United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park, NC 27711
FINAL REPORT
EPA-453/R-96-016
November 1996
Air
?* EPA ECONOMIC IMPACT ANALYSIS
OF THE PROPOSED
OIL AND NATURAL GAS
NESHAPs
Final Report
-------
Economic Impact Analysis
of the Proposed
Oil and Natural Gas NESHAP
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and Standards
Air Quality Strategies and Standards Division
MD-15; Research Triangle Park, N.C. 27711
Prepared under contract by:
Research Triangle Institute
3040 Cornwallis Road
P.O. Box 12194
Research Triangle Park, N.C. 27709-2194
Final Report
November 1996
U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12Ul Floor
Chicago, IL 60604-3590
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Disclaimer
This report is issued by the Emission Standards Division of
the Office of Air Quality Planning and Standards of the U.S.
Environmental Protection Agency (EPA). It presents technical
data on the National Emission Standard for Hazardous Air
Pollutants (NESHAP), which is of interest to a limited number
of readers. It should be read in conjunction with the
Background Information Document (BID) for Proposed Air
Emission Standards on the Oil and Natural Gas Production and
Natural Gas Transmission and Storage source categories (July
1996). Both the Economic Impact Analysis and the BID are in
the public docket for the NESHAP proposal. Copies of these
reports and other material supporting the proposal are in
Docket A-94-04 at EPA's Air and Radiation Docket and
Information Center, Waterside Mall, Room M1500, Central Mall,
501 M Street, SW, Washington, DC 20460. The EPA may charge a
reasonable fee for copying. Copies are also available through
the National Technical Information Services, 5285 Port Royal
Road, Springfield, VA 22161. Federal employees, current
contractors and grantees, and nonprofit organizations may
obtain copies from the Library Services Office (MD-35), U.S.
Environmental Protection Agency, Research Triangle Park, NC
27711; phone (919) 541-2777.
11
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TABLE OF CONTENTS
Section Page
List of Figures vii
List of Tables ix