
1 1
1
12 23 863
6.0 11.5 4.0 3.0 1.5
80 91.5 95.5 98
Total
4
4
5
2
22
31
32
49
27
13
1
5
3
1
199
Cum.
% of
Total
2
4
6.5
7.5
18.5
34.1
50.2
74.9
38.5
95.
95.5
98.
99.5
100%
(1) Sources: U.S.G.S. Conservation Division, Gulf of Mexico Area, O.C.S.:
1. Approved Maximum Production Rates for Well Completions, October 1, 1974
2. Summary Production Report of Oil, Gas, Water by O.C.S. Leases, June 1974
Oil Scouts Association:
Platforms in O.C.S. Leases, June 1974
V-ll
-------
• Of a total of 440 oil producing platforms, only 147 or 33.4%
had a hydrocarbon production of more than 2000 B/D. About 4.5%
of the gas producing platforms had a production larger than
120,000 MCF/D equivalent to 20,000 B/D which was the upper limit
for the size of oil producing platforms in the sample.
9 Total water production on gas producing platforms is significantly
smaller than total water production on oil producing platforms.
About 75% of the gas producing platforms in the sample had less
than 100 B/D of water production, compared, on the same basis,
with not more than 28% of the oil producing platforms. Not more
than 4.5% of gas producing platforms have water production higher
than 1000 B/D compared with approximately 22.5% of the oil producing
platforms.
• Maximum water/oil or water/gas ratios are significantly higher
for oil producing platforms than for gas producing platforms.
Not more than 12 (6%) of a total of 199 gas producing platforms
have water/gas ratios greater than or equal to one when measured
on a barrel equivalent basis (6000 cu. ft. gas + 1 bbl equivalent
oil) compared with 97 (22%) of the oil producing platforms.
V-12
-------
i-m
iz-iu
-------
For the analyses it was necessary to estimate what size
treatment and reinjection capacities would be required on different sized
production units. This required an estimate of the amount of water which
could be expected to be produced together with the oil and gas of a given
field. For this purpose it was assumed that reservoirs included in the data
base for the Gulf of Mexico area are without exception water drive reservoirs.
The formation pressure in a field with a water drive stays approximately level during
the life of the field (except where permeability is low and producing rates high)
while the formation pressure of other types of drive mechanisms (e.g. solution
gas drive, gas cap drive), decrease with relative uniformity over the life of a
field.
Given the fact that the reservoir pressure has to overcome the pressure
differentials resulting from the weight of the fluid column in the production
tubing plus the resistance to flow in the reservoir, production tubing and
surface lines^ the amount of formation water produced during any time
interval on the field's life can be assumed never to exceed the amount
of oil, corrected for the difference in gravity between oil and water.
Therefore, for the analysis it was assumed that for a given production unit
the capacity of treatment and reinjection facilities would be sufficient to
accommodate volumes of water equal to the "total volume of oil and water processed
in 1974, corrected for the difference in gravity between oil and water.
Most fields in the Gulf of Mexico have a combination of gas cap and water
drive. As a result end of life water production for production units can be
expected to be lower than implied by the assumption of a uniform water drive.
V-14
-------
In the case of gas fields, based on the statistics shown in Table III-6,
it was assumed that the water/gas ratio of barrels of water per MCF of gas
produced would never exceed 0.16 and that the maximum capacity for a given
water treatment facility on a platform would not exceed 5000 bbls/day of water.
In the absence of information on actual decline curves experienced on
production units in the Gulf of Mexico or Alaska offshore a uniform 'exponential
decline rate was assumed, implying that the annual oil or gas production would
decrease by the same percentage in each consecutive period. The results of the
impact were tested to changes in the value of these decline rates, which were
assumed to be 15% per year for oil producing facilities and 12% per year for
gas producing facilities.
The approximate volume of annual production in 1974 for each completion
for oil wells and gas wells was obtained from the allowable schedules for the
Gulf of Mexico federal and state waters. For various reasons, such as well
shut-ins for workover purposes or for observation, the allowed production can
be less than the actual production during a given year.
Actual oil production and gas production for the Gulf of Mexico area
during 1974 and 1973, respectively, was therefore compared with the implied
production used in the analysis. Table V-6 shows that the use of allowables
in the case of oil resulted in a production estimate about 25% higher than the
actual production in 1974. In the case of gas the use of allowables resulted
in an estimated production not more than 0.5% different from the actual
production. A possible explanation for the much larger difference between
actual and implied production for oil in 1974 may lie in the fact that implied
production in federal waters was based on the use of Maximum Efficient Rates
V-15
-------
f
Federal waters
(4
State waters
Gulf of Mexico
(3)
(5)
TABLE V-6
Actual Production in 1973/1974 Compared with
the Production in 1973/1974 Implied by the
Use of Allowables in the Analysis
Actual
Oil and
Lease
Condensate
874
216
1090
1974 Product ion '^
Implied
Conden-
Oil sate Total
(in thousand B/D)
957 32 989
253 27 280
1269
(2)
1973 Product ion ^ '
Actual Implied
Gas and Gas Oil
Oil Well Well Well
Gas Gas Gas
-------
while 1974 production was still based on Maximum Production Rates.
3.4 Production Units in State Waters
For the Gulf of Mexico state waters, information was available only
on the number of producing completions by company for each individual pool or
field. A considerable number of these fields produce oil, water and gas into
onshore facilities, where these fluids are separated and treated. It was assumed
that the additional treatment equipment would be sized to process the water
produced from these clusters of completions operated by one company. Most of
these clusters were relatively small (Table V-7). The size range for treat-
ment systems assumed to be required in state waters can therefore be expected
not to be much different from the actual range of required sizes.
3.5 Production Units in Cook Inlet, Alaska
For Alaska, data was available on oil, gas and water production for
each completion on the fourteen oil producing platforms in Cook Inlet. This
data is discussed in Section VI.4 where the impact analysis for Alaska is
discussed.
rate^hiT Ef"Cient Rate for a Completion is defined to be that production
rate which can be sustained during at least six months without causing
lasting damage in the production characteristics of a reservoir.
The Maximum Production Rate is set for resource conservation purposes and
as such usually lower than the Maximum Efficient Rate.
V-17
-------
TABLE V-7
Size Distribution of Production Units in
Gulf of Mexico Federal Waters and in
Louisiana State Waters
Federal Waters State Waters
Number of
Completions Oil Gas/2' Oil Gas/
0-2 96 40 17 12
2-4 104 42 67
4-6 103 28 21 7
6-8 66 13 24
8-10 44 14 21
10-12 12 7 02
12-14 12 5 30
14-16 15 2 01
16-18 64 01
18-20 72 22
20-25 11 6 32
25-30 0 02
30-35 1 02
35-40 0 11
40-50 0 3
50-60 0 1
60-70 0 0
70-80 0 1
80 1
Including Louisiana and Texas federal waters
(2)
Nonassociated gas
Source: Production and Proration Order, Louisiana Dept. of Conservation,
and U.S.G.S. Conservation Div.
V-18
-------
VI. ECONOMIC IMPACT ANALYSIS
VI.1. SUMMARY
The following chapter presents the results of the impact analysis
obtained using the methodology as explained in the previous chapter. The
analysis was first done for what will be called "base cases" developed
separately for the Louisiana state waters and the Gulf of Mexico federal
waters using best estimates for important parameters such as prices for oil
and gas, annual production decline rates, the cost of capital and using
assumptions of the most likely configuration of production units in terms
of number of platforms per unit and space availability for
additional treatment and reinjection equipment.
This analysis measured the impact by investment and operating costs
for additional water treatment equipment expected to be required on oil and
gas production units in state and federal waters in 1977 to comply with new
water pollution standards and the impact of costs for additional water
reinjection facilities expected to be required in 1983 in state waters. The
impact was measured in terms of:
• The loss in potential production if oil and gas producers
have to absorb the investment and operating costs for the treat-
ment and reinjection facilities.
• The total investment required for treatment and reinjection
facilities in 1977 and 1983 respectively.
VI -1
-------
• The total number of completions which would be abandoned in
1977 and 1983 because some production units will not be able to
pay for the additional investment with the remaining
production. Price increases are assumed not to occur.
• The average increase in the costs per unit produced.
The analysis considered, oil and gas production in Louisiana state waters
and the Gulf of Mexico federal waters using 1974 data for existing production
units.
The results of these analyses are summarized in Tables VI-1 and VI-2.
If operators of oil and gas producing units existing in 1974, will have to
absorb all of the treatment costs and operating costs required for treatment
and reinjection facilities, then it can be expected that for units producing
in 1974:
• In the Gulf of Mexico, 14.0 to 27.8 million barrels of potential
remaining production of oil and lease condensate will be lost
or 0.6 to 1.2% of total potential production in 1977 and 81.4
to 249.4 million MCF nonassociated and associated gas representing
0.3 to 1.0% of total potential remaining production in 1977
from oil and gas producing units existing in 1974.
VI-2
-------
TABLE VI-1
Producers Absorb All Costs
Range of Likely Impact in the Gulf of Mexico
Federal and State Waters
(1974 dollars)
Federal Waters (No Reinjection Required)
Loss in Potential Prod., oil (2) 0.5 - 1.0% 8.5 - 17.5 MMB
gas (3) 0.3 - 0.85% 60 - 158 MM MCF
Total Invest. Required, 1977 45 - 125 MM $
1983 N A
Total Completions Aban. 1977 less than 0.3% 2-8
State Waters
Loss in Potential Prod., oil (2) 1.2-2.1% 5.5 - 10.3 MMB
gas (3) 0.4 - 1.5% 21.4 - 91.4 MM MCF
Total Invest. Required, 1977 18.8 - 19.7 MM $
1983 49.7 - 56.4 MM $
Total Completions Aban. 1977 < 0.2% 1-2
1983 3.5 - 6.2% 42 - 75
Total Federal and State
Loss in Potential Prod., oil (2) 0.6 - 1.2% 14.0 - 27.8 MMB
gas (3) 0.3 - 1.0% 81.4 - 249.4 MM MCF
Total Investment Req., 1977 63.8 - 144.7 MM $
1983 49.7 - 56.4 MM $
Total Completions Aban. 1977 < 0.2% 3-10
1983 0.9 - 1.5% 42 - 75
State waters do not include Texas state waters, which represent less than
1% of total oil production in state waters and less than 0.25% of total
oil production in federal waters.
(2)
Including lease condensate
(3)Including associated gas SOURCE: Arthur D- Little, Inc., estimates
VI-3
-------
• Total investment requirements, in 1974 dollars, will be
between $63.8 to $144.7 million by 1977 and between $49.7 to
$56.4 million by 1983.
• The number of completions abandoned in 1977 will be less
than 0.2% of total producing completions in 1976 or 1977 and
the total number of completions abandoned in state waters in 1983
will be between 0.9% to 1.5% of the completions producing in 1982.
Operators will not necessarily have to absorb all of these costs. Therefore
it was calculated what the average increase in costs per barrel or MCF
produced might be, which producers would like to pass on. The results of
these calculations are shown in Table Vl-2:
• For oil produced in federal waters, average cost increases in
1977 will likely be between 9.0 to 31.2c per barrel and
between 11.6 and 16. 3c per barrel for oil produced in state
waters to allow producers to cover investment and operating
costs for treatment facilities over a fifteen year period.
VI-4
-------
TABLE VI - 2
(1) Range of Average Cost Increases in the Gulf of Mexico
Federal and State Waters
(1974 Dollars)
Oil Wells Gas Wells
1977 1983 1977 1983
Federal Waters (in C/Bbl) (in C/MCF)
Cost Increase 9.0 _ ^1.2 N/A .14 _ 0.92 N/A
State Waters
Cost Increase 11.6 -16.3 77.3-107.9 0.41 -0.57 2.41 - 3.31
(2) Economic Cost per Average Barrel of Oil Recovered
Oil Wells Gas Wells
Federal Waters 1977 1983 1977 1983
EC. Cost per Bbl Recovered ($/Bbl) 94 2382 N/A 42 4511 N/A
•
State Waters
EC. Cost per Bbl Recovered ($/Bbl) 36 - 1237 371 - 8321 133 - 2984 808 - 17741
SOURCE: Arthur D. Little, Inc., estimates
VI-5
-------
• For oil produced in state wateis average cost increases in
1983 will be about 77.3 to 107.9c per barrel, allowing producers
to recover investment and operating costs for reinjaction
facilities over a fifteen-year period.
• For gas produced in federal waters, average cost increases in
1977 will be about 0-14 to 0.92C per MCF and in state waters
they will be'about 0.41 to 0.57C per MCF, allowing recovery over a
period of 15 years investment and operating costs for treatment
facilities installed in 1977.
• For gas produced in state waters, average cost increases in 1983 will
likely be 2.41 to 3.31C per MCF, allowing recovery of investment
and operating costs for reinjection facilities installed in 1983.
As mentioned above, the data base used for the analysis consisted of wells
reported to be producing in 1974 and as such represented only a part of the
wells which will be affected by the new regulations in 1977 and in 1983.
To give a rough indication of potential impact of the guidelines on new
wells in the Gulf of Mexico, USGS estimates of reserves
Geological Estimates of Undiscovered Recoverable Oil and Gas Resources
in the United States," Geological Survey circular 725.
VI- 6
-------
were used and the results of the analysis were extrapolated on a unit of
reserves basis.
The same was done with estimates of the category of undiscovered
recoverable resources in the Gulf of Mexico and other offshore areas
as estimated by the U.S.G.S. to obtain at least an indication of the potential
impact on the oil and gas wells and platforms expected to be installed later
than 1977. The results show that for new sources the loss in potential produc-
tion might be as high as .35 billion bbls of oil and 1.75 billion MCF of gas if price
increases are not allowed. Investment might be as high as 1.92 billion dollars
(see Table VI-17). These high estimates of losses in potential production from
recoverable resources are equivalent to about 75% of 1974 offshore oil production
and to about 15% of 1974 offshore gas production. The losses will not occur
during any single year but rather during a period of about 50 years starting
somewhere between 1990 and 2000. The additional investment required will also
be made over a period of at least 30 years following 1977, rather than
having to be made in any one single year.
Since some oil which otherwise would be discharged will be
recovered through the additional treatment required in 1977,this treatment
can be considered as another way to produce oil. It is shown in Section VI-10
VI-7
-------
m
of this chapter that the treatment technology considered to be BPCTCA^ on
the average recovers more energy than it consumes. However, in terms of
economic cost per barrel recovered, it can be considered as, at best, a rather
larginal investment if the objective would only be to produce more barrels of
oil at an earlier point in time.
• For oil wells the average economic cost per barrel recovered
in 1977 for treatment facilities will be somewhere between $36
to $2382 mainly depending on the amount of water treated during
that period.
• For gas wells the economic cost per barrel recovered in 1977
will be somewhere between $42 and $4511.
Reinjection systems to be installed in state waters in 1983 are
not part of the treatment systems proper. If it is assumed, however, that
these systems will have to be paid for by the oil which is recovered through
treatment then, as shown in Table Vl-2, the economic cost per barrel recovered
for oil wells will be between $371 and $8321 and for gas wells between $808
and $17741.
As mentioned earlier, cost data which would allow a rigorous analysis of
the potential impact on offshore oil and gas production in Cook Inlet in Alaska
were not available. A preliminary estimate of the potential impact has been made
assuming that costs for oil and gas production and required treatment and re-
injection in Cook Inlet will be from three to six times higher than the ones
used in the impact analysis for the Gulf of Mexico. The results of this estimate
are discussed in Section VI-12.
Best Practicable Control Technology Currently Available.
(2)
The average cost per barrel recovered over a 15-year period allowing for a
return on investment of 12% to 20% and after tax operating costs.
VI-8
-------
VI.2. FEDERAL WATERS: BASE CASE RESULTS FOR OIL WELLS AND GAS WELLS
The computer program, discussed in the previous chapter, was used to
estimate the impact of the new treatment regulations on existing oil and gas
producing facilities in the federal waters of the Gulf of Mexico. Base case
parameter values and assumptions consisted of the following:
• Oil and gas wellhead prices of $7.50/Bbl and $0.50/MCF respectively.
• Annual decline rates of 15%/yr for oil and 12%/yr for gas.
• Production units consist of one platform.
• All platforms will require additional treatment equipment in 1977,
consisting of surge tank and flotation unit.
• All platforms will have enough space to accommodate this additional
equipment.
The results of the analysis for oil wells are shown in Table VI-3.
Only.one oil producing platform with one producing completion would
likely be abandoned in 1977 resulting in a loss of potential production not more
than 36.4 MB or less than 0.3% of the total 14.0 MMB of oil production foregone.
The annual volumes of potential production lost through immediate abandonment
In 1977 are shown in the column under the heading "Production Loss By Platform
Shut-ins in 1977." Most of the potential oil production loss, 13.98 MMB or
99.7% of the total of 14.0 MMB, will be by a decrease in the producing lives of
completions.
The annual volumes of potential production lost by this decrease in the
producing life of completions is shown in the column under the heading "By
Decrease in Producing Life." The number of completions abandoned annually shown
in the column under the heading "Abandonments."
In addition to the loss of potential oil production of 14.0 MMB, 40.3
MM MCF of associated gas has been estimated to be lost as well. These losses in
VI-9
-------
TABLE VI-3
Federal Waters - Oil
Producers Absorb All Costs
Year
Production Loss
by Platform Shut-
ins in 1977
(barrels)
'Production Loss
by decrease in
Producing life
(barrels)
Completion
Ab an d onmen t s
1977
1 9 a n
19 HI
19B?
19H1
1901
1 9 b CJ
19H9
I99n
1991
199?
1993
1991
1997
199«
1990
2001
2 H 0 9.
2003
2001
2005
200*
TOTAL
« " fc 6'
n-
n,
n.
n«
n .
n •
n '
n ,
n •
i «
n«
n •
n-
p .
n .
n .
n .
n ,
n .
n-
n ,
n .
n •
n .
n.
n,
n.
6 1 7 P .
2 '/!>
H h
1 9 v n o rt
19471 A
1 8 y t> « n
1 3. 1 U «
7R77P
1
1.
0-
D.
1 .
U.
39.
94.
12-
10U.
20 /.
26.5,
243
231
130.
1 1 0 .
47.
A3,
3U,
1-
3-
U.
4
Cl
2690
Total Equipment Investment in 1977: $63.9 million
Fraction of Investment Made in Reinj. in 1977: .0000
Total Equipment Investment in 1983: 0
Platforms Immediately Abandoned: 1
Total Oil Production Foregone: 1A.O million Bbls
Total Associated Gas Foregone: 40.3 million MCF
Completion Lost before 1977: 4.
Production Lost before 1977: .054 million barrels
SOURCE: Arthur D. Little, Inc.,
estimates
VI-10
-------
potential production of oil and associated gas will amount to about .88% of
estimated recoverable oil reserves in 1977 and 1.12% of associated gas reserves.
Total investment required for additional equipment in 1977 will be 63.9 MM $.
Table VI-4 shows the base case results for the gas wells in federal waters.
Early abandonments in 1977 will result in a loss of potential gas production of
513.8 M MCF or less than .7% of a total of 75.4 MM MCF of non-associated gas.
About 74.9 MM MCF of non-associated gas, or 99.3% of the total loss
in potential production, will be through a decrease in the producing lives of well
completions. It is estimated that together with the loss of a total of 75.4 MM MCF
of non-associated gas about 1.1 MMB of condensate will be foregone.
Total gas production foregone will be about 0.5% of estimated recoverable
reserves in 1977 and total condensate production foregone will be about 0.67% of
estimated reserves. Total investment requirements in 1977 will be 23.5 MM$.
Given the small number of early abandonments in 1977 it can be expected that the
new regulations will have no effect on the employment situation related with
oil and gas production in federal waters.
VI-11
-------
TABLE VI-4
Federal Waters - Gas
Producers Absorb All Costs
Year
19/7
197H
1970
1990
1991
199?
-1
199*
1997
2000
2001
200 4
2001
TOTAL
Production Loss
by Platform Shut-
ins in 1977
(MCF) _
f 9 M -I •
f;6/;J1 -
-12377-
n ,
n ,
n •
n»
n .
n •
n .
n •
n .
n.
n ,
n ,
n .
0 i
0 ,
n
n
H
Production Loss
by Platform Shut-
ins in 1983
(MCF)
"i ,
i t
n t
n .
f ,
n.
n,
, J •
n,
n.
Production Loss
by decrease in
Producing Life
(MCF)
--"T7-
n,
r.,
n.
7 .' ?
4 V 4 4 / 1 ^
5 P 3 3 4 -1
'
-------
Federal Waters; Sensitivity Tests by Changes in Base Case Parameters
The base case results were tested for their sensitivity to changes in
the following parameters and assumptions:
• Changes in the "wellhead" price for oil, ranging from $5.25 to
$11.00/Bbl, and for gas, ranging from $0.30 to $0.75 per MCF.
• Changes in the annual decline rate, ranging from 12% to 18% for oil
and from 9% to 15% for gas.
• Changes in the cost of capital, ranging from 12% to 25% for oil -
as well as for gas producers.
• Assuming that extra space would be added on to existing platforms
either by an extra deck or by an additional platform if extra space
requirements exceeded 1000 square feet.
• Assuming that production units consisted of clusters of 3 platforms
rather than 1 platform units.
The results of these sensitivity tests produced the following conclusions (see
Tables VI-5 and VI-6):
• The estimated impact in terms of percentage loss of total potential
production is most sensitive to changes in the price parameter.
For oil this estimate ranged from a high 1.06% to a low 0.56% of
potential production lost, assuming "wellhead" prices of $5.25 and $11.00
per barrel respectively.
For gas this estimate ranged from a high 0.98% to a low 0.29%, assuming
wellhead prices of $0.30 and $0.75 per MCF respectively.
• The estimated impact in terms of total investment required is very
sensitive to changes in the assumptions about whether extra space will
have to be provided by an extra deck or extra platform and whether typical
VI-13
-------
TABLE VI-5
Sensitivity of Results to Changes in Key Variables
Varied
Parameter
Price
Decline
Rate
Cost of
Capital
Extra Space
Required
3 Platform
Unit
(1974 dollars)
Federal waters; no reinjection required; oil
Producers Absorb All Costs
% Loss of Total Number of
Potential Investment Completions
Value
$ 5.25
*$ 7.50
$ 9.00
$11.00
12%
18%
15%
20%
25%
Production
Oil
1.06
0.88
0.73
0.56
0.66
0.94
0.88
0.88
0.88
0.89
0.80
Gas
1.38
1.12
0.94
0.77
0.95
1.24
1.12
1.12
1.12
1.13
1.03
(in
1977
63.70
63.86
63.86
63.99
64.88
62.78
63.86
63.86
63.86
120.41
40.87
MM$) Abandoned
1983 Total 1977 1983
NA 3 NA
1
5
3
1
2
1
1
1
3
1
Number of
Producing
Completions
End 1976
2690
2690
2694
2694
2690
2690
2690
2690
2690
2690
2690
*Base Case: 1 Platform Unit
Equipment Technology C
Price $7.50
Decline Rate 15%/year
Cost of Capital 12%/year
SOURCE: Arthur D. Little, Inc., estimates
VI-14
-------
TABLE VI-6
Sensitivity of Results to Changes in Key Variables
Varied
Parameter
(1974 dollars)
Federal waters; no reinjection required; gas
Producers Absorb All Costs
% Loss of Total Number of
Potential Investment Completions
Value Production (in MM$) .Abandoned
Gas
Price
$ 0.30 0.
*$ 0.50 0.
$ 0.75 0.
98
50
29
Oil
1.
0.
0.
10
67
32
1977 1983 Total 1977 198:
23.
23.
23.
31 NA
50
61
1
1
3
Number of
; Producing
Completions
3 End 1976
971
971
971
$ 1.00 NA
Decline
Rate
Cost of
Capital
Extra Space
Required
3 Platform
Unit
9% 0.
15% 0.
15% 0.
20% 0.
25% 0.
0.
0.
17
65
51
51
51
50
50
0.
0.
0.
0.
0.
0.
0.
41
75
67
67
67
67
67
23.
23.
23.
23.
23.
35.
5.
74
30
51
51
51
60
5
0
1
1
1
1
1
0
971
971
971
971
971
971
971
*Base Case: 1 Platform Unit
Equipment Technology C
Price $0.50
Decline Rate 12%/year
Cost of Capital 12%/year
SOURCE: Arthur D. Little, Inc., estimates
VI-15
-------
production units consist of clur :ers of more than on<_ platform.
If production units were assumed to consist of one platform which
will require an extra deck or an extra platform, when total
space requirements for the treatment facilities exceed 1000 square
feet, then investment costs for oil producing facilities will almost
double to $120 million and investment costs for gas producing
facilities will increase by about 50% to $35 million.
On the other hand, if we assume that typical production units
consist of three platforms rather than one, then total investment
requirements for oil producing units will be 50% of the base case
value or $40 million and total investment requirements for gas
producing units will be 25% of the base case value or $5.5 million.
• The number of early abandonments in 1977 remains very small
despite changes in parameters; less than 0.2% of the total
number of producing completions in 1977 for oil producing units
and less than 0.3% for gas producing units.
• The results of the impact analysis are not very sensitive to
changes in the cost of capital. No significant change in the
results occurred even when the cost of capital was 25%.
VI-16
-------
Ll-lA.
T-IA 3HI10I.1
-------
The results of these sensitivity tests are also shown in Figure VI-1-
It is shown in this figure that the percentage loss in potential production
of nonassociated gas is consistently lower than the loss in potential oil
production. Also, it does appear that the percentage loss of potential gas
production will not become much less than 0.20% when the wellhead price is
increased and not much more than 0.75% when the decline rate is increased.
The fact that present-day intrastate prices are already higher.than $1 per MCF
indicates that it can reasonably be expected that not much gas will be sold
in 1977 at $0.35 per MCF. The range in which the actual percentage loss in
potential production probably will be is therefore 0.20% to 0.75%.
Using the same reasoning, but choosing $5.25 as the lower limit for
the expected price in 1974, the probable range for the percentage loss in oil
production was taken to be between 0.50% and 1.00%.
Summarizing for the federal waters, the results of the impact analysis
amount to the following (See Table VI-7):
• Loss in potential gas production from both gas and oil wells
will be between 8.5 and 17.5 million barrels, (no price increases)
• Loss in potential gas production from both gas and oil wells
will be between 60-158 million MCF. (no price increases)
• Total investment required in 1977 in terms of 1974 dollars,
will amount to between 45 and 125 million dollars.
• Between 2-8 completions will have to be abandoned in 1977.
VI-18
-------
TABLE VI-7
Range of Likely Impact in the Gulf of Mexico
Federal Waters
(1974 dollars)
Oil Wells
Loss in Potential Prod., oil
ass. gas
Completions Abandoned in 1977
Investment Required in 1977
0.5 - 1.0% or_ 8 - 16 MMB
22 - 44 MM MCF
less than 0.2%
1-5
40 - 100 MM $
Gas Wells
Loss in Potential Prod., gas 0.2 - 0.75% or
condensate
Completions Abandoned in 1977
Investment Required in 1977
Total Loss in Potential oil
Prod.
Total Investment Req. in 1977
Total Completions Aban. in 1977
1983
less than 0.3%
38 - 114 MM MCF
0.5 - 1.5 MMB
1-3
5 - 25 MM $
8.5 - 17.5 MMB
60 - 158 MM MCF
45 - 125 MM $
2-8
(1)
Assuming producers absorb all costs.
SOURCE: Arthur D. Little, Inc., estimates
VI-19
-------
Average Cost Increases for Oil and Gas, Federal Waters
It might well be that producers in federal waters can pass on some of
the additional costs for treatment facilities by increasing the price for oil
and gas in 1977. Therefore, the range was calculated of these average cost
increases separately for oil and gas produced in the Gulf of Mexico Federal
waters.
i
First, assuming that producers would like to have a return on their
investment within 15 years, cumulative production of oil and gas was calculated
for the 15-year period starting in 1977. (See Table VI-8.)
Second, using the low and high estimate of the likely investment requirement
for oil producing facilities and the corresponding annual operating cost
estimates, the average per-barrel capital charge (Item 5), the per-barrel
operating cost (Item 7), and per-barrel depreciation charge (Item 8) could be
calculated.
Third, the net after tax increase in per-barrel operating costs was
calculated using a tax rate of 0.5 (Item 9).
The estimated average cost increase was then found by adding the after
tax capital charge and the increase in after-tax operating costs.
The capital charge was calculated assuming a 12% and 20% capital cost
to indicate how sensitive the cost estimate was to this particular parameter.
The results show that a price increase for oil in 1977 would have to be
£ *•
between 3.7 and 9.6 per barrel and between 0.06 and O^O^per MCF for gas
if producers are to recover the treatment facilities operating and invest-
ment costs including a return on that investment.
VI-20
-------
TABLE VI -8
Range for Likely Average Cost Increases in 1977
for Producers in
Federal Waters, Gulf of Mexico
(1974 dollars)
n 1977(1)
n 1991(1)
ion (15 years) ^
MM $)
Oil Wells
1977
252.6
23.8
1296.5
40 - 100
Gas Wells
1977
1850.6
305.8
11328.5
5-25
4. Investment (MM $)
5. Cap. Charge per Bbl (MCF)
(4 x 2.80)/ 3
6. Add Ann. Op. Costs (MM $)
7. Add Op. Costs per Bbl (MCF)
(6 x 15)/ 3
8. Add Dep. Charge per Bbl (MCF)
(4/1) (C/B)
9. Add After Tax per Bbl (MCF)
Op. Cost
0.5 x (7-8)
10. Cost Increase
(5 + 9)
(assuming 12% Capital Cost)
11. Cost Increase
(assuming 20% Capital Cost)
8.8 -21.5 C/B
3.4 - 8.6
9.0 -22.0
0.13 - 0.63 C/MCF
3.9 - 9.9 c/B 0.06 - 0.28 c/MCF
3.1 - 7.7 C/B 0.04 - 0.22 C/MCF
0.2 - 0.5 C/B 0.01 - 0.03 C/MCF
0.14 - 0.66 C/MCF
12.7 -31.2 C/B 0.19 - 0.92 C/MCF
(1)
In MMB or MM MCF
SOURCE; Arthur D. Little, Inc., estimates
VI-21
-------
VI.3. STATE WATERS: BASE CASE RESULTS FOR OIL WELLS AND GAS tfaLLS
The impact of treatment requirements in 1977 and reinjaction
requirements in 1983 in state waters was estimated for offshore Louisiana
using the computer program described in the previous chapter. The base
case parameters used were the same as for the impact analysis for federal
waters.
In the previous chapter it was explained that no data were available
on platforms in Louisiana state waters. Therefore, it was assumed that
production units consisted of clusters of completions reported to be operated
by one company in the fields, which were considered. Also it was assumed
that, if treatment of produced oil, gas and water took place on a platform,
adequate space would be available to accommodate additional treatment equip-
ment. If treatment would have to be done on land, then space availability
would not be a limiting factor.
Table V-7 indicates that this assumption may have introduced some
bias towards large treatment facilities, if production units within
state waters are distributed similarly as in federal waters.
Data on water, associated gas and condensate production were not
available on a lease-by-lease basis as for federal waters. Therefore, averages
had to be used obtained by using gross production data for the area.
Based on these gross production data, an oil/water ratio of .70,
a gas/oil ratio of .95 MCF associated gas per Bbl of oil, and a condensate/
gas ratio or .011 Bbl of condensate per MCF of nonassociated gas was used in the
analysis.
VI-22
-------
Table VI-9 and VI-10 shows the results for oil and gas wells in the
state waters respectively. For oil, these results show that:
• With no price increases, total loss in potential production will amount
to 6.87 million barrels of oil and 6.53 million MCF of associated gas;
less than 0.35% of this total will be due to early abandonments in 1977,
about 7% due to early abandonments in 1983, and the rest or 92.65%
will be due to a shortening of the producing life of completions.
• Total equipment investment will be $13.5 million in 1977 and
$37.7 million in 1983 or a total of $51.2 million.
• Early abandonments in 1977 will be 2 completions or less than
0.3% of total producing completions in 1977 and 53 in 1983 or
about 6.5% of the 1977 total.
• All operators will prefer to wait until 1983 before investing in
reinjection facilities rather than to invest in reinjection
facilities in 1977.
Table VI-10 shows the results of gas wells from which it can be concluded
that:
• A total of 60.4 million MCF of gas and 0.68 million barrels of
condensate will be lost, of which 3.1 million MCF or 5.1% will
be lost due to early abandonments in 1983 and 57.3 million MCF
or 94.9% due to a decrease in producing lives of completions
if no price increases are possible.
VI-23
-------
TABLE VI-9
State Waters - Oil
Producers Absorb All Costs
Year
1977
3.97ft
1979
1981
198?
I9b3
19(34
1935
198*
1987
196*
I99n
1991
199?
1991
1995
199*
1997
1999
2 0 0 n
20Q 1
2003
2004
2006
TOTAL
Production Loss
by Platform Shut-
ins in 1977
(barrels) _
1292?,
K294,
23H?,
p.
0,
n,
n,
(i,
0 .
n.
0,
n,
n»
n,
Hi
n,
n,
n,
n •
n,
n,
n,
n,
n ,
n,
P,
n,
n,
n,
n,
Production Loss
by
ins
Platform Shut-
in 1983
(barrels)
0,
Oi
0,
0,
C'»
p.
134306.
114536.
72290,
4U069,
34Clbfl,
2»9bO,
22244,
12148.
62HB,
2672,
0.
n«
n,
n,
n,
o.
0,
L',
n,
0.
0,
n.
n»
Ct
Production Loss
by decrease in
producing life
(barrels)
o,
n,
n,
n.
n,
0.
151180.
44/64,
libllfi.
11^22,
37537,
334^39,
2441U2,
1496V7,
!Q?lb4?,
1012427,
711207,
.359340,
592366,
352096,
1096J.4,
119436,
357933,
.5256*6,
148464,
1261V1,
^3637.
n.
0,
n,
Completion
Abandonments
2,
0,
Q.
0.
0.
0.
53.
0,
40.
0,
4,
53,
14,
If),
160,
101,
lib,
AQ,
76,
14,
0,
10.
46,
22,
0,
U,
u.
Q.
U,
c,
6378367,
Total Equipment Investment in 1977: $13.47 million
Fraction of Investment made in Reinj. in 1977: .0000
Total Equipment Investment in 1983: $37.74 million
Platforms immediately abandoned: 2
Total Oil Production Foregone: 6.87 million Bbls
Total Associated Gas Production Foregone: 6.53 million MCF
Completion Lost before 1977: 0.
Production Lost before 1977: 0. SOURCE: Arthur D. Little, Inc., estimates
VI-24
-------
TABLE VI-10
State Waters - Gas
Producers Absorb All Costs
Year
1977
197«
1979
1981
1984
1987
193"
1930
199.1
199?
1994
1997
199"
1990
200n
2nt)1
20U?
2003
20 U4
Production Loss
by Platform Shut-
ins in 1977
(MCF)
n.
n.
n .
Production Loss
by Platform Shut-
ins in 1983
(MCF)
ij
n
1.
n ,
n,
P .
n ,
p .
4 6 2 f.]^ D. •
410613 ,
35/»l?.
Ji'iBon.
2 7 / 0 9 4 .
> •} 3 H 4 3 ,
Production Loss
by decrease in
producing life
(MCF)
P,
r*
r .
P ,
n .
n .
?339?.in.
n.
i. n.
p,. n •
n . n ,
P ) j a
1, n ,
~] i "i .
"I , •! ,
TOTAL n, 3r/'3/>/?.
Total Equipment Investment in 1977: $5.87 million
Fraction of Investment made in Reinj. in 1977: .0000
Total Equipment Investment in 1983: $16.4 million
Platforms Immediately Abandoned: 0
Total Gas Production Foregone: 60.4 million MCF
Total Oil Production Foregone: .682 million barrels
Completion Lost Before 1977: 3.
Production Lost Before 1977: 0.31 million MCF
'; 2 n 2 1 V 5.
7271*77.
1.-4"5409 5.
7 rt 5 ti 6 .
1 () "*. 5 1 j 1 .
1 1^93 M,
1 *> ^ 3 > / 1 .
1 i 'i 6 n i 7 ,
? 7 £ , I 5 o '•» .
Completion
Abandonments
0.
0.
0.
u.
0.
'j f
6 ,
o.
o.
G.
0 .
4 .
10-
13.
1».
20.
ft'j.
66.
43.
U.
2V,
0.
11.
7 .
"I
U *
11.
16.
0 •
422
SOURCE: Arthur D. Little, Inc., estimate
VI-25
-------
• Investment in treatment equipment in 1977 will be $5.87 million
and investment in reinjection facilities in 1983 will be $16.39
million amounting to a total investment of $22.26 million.
• There will be no early abandonments in 1977 and not more than
6 in 1983 or 1.4% of completions producing in 1977.
It appears that a substantial number of oil completions will be producing
close to the economic limit in 1983, resulting in early abandonment of 53
of a total of 786 still producing in 1982. Given the fact that these
completions otherwise would have been phased out over a period of ten years,
it can be expected that the reassignment of personnel directly involved
in the production operations of these wells might pose a problem. This
especially if the completions were part of one company's operations
rather than being part of several companies' operations.
In the worst case this might even lead to lay-offs. Using one man
for every two completions as a rough, direct employment indicator about
27 people could be affected by early abandonments of oil completions in
1983.
VI-26
-------
FIGURE VI-2
1
t
*
I
-in Prirp
^__Los,s in potential |_
Production
Cfianjges in Cost
ol . Capital
1 Loss
Prod
UCtlOH;
t
.Changes tin ..I
y
Production
^oss in Potential,
-Sensitivity Tests
LuuTJ
-Gaif bf Mex
ase p
'DLeiikci ',
bf Me-:
Lco^ — Eedorai.
irametfers:
j" r! _____ - _
(A) Gas (
I
Price!
Decline.Rate
^7.50- J--$er
, 151-1 12%
Cap
Ltal
(H
-1255-
5SQC13
rcui
. :
me.,
st of
Capitc
VI-27
-------
State Waters; Sensitivity Tes-._s by Changes in Base Case Parameters.
Sensitivity tests for state waters were made by changes in the
following parameters:
• Changes in the "wellhead" price for oil, ranging from $5.25 to
$11.00/bbl and for gas, ranging from $0.30 to $1.00 per MCF.
• Changes in the cost of capital, ranging from 12% to 25% for oil as
well as for gas producers.
• Changes in the annual decline rate ranging from 12% to 18% per
year for oil and 9% to 15% per year for gas.
The results of these tests are shown in Table VI-12and Table VI-13 for oil
and gas respectively and the changes in impact in terms of a percentage loss
in potential production have been graphed as shown in Figure VI-2.
Table VI-11 summarizes the results of the impact analysis for Louisiana state
waters presenting the ranges within which the different impacts measured
are likely to fall as indicated by the results of the sensitivity tests:
* The loss in potential production will be between 1.25 to 2.25%
or 5.2 to 9.4 million barrels of oil and 5.0-9.0 million MCF
associated gas from oil wells. For gas wells the loss will be
0.3% to 1.5% or 16.4 to 82.4 million MCF and 0.25-0.93 million
barrels of condensate if no price increases are assumed for oil or gas.
• Completion abandonments in 1977 will amount to between 1 to 2
of a total 1213 producing oil and gas completions in 1977 and
to between 42 and 75 of a total of 1211 producing oil and gas
completions producing in 1983.
• Total investment requirements will be between $18.8 and $19.7
million in 1977 and between $49.7 and $56.4 million in 1983.
VI-28
-------
TABLE VI-11
Reinjection Required in 1983
Range of Likely Impact in Louisiana
State Waters '
(1974 dollars)
Oil Wells
Loss in Potential Prod., oil 1.25 - 2.25% 5.2 - 9.4 MMB
ass. gas 5.0 - 9.0 MM MCF
Completions Abandoned in 1977 less than 0.3% 1-2
in 1983 5.0 - 8.4% 40 - 66
Investment Required in 1977 13.0 - 13.8 MM $
1983 34.5 - 38.9 MM $
Gas Wells
Loss in Potential Prod., gas 0.3 - 1.5% 16.4 - 82.4 MM MCF
condensate 0.25 - 0.93 MME
Completions Abandoned in 1977 0
in 1983 0.5-2.1% 2-9
Investment Required in 1977 5.82 - 5.92 MM $
1983 15.2 - 17.5 MM $
Total Loss in Potential Prod., oil 5.45 - 10.33 MMB
gas 21.4 - 91.4 MM MCF
Total Investment Req. in - 1977 18.8 - 19.7 MM $
1983 49.7 - 56.4 MM $
Total Completions Aban. in 1977 1-2
1983 42 - 75
Assuming producers absorb all costs,
SOURCE; Arthur !••. Little, Inc., ccii-^t
VI-29
-------
TABLE Vl-lla
No Reinjection Required in 1983
Range of Likely Impact in Louisiana
State Waters
(1974 dollars)
Oil Wells
Loss in Potential Prod., oil 0.6-1.1% 2.7-4.4 MMB
aSS- gaS 2.6 - 4.2 MM MCF
Completions Abandoned in 1977 less than 0.3% 1-2
in 1983 NA
Investment Required in 1977 13.0 - 13.8 MM $
1983 NA
Gas Wells
Loss in Potential Prod., gas 0.16-0.8% 9.1 - 42.2 MM MCF
condensate 0.1 - 0.5 MMB
Completions Abandoned in 1977
in 1983 NA
Investment Required in 1977 5.82 - 5.92 MM $
_1983 NA
Total Loss in Potential Prod., oil 2.8 - 4.9 MMB
Sas 11.7 - 46.4 MM MCF
Total Investment Req. in 1977 18.82 - 19.72 MM $
1983 NA
Total Completions Aban. in 1977 1_2
1983 NA
Assuming producers absorb all costs.
SOURCE: Arthur D. Little, Inc., estimates
VI-30
-------
To show what difference it would make in terms of potential
loss in production, investment requirements and early abandonments, an
impact analysis for state waters was also done assuming that no reinjec-
tion would be required as of 1983. The results in Table Vl-lla show
that:
• The loss in potential oil and gas production will be
about half of what will occur when reinjection is
required in 1983.
• Investment requirements in 1977 will be the same, but
total investment requirements will be about 25% of the
total required in 1977 and in 1983 if reinjection in
1983 is required.
• Completion abandonments will be negligible.
VI-31
-------
TABLE VI-12
Sensitivity of Results to Changes in Key Variable;.
Varied
Parameter
Price
Decline
Rate
Cost of
Capital
Extra Space
Required
3 Platform
Unit
Value
$ 5.25
*$ 7.50
$ 9.00
$11.00
12%
18%
15%
20%
25%
(1974 dollars)
State waters; reinjection required; nil
Producers Absorb All Costs
% Loss of Total Number of
Potential Investment Completions
Production (in MM$) Abandoned
Oil
2.38
1.64
1.40
1.33
1.19
1.83
1.64
1.64
1.64
NA
NA
Gas
2.
1.
1.
1.
1.
1.
1.
1.
1.
38
64
40
33
19
83
64
64
64
1977
13.
13.
13.
13.
13.
13.
13.
13.
13.
37
47
47
47
85
09
47
47
47
1983
35.
37.
37.
38.
40.
34.
37.
37.
37.
73
74
74
88
24
43
74
74
74
Total 197 •
49.10 I
51.21 2
51.21 2
52.35 2
54.09 2
47.52 2
51.21 2
51.21 2
51.21 2
1983
66
53
53
40
40
66
53
53
53
Number of
Producing
Completion;
End 1976
786
788
788
788
788
788
788
788
788
*Base Case: 1 Platform Unit
Equipment Technology C
Price $7.50
Decline Rate 15%/year
Cost of Capital 12%/year
SOURCE; Arthur D. Little, Inc., estimates
VI-32
-------
TABLE VI-13
Sensitivity of Results to Changes in Key Variables
Varied
Parameter
Price
Decline
Rate
Cost of
Capital
Extra Space
Required
3 Platform
Unit
Value
$ 0.30
*$ 0.50
$ 0.75
$ 1.00
9%
15%
15%
20%
25%
(1974 dollars)
State waters; reinjecticn required; gas
Producers Absorb All Costs
% Loss of Total Number of
Potential Investment Completions
Production (in MM$) Abandoned
Gas
1.76
1.10
0.58
0.41
0.71
1.34
1.10
1.10
1.10
NA
NA
Oil
1.76
1.10
0.58
0.41
0.70
1.34
1.10
1.10
1.10
1977
5.
5.
5.
5.
5.
5.
5.
5.
5.
87
87
87
87
92
82
87
87
87
1983
15.27
16.39
17.11
17.47
17.18
15.20
16.39
16.39
16.39
Total
21.
22.
22.
23.
23.
21.
22.
22.
22.
14
26
98
05
10
02
26
26
26
1977
0
0
0
0
0
0
0
0
0
1983
9
6
4
2
4
11
6
6
6
Number of
Producing
Completions
End 1976
425
425
425
425
425
425
425
425
425
*Base Case: 1 Platform Unit
Equipment Technology C
Price $0.50
Decline Rate 12%/year
Cost of Capital 12%/year
SOURCE: Arthur D. Little, Inc., estimates
VI-33
-------
Likely Average Cost Increases for Oil and Gas, State Waters
~ '3 - 1-L_L1_ -
As explained in Section VI-4, producers might be able to pass on
the additional costs they have to incur to comply with the new water
treatment regulations.
Therefore, an estimate was made of the average cost increase for
oil and gas which can be expected to result in state waters in 1977 and 1983
and which producers would like to pass on. For the calculations, it
was assumed that producers would like to recover investment costs includ-
ing a return on that investment and after tax operating costs over a period
of 15 years following the investment.
The cost increase to be expected will then be the sum of the
average per barrel capital charge and the average per barrel net increase
in operating costs. These calculations are shown in Table VI-14. The
results show that oil prices would have to be increased by 11.6
-------
5.
6.
7.
TABLE VI-14
Likely Average Cost Increase in 1977 and 1983
for Producers in
State Waters
1. Production in 1977/1983
2. Production in
3. Cum. Productic
4. Investment (MM $)
Cap. Charge (i
Add. Op. Costs ($/yr)
Add. Op. Costs (6x1
Add. Dep. Charge (4/3)
(1974 dollars)
7/1983(1)
1 1 / 1 Q Q7
15 years) (1)
2.8 )/3
7yr)
. x 15) /3
(4/3)
Oil
1977
66.7
6.3
342.3
13.5
11.0 C/B
1.2
5.2 C/B
3.9 C/B
Wells
1983
25.0
0.8
137.1
35.0
71.5 C/B
3.4
37.2 C/B
25.5 C/B
Gas Wells
1977
689.2
112.6
4228.4
5.8
0<38 C/MCF 2.
0.55
0.20 C/MCF 1.
0.14 C/MCF 0.
1983
320.0
40.2
2051.9
15.5
13 C/MCF
1.82
33 C/MCF
76 C/MCF
9. Add After Tax Op. Cost
0.5 x (7-8)
10. Cost Increase
(Assuming 12% Annual Cap. Change)
11. Cost Increase
(Assuming 20% Annual Cap. Cb •-- ,e)
0.6 C/B 5.8 C/B 0.03 C/MCF 0.28 C/MCF
11.6 C/B 77.3 C/B 0.41 C/MCF 2.41 C/MCF
16.3 C/B 107.9 C/B 0.57 C/MCF 3.31 C/MCF
(1)
In MMB or MM MCF
SOURCE; Arthur D. Little, Inc., estimates
VI-35
-------
VI.4. ALASKA, RESULTS OF A PRELIMINARY IMPACT ANALYSIS
The production and treatment economics developed for the Gulf of Mexico
could not be applied to present offshore production in Alaska.
Industry sources indicated that operating cost levels are three-to-
six-times higher than the operating cost level used for the Gulf of Mexico analysis.
Investment levels can also be expected to be much higher given the harsher climate
under which construction has to take place and longer distances from major supply
centers.
The most important production statistics for the four oil fields and
one gas field producing in the Cook Inlet are summarized in Table VI-15. Water
production in each of the four oil producing fields is not sufficient to fulfill
the needs for the pressure maintenance programs by water injection in those fields.
The seawater which is used for this purpose is chemically incompatible
with the produced formation water, which precludes the use of a mixture of these
types of water for reinjection purposes. Therefore, only seawater is used for
reinjection purposes, even though the high solids content of this water necessitates
costly filtering before the water can be injected. Separation of produced fluids
and water treatment on the platform is limited to free water knockout. All other
treatment is done onshore by four large water treatment plants, one for each field.
One of these plants is judged by the EPA to be capable of meeting 1977 treatment
standards without any additional investment. All three others would require
additional equipment or equipment modifications, the economics of which were not
available.If the volumes of produced formation water increase to meet the total
reinjection requirements by 1983, the use of produced formation water for pressure
(1) Information obtained through discussions with EPA representatives
VI-36
-------
TABLE VI- 15
1973 Statistics on Oil and Gas Fields
Offshore Alaska, Cook Inlet
Field Name
Granite Point
McArthur River
Middle Ground
Shoal
Trading Bay
Average Production
Number of
Platforms
3
3
4
3
Number of
Completions
9
7
9
19
23
12
7
10
11
6
8
31
5
Oil
(B/D)
6,139
3,307
3,613
38,650
42,982
24,771
3,350
7,291
11,409
5,681
2,164
15,168
4,105
in 1973
Gas
(MCF/D)
5,368
3,812
3,199
9,614
16,200
7,429
1,512
3,807
5,292
2,182
601
7,637
1,157
Water
(B/D)
14
54
202
4,028
5,689
7,806
202
854
4,488
2,521
1,993
3,917
5,118
Water
Re injected
Field Total
(in B/D)
26,122
154,463
55,950
35,358
North Cook
Inlet (Gas)
0 117,011
Source: "Statistical Report 1973," State of Alaska Department of
Resources, Division of Oil and Gas.
VI-37
-------
lintenance might be the economically most attractive way to comply with the
'injection requirement. In that case, no investment in reinjection facilities
Lght be necessary in 1983. However, if this is not the case, then investment
i reinjection facilities for produced formation waters would be necessary in
•83 either on the platform itself or onshore next to the existing treatment plants.
Cost estimates of these solutions were not available. Therefore, to indicate
i which range the impact from new regulations can reasonably by expected to fall,
'o cases were evaluated, both using estimates of operating and investment costs
>r treatment and reinjection facilities of three and six times the costs used
r the Gulf of Mexico. The two cases differed in that the first case assumed the
eatment and reinjection facilities would be placed on the platforms and the
cond case assumed they would be placed onshore near the present treatment facilities
The results of this preliminary analysis of the first case are shown on
ble VI-16 and can be summarized as the following:
• If no investment in reinjection facilities would be required in 1983,
and assuming that producers would have to absorb all costs, then:
Loss in potential production would range between 0.8 and 1.9%
or 2.2 to 5.1 million barrels of oil and between 0.9 and 2.1%
or 2.4 to 5.0 million MCF of associated gas.
- No early abandonments would occur in 1977.
- Total required investment would range from $12.6 to $25.1 million.
• If it is assumed that producers would be able to pass on all costs
through ft T>rrire increase, calculated in the same wav as discussed in
Sections VI-2.3 and VI-3.3
- The required price increase in 1977 in terms of 1974 dollars would
be between 14£ per barrel and 28£ per barrel, assuming a 12% cost
of capital and between 21c per barrel and 42c per barrel, assuming
a 20% cost of capital.
VI-38
-------
TABLE VI-1-6
Alaska, Cook Inlet
Preliminary Estimate of Likely Impact (3)
(1974 dollars)
1. Assuming Producers Absorb All Costs
Potential Prod. Oil (MMB)
Ass. Gas (MM MCF)
Loss in Pot. Prod. (MMB)
(MM MCF)
% Loss in Pot. Prod: Oil
Ass. Gas
Early Abandonments, 1977
1983
Investment Required, 1977
(in MM$) 1983
No Reinjection Req.
3x
(1)
6x
(1)
Reinjection Req.
(4)
3x
(1)
6x
(1)
280
261
2.2
2.4
0.8
0.9
0
NA
12.6
NA
263
242
5.1
5.0
1.9
2.1
0
NA
25.1
NA
280
261
6.8
7.0
2.4
2.7
0
8 (= 5%)
12.6
35.0
263
242
14.7
16.7
5.6
6.9
0
54 (= 34%)
25.1
54.7
2. Increases in Average Cost per Unit Produced
(2)
Average Cost Increase Oil
Cost of Capital 12%, 1977
1983
Cost of Capital 20%, 1977
1983
in c/I
14
NA
21
NA
5
28
NA
42
NA
14
46.0
21
167
in C/B
28
71.0
42
313
(1)
(2)
(3)
(4)
3 x: Assuming all operating and investment costs are 3 x as high as in the
Gulf of Mexico.
6 x: Assuming all operating and investment costs are 6 x as high as in the
Gulf of Mexico.
Based on a calculation of the per-barrel after tax operating costs plus invest-
ment costs including a return on that investment over a period of 15 years.
Assuming treatment facilities will be put on each of fourteen oil production
platforms.
Assuming that reinjection facilities on platforms will be necessary in
addition to existing injection plants used for pressure maintenance.
SOURCE; Arthur D. Little, Inc., estimates
VI-39
-------
• If investment reinjection in facilities would be required in 1983
and assuming that producers would absorb all costs, then:
- Loss in potential production would range between 2.4 and 5.6%
or 6.8 and 14.7 million barrels of oil and between ?.7 and 6.9%
or 7.0 and 16.7 million MCF of associated gas.
- Early abandonments in 1983 would be between 8 and 54 or between
5% and 34% of total producing completions in 1977.
- Total investment required would be between $12.6 and $25.1
million in 1977 and between $35.0 and $54.7 million in 1983.
• If it is assumed that producers would be able to pass on all costs as price
increases and that they would calculate these price increases as
described in Sections VI-2.3 and VI-3.3, then:
- The required price increase would be 6.3C to 11.4c per barrel
in 1977 and 46
-------
TABLE VI- 17
Alaska, Cook Inlet
Preliminary Estimates of Likely Impact (3)
(1974 dollars)
1. Assuming Producers Absorb All Costs
No Reinjection Req.
Potential Prod. Oil (MMB)
Ass. Gas (MM MCF)
Loss in Pot. Prod. (MMB)
(MM MCF)
% Loss in Pot. Prod: Oil
Ass. Gas
Early Abandonments, 1977
1983
Investment Required, 1977
(in MMS) 1983
2. Increases in Averaee Cost
Average Cost Increase ^
Cost of Capital 12%, 1977
1983
Cost of Capital 20%, 1977
1983
3x(1)
280
261
2.0
2.2
0.7
0.8
0
NA
7.7
NA
ner Un
9
NA
13
NA
, (1)
6x
263
242
5.0
4.9
1.9
2.0
0
NA
15.5
NA
it; Produpprl
in C/B
17
NA
26
NA
Rein
3x(1)
280
261
3.6
4.1
1.3
1.6
0
0
7.7
25.7
9
81
13
127
jection Req. (4)
6x(1)
•263
242
11.1
12.2
4.2
5.0
0
44.0
15.4
43.1
in c/B
17
157
26
247
3 x: Assuming all operating and investment costs are 3 x as high as in the
Gulf of Mexico.
6 x: Assuming all operating and investment costs are 6 x as high as in the
Gulf of Mexico.
P)
"Assuming producers pass on the per-barrel after tax operating costs plus invest-
mpnr- costs including a return on that investment over a period of 15 yeirs.
Assuming treatment and reinjection facilities onshore - one for each of four
oil producing fields.
(4)
Assuming reinjection facilities will be necessary in addition to existing
injection plants for pressure maintenance purposes. SOURCE: Arthur D. Little, Inc.
VI-41
-------
No early abandonments would occur in 1977.
- Total required investment would range from $7.7 to $15.4 million.
If it is assumed that producers would pass on all costs through a price
increase, then:
The required price increase in 1977 in terms of 1974 dollars would
be between 3.8c per barrel and 7.6
-------
VI.5. CALIFORNIA
There are 14 producing platforms off of California, nine in state
waters and five in Federal waters. In addition, there are seven man-made
islands on which wells are producing offshore in state waters. (See Table VI-18),
All of the produced formation water from offshore facilities on state
and Federal leases is sent ashore for processing and disposal. The formation
water produced from facilities in Federal waters four to five miles offshore
is piped ashore, treated and returned to the platforms for reinjection. Of
the nine platforms in state waters, four have their production piped to one
onshore processing facility and the other five to five separate processing
plants.
Most formation water is reinjected for pressure maintenace, A small
portion is treated onshore and pumped into the ocean; while accurate data
is not available, the percentage of offshore produced formation water dis-
carded into the ocean has been estimated at 3.9% of total produced brine
in 1974. The 1974 brine production was 293.3 million barrels. If the same
percentage tage is applied *•• "'73, the volume of formation water discarded
is 10.9 million barrels. In addition to the brine from offshore production,
about 16 million barrels of formation water from onshore wells is discarded into
the ocean. This is about 2.3% of total onshore water produced with oil
and gas in the coastal basins.
Estimate made by Mr. John Hardoin, California Division of Oil and Gas,
Long Beach.
VI-43
-------
TABLE VI-18
California; Platforms and Offshore Oil,
Gas and Watep Production
in 1973
Number of Platforms
Oil production MMB
Associated Gas MM MCF
Non Associated Gas MM MCF
Water Associated MMB with Oil
Water Associated MMB with Gas
State Waters
9 + 7(2)
70.5
20.9
9.7
266.0
0.5
Federal Waters
5
18.8
9.1
0.0
12.2
0.0
(1)
(2)
Source: "Oil, Gas and Geothermal Production Statistics, 1973."
Resources Agency of California, Vol. 59, No. 2.
9 Platforms and 7 man-made islands.
VI-44
-------
California has enacted a brine disposal requirement that is more
restrictive than the proposed Federal effluent guidelines for 1977.
California regulations require water to be discharged in the ocean to be
treated to 20 parts per million (ppm) long-term average of oil and
grease. The Federal requirements are a 27 ppm long-term average. Unlike
the produced formation water from the Gulf of Mexico, the California
formation water has far lower salinity and is typically less saline than
the sea water.
The proposed EPA 1977 effluent guidelines do not appear to impose an
additional burden on California offshore production. The California state
requirement resulted in Phillips shutting in and removing one platform and
Texaco stopping production on two others in 1973 when the requirements went
into effect.
VI-45
-------
VI.6. INFERRED IMPACT, EXISTING SOURCES IN 'IdE GULF OF MEXICO
The estimates of the total impact in federal and state waters was
Dased on units already producing in 1974 It can be expected that by 1977
quite a few additional wells will have been drilled. Therefore, the total
number of, what the EPA considers to be 'existing sources," will be larger
than the number of production units considered in the earlier analysis.
To obtain an idea of how much this actual number of existing
sources will differ from the number of sources considered, tue total reserves
(2)
implied by the analysis was compared with the sum of demonstrated and
(3)
inferred reserves as defined and estimated by the U.S.G.S.
The underlying assumption was that demonstrated and
inferred reserves will be produced by wells existing in 1974 and wells to be
drilled until 1977 in federal waters and existing wells plus wells drilled until
1983 in state waters.
Assuming that the relative number of wells in federal and state
waters would remain the same and assuming that the measured impacts would be
extrapolated on a unit of reserves basis an estimate was made of the
total impact for these existing sources.
The results of this calculation using the assumptions for the
base case are shown in Table VI- 19 and Table VI-20.
Source" in this context should be understood to mean point source of
discharged water.
(2)
Implied reserves consisted of the total potential production of all com-
pletions considered.
Geological estimates of undiscovered recoverable oil and gas resources in
the United States," Geological Survey circular 725, 1975.
VI-46
-------
TABLE VI-19
Total Inferred Impact for Existing Sources in
the Gulf of Mexico as Derived from
the Measured Impact
Producers Absorb All
(1974 dollars)
Recoverable
Reserves
Oil Gas
MMB MM MCF
Costs
Potential
Prod. Lost
Oil
MMB
Gas
MM MCF
Required
Invest-
ment
MM $
Gulf of Mexico, Oil Wells
Federal, measured impact
Implied reserves
State, measured impact
Implied reserves
Total measured impact
Total implied res.
U.S.G.S. reserves
(2)&(4)
1590
419
2233
4612
3600
398
Inferred total impact (lx(3:2)) =
Gulf of Mexico, Gas Wells
Federal, measured impact
Implied reserves 162
State, measured impact
Implied reserves 62
Total measured impact
Total implied res.
U.S.G.S. reserves
Inferred total impact (5x(7 :6)) =
Total Gulf of Mexico (4+8) =
14743
5471
24212
102834
14.0
6.9
43.:
40.3
6.5
63.9
51.2
20.9 46.8 115.1
96.6 237.7
1.1 75.4 23.5
0.7 60.4 22.3
1.8 135.4 45.8
7.6 575.1 194.5
50.8 671.7 432.3
(1)
(2)
(3)
(4)
Including condensate produced with nonassociated gas.
Source: "Geological estimates of undiscovered recoverable oil and gas resources
in the United States," Geological Survey circular 725, 1975.
Including associated and dissolved gas to be produced with oil.
Including Demonstrated and Inferred Reserves.
SOURCE: Arthur D. Little, Inc., estimates
VI-47
-------
i AE: ^ vi-2
il 1 lirs. d Impact for New Sou1ee -
Produrerf Absorb An 1 Cr-ets
(J974 dollars)
Cul' of Me oil an.- -.:..
in the United States," Geological Sui -ey circulc-.r 725, 1^7-,
(3)
Including associated an-: , '--solved gas to be produced with oil.
SOURCE: Arthur D. Little, Inc., estimates
VI-48
-------
According to these results, loss in potential oil production,
including lease condensate, will be 50.8 million bbls and loss in potential gas
production, including associated gas, will be 671.7 million MCF; total invest-
ment requirements in 1977 and 1983 will amount to $432.2 million.
Given the gross assumptions which were made in deriving these
numbers, they should be regarded to be no more than a very rough estimate,
which might be off by as much as a hundred percent.
VI-
-------
VI.7. INFERRED IMPACT, NEW SOURCES IN THE GULF OF MEXICO
The earlier sections of this chapter have presented estimates
of foregone production from wells existing in 1974 and the required invest-
ments in treatment and reinjection facilities for these wells resulting
from the application of the effluent limitations guidelines. As explained
in Chapter III, the EPA is also proposing a New Source Performance Standard
(NSPS) guideline applicable to all new wells in both state and Federal
waters which is identical in its requirements to the 1983 guidelines for wells
which were already producing prior to 1977 except that it becomes applicable
in 1977. This implies that new wells in state waters as of 1977 v/ill
be required to reinject all produced formation water and new wells in federal
waters must comply with the BATEA/NSPS requirements in 1977.
A rough worst case estimate can be made of the foregone production
resulting from the application of the NSPS requirements to wells beginning
production in 1977 and thereafter. The majority of these new wells are
expected to be in federal waters, not state waters. To simplify the
estimating process, which is crude at best, the assumption has been made
that all new wells after 1977 will be in federal waters, which implies that
there will be no reinjection requirement for these wells.
The U.S. Geological Survey has published estimates of the total
recoverable resources from the U.S. given existing production technology.
' 11
"Geological estimates of undiscovered recoverable oil and gas resources
in the United States" Geological Survey Circular 725, 1975.
VI- 50
-------
Table VI-21 lists the resource estimates for the offshore areas. The
estimates can be regarded as an approximate estimate of the total life-
time production from all new offshore oil and gas wells in the futuie.
As production technology and the relative cost of other energy sources
change in the future the volumes of oil and gas which may ultimately
be produced from U.S. offshore wells can also change. However, the U.S.
G.S. resource estimates at least provide one basis from which the long
term production losses resulting from the proposed regulations can be
estimated.
The earlier analysis of potential production losses from the
application of BPCTCA and BATEA requirements to wells in federal waters
which were producing in 1974 showed that 0.5% to 1.0% of their remaining
lifetime oil production and 0.2% to 0.75% of their remaining lifetime
production of gas would be lost if prices could not be increased to
recover the pollution control costs. Table VI-20 lists the projected
production losses if these percentages are applied to the U.S.G.S.
resource values.
Using this estimating proceedure as demonstrated in Table VI-19
for new sources in the Gulf of Mexico, the projected loss in potential
production is 25 to 70 million barrels of oil and 144 to 558 million
MCF of gas. These losses would be stratched out over the entire period
of offshore U.S. production beyond 1977. Most of the potential losses
would not occur until after the year 2000.
The estimate of total investment was made in a similar way as
demonstrated in Table VT-20. First, investment required for future oil
VI- 51
-------
TABLE VI-21
Total Inferred Impact for New Sources
Offshore U.S.A. 1^
(1974 dollars)
Producers Absorb All Costs
( , Potential ( . .
Rec. Resources\ ' Prod. Lost^ ; Required^ }
Oil Gas Oil Gas Investment
Billion Billion Billion Billion Billion
Bis MCF Bis MCF $
Gulf of Mexico 5.4-8.0 18.0-91.0 .03-.07 .14-.56 .13-.41
Alaska 3.0-31.0 8.0-80.0 .03-.25 .10-1.04 .12-1.35
Atlantic Coast 2.0-4.0 5.-14.0 .02-.03 .06-.15 .08-.16
Pacific Coast 2.0-5.0 2.0-6.0 .01-.07 .05-.14 .08-.19
Total .08-.35 .30-1.75 .33-1.92
.11-.38 .65-1.89 .53-2.12
Based on base case results for the impact analysis for old sources and as such
presenting a lower limit for the estimated impact for new sources.
Source:
"Geological Estimates of Undiscovered Recoverable Oil and Gas Resources
in the United States," Geological Survey circular 725, 1975.
The low and high estimates have been made at the 95% and 5% confidence levels
respectively.
Source: Arthur D. Little, Inc. calculations based on U.S.G.S. estimates of
recoverable resource.
(3)
Expected to occur over a period of about 50 years starting between 1990 and 2000.
(4)
Expected to be required over a period of at least 25 years following 1977.
SOURCE; Arthur D. Little, Inc., estimates
VI- 52
-------
and gas producing wells in each area considered was estimated multiplying
the estimated investment requirement per unit of estimated remaining
reserves in 1977 for wells producing in 1974 by the total estimates of
total recoverable oil and gas resources respectively. The total invest-
ment requirement shown in Table VI-21 was obtained by summing these
estimates obtained for oil and gas resources.
In addition to the uncertainty about the resource values them-
selves, there are several potential errors from simply multiplying the
percentage loss from 1974 wells times the resource estimates. The
percentages are the portion of the remaining life after 1977 of the
wells existing in 1974.
All of these wells have been producing prior to 1974. This
implies that the estimated percentage loss of remaining production in
1977 is considerably higher than it would have been if this percentage
would have been calculated using the total lifetime production of these
wells.
As a result, the estimated loss in potential production for
new wells, which has ,tan derived by multiplying this percentage
obtained for 1974 wells with the estimated total lifetime production
for new wells (i.e. estimated total recoverable resources), should be
too high.
For the same reasons the investment estimates for new sources
derived by using investment requirements per unit of potential production
of wells producing in 1974 might be too high.
On the other hand, this upward bias in estimated loss in potential
production may be mitigated by the fact that much of the new production
VI- 53
-------
will be from wells in areas with higher production costs such as Alaska
and the Atlantic. It can be expected that the cost of compliance per
well or unit of production in these areas will be higher than was
assumed in the Gulf of Mexico analysis which will result in higher
losses of potential production.
The relative weight of these opposing biases is not known.
However, they do suggest the approximate nature of the estimates.
VI-54
-------
VI.8. DIRECT ENERGY EFFECTIVENESS OF TREATMENT EQUIPMENT
The following analysis has assumed that EPA1s estimate that a
long-term average of 27 ppm of effluent hydrocarbon concentration is
achievable with the application of the BPCTCA regulation. See
Chapter III for a discussion of the analysis behind the assumptions.
The average hydrocarbon influent concentration of all units
considered by Brown & Root was 196 ppm. Based on this information,
an average of 169 ppm (mg oil per liter of water treated) to be
recovered by treatment of produced formation waters will be used in
this analysis of the direct energy effectiveness of treatment equipment,
This 169 ppm of recoverable crude oil corresponds with 2.02 bbl
of oil recovered per 10,000 bbls of water treated.
Brown & Root report, page IV-8.
VI-55
-------
Figure VI -3 taken from the Brown & Root report shows the horse-
powers required as a function of treatment capacity for treatment by flotation
and treatment by coalescence, respectively. Based on these graphs, the
horsepower requirements for flotation equipment used in the following analysis
will be 1 HP/344 barrels water treated. Treatment by gravity separation using
pits or tanks has a negligible energy requirement.
To inject 1 bbl/day of water at 1 psi pump pressure, 1.7 x 10 HP
pump power is required.
Assuming that 80% of the total installed pump capacity will be used,
one will need 2.125 10 HP installed pump capacity for each barrel of water
reinjected at a discharge pressure of 1 psi.
Assuming a 3000 foot deep reinjection well and knowing that the
overburden pressure decreased by the hydrostatic is about 0.5 psi/foot, we know
that the maximum discharge pressure cannot exceed 1500 psi. Using 1300 psi as the
maximum injection pressure at the pump (1300 x 2.125 10~ ) or .0276 HP will
have to be installed for each daily barrel of water to be reinjected.
A daily volume of 1000 barrels per day will thus require 27.6 HP of
installed pump power.
One HP delivered during one day is equivalent to .061 MCF of natural
gas or to .0101 barrels of diesel oil.
Assuming a conversion efficiency of 20%, 5 x .061 = .305 MCF/day
natural gas or 5 x .0101 = .0505 bbls/day diesel oil will be required for each
HP-day.
'Approximately: 1 bbl diesel oil = 6000 Btu
1 bbl crude oil - 5850 Btu
1 MCF natural gas - 1000 Btu
VI-56
-------
FIGURE VI-3
POWER REQUIREKZ'ITS
FOR BRINE TREATMENT SYSTEMS
1201-
100
80
z
UJ
a: i-
l-H 0)
cr 6
UJ Q-
0£ (1)
01
a: i.
ui o
60
40
20
Flotation
Loose Media Coalescer
10,000 20,000 30,000
BRINE CAPACITY (BPD)
40,000
50,000
NOTES: 1.
2.
Flotation power requirements are based on an induced gas
flotation device and includes power for operating motors.
Loose media coalescer power requirements are based on
power for influent, flush, and flush water disposal pumps.
OFFSHORE OPERATORS
COMMITTEE
VI-57
-------
Direct energy effectiveness, as used here, is the ratio of number
of barrels of crude oil recovered by treatment over number of barrels of diesel
oil equivalent required by the treatment (and reinjection) equipment.
Using these values it is estimated that by treatment with flotation
units, on the average, 1 barrel of diesel oil equivalent will have to be
consumed for treatment of 6850 barrels of water to recover 1.4 barrels of crude
oil.
When treated formation waters are reinjected, then only .13 barrels
of crude oil will be recovered for each barrel of diesel oil required for
treatment plus reinjection of 719 barrels of water.
In terms of natural gas the requirement would be for 1 MCF natural
gas to recover 0.23 barrel of crude oil from 1141 barrels of treated formation
water. However, 1 MCF natural gas will only treat and reinject 120 barrels of
formation water from which .022 barrels of crude oil will be recovered.
This analysis estimates the total energy recovery from the BPCTCA
treatment system. The analysis is not intended to represent the incremental
energy recovery from the application of the BPCTCA guidelines. The platforms
in federal waters presently are under a 50 ppm long-term average requirement
of the USGS. Thus, the incremental oil recovery resulting from compliance
with the BPCTCA requirement is 23 ppm per barrel of formation water treated.
VI-58
-------
,VI.9. ECONOMIC COST PER BARREL RECOVERED
Given the fact, shown in the previous section, that on the average
the treatment equipment expected to be installed in 1977 will recover more
energy than it consumes, it was of interest to consider the economic cost
of the average additional barrel recovered by the BPCTCA facilities.(See Table VI-22
and Table VI- 23.) For the calculation of this economic cost it was assumed
that producers would expect to recover their investment plus a return on
that investment over a period of 15 years in addition to net after tax operating
costs incurred for the treatment equipment during that same period.
An estimate of maximum and minimum number of barrels of oil
recovered during the 15 years considered was made.
The minimum estimate was based on the average water/oil and water/gas
ratio in 1974 of all platforms considered, assuming that this ratio would not
increase during the next 18 years.
The maximum estimate was obtained assuming that platforms would
produce the maximum amount of water considered to be possible based on the
engineering considerations and analysis of actual water/oil and water/gas
ratios as discussed in the previous chapter.
Minimum and maximum amount of oil recovered was calculated using the
average recovery factor of 2 barrels of oil per 10,000 barrels of water
treated as derived in the previous section.
Using investment and operating cost estimates developed in previous
sections, the capital charge and total increase in after tax operating costs
Economic cost is supposed to mean the average cost per barrel recovered
allowing for the additional operating and investment costs which have to
be incurred for recovery equipment.
VI-59
-------
for the 15-year period could be calculated. The sum of these two cost
items divided by the total number of barrels recovered during the 15 years
resulted in the estimate of minimum and maximum economic cost per barrel of
oil recovered (See Table VI- 22 and Table VI-23 ). The results show that:
• For federal waters the economic cost per barrel recovered by
treatment of produced formation water will range from $94 to $2382
for oil producing units and from $42 to $4511 for gas producing
units.
• For state waters the economic cost per barrel recovered will
range from $36 to $1237 for oil producing units and from $133 to
$2984 for gas producing units.
Reinjection is not really part of the treatment installation but it could be
argued that the barrels of oil recovered by treatment should also pay for the
additional costs incurred for reinjection in state waters starting in 1983.
Therefore, the economic cost per barrel recovered was also calculated for
reinjection facilities, which may be required in 1983. The range of $371 to
$8321 for oil producing facilities and $808 to $17741 for gas producing
facilities (see Table VI-19) derived as the economic cost per barrel of oil
recovered for treatment and reinjection installations, shows that the
reinjection requirement increases the economic cost by about a factor of nine.
Vl-60
-------
TABLE VI -
Economic Cost per Barrel of Oil Recovered
Federal Waters
(1974 Dollars)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Cumulative Production (15 yrs . ) (MMB/MM
(a)
Minimum^ Water Production (MMB)
Minimum Oil Recovered (MB)
Maximum Water Production (MMB)
Maximum Oil Recovered (MB)
Investment (MM$)
Capital Charge (6x 2.8)(MM$)
Added Op. Costs (15 yrs.)(MM$)
Added Dep. Charge (15 yrs.)(MM$)
Net Increase in Op. Cost (8-9) (MM$)
Oil
1977
MCF) 1296. 5
648.3
129.7
6555.9
1311.0
40
112.0
51
40
11
Wells
1983
N/A
- 100
- 280
- 129
- 100
- 29
Gas
1977
11328.5
85.0
17.0
1891.9
378.4
5
14.0
6.8
5
1.8
Wells
1983
N/A
- 25
- 70
-31.7
- 25
- 6.7
11. Minimum EC. Cost per Bbl Recovered
((741Q)/5)($/B)
12. Maximum EC. Cost per Bbl Recovered
((7+10)/3)($/B)
13. EC. Cost Range ($/B Recovered)
94
2382
94 - 2382
42
4511
42 - 4511
(a)
(b)
Assuming 0.5 Bbl water per Bbl of oil and .0075 Bbl water per MCF gas in 1977,
Assuming (oil prod. + water prod./.7) = constant and .167 Bbl water per
gas in 1977.
SOURCE: Arthur D. Little, Inc., estimates
VI-61
-------
' AdLE \ I -2j
Economic Cost rcr_ Bai :el 01 Oil Recovered
v-tate
(1974 Do Liars
DATE DUE
Cumulative Production (15 yrs.)
(MMB or MM MCF)
(a)
>.. Minimum Water Production (MMB)
3. Minimum Oil Recovered (MB)
Maximum Water Production (MMB)
Maximum Oil Recovered (MB)
r>. Investment (MM$)
7. Capital Charge (6x 2.80) (MM$)
8. Added Op. Costs (15 yrs.)(MM$)
9. Added Dep. Charge (15 yrs.)(MM$)
Jl-_ _Net Increase in Op. Costs
U.-5-X (3-9) (MM$)
1. EC. Cost per Bbl Recovered ($/B)
Oil Wells
Gas Wells
1977
342.3
171.2
34.2
5882.0
1176
13.5
37.8
18
13.5
1983
137.1
68.6
13.7
1537.0
307
35
98
51
35
1977
4228.4
31.7
6,3
/06.0
141
5.8
16.3
8.3
5.8
1983
2051.9
15.4
3.1
342.0
68
15.5
43.5
27
15.5
4.5
16
2.5
11.5
36 - 1237 371 - 8321 133 - 2984 808 - 17741
(a)
(b)
Assuming 0.5 Bbl water per Bbl of oil and .0075 Bbl water per MCF gas in 1977.
Assuming (oil prod. + water prod./.7) = constant and .167 Bbl water per Bbl MCF
gas in 1977.
SOURCE; Arthur D. Little, Inc., estimates
U,-. dn-^oumenU! Election Agen«
pv -ion V. U'orary ---"
230 South Dearborn Street ,
Chicrgo, Illinois 60bu4
VI-62
------- |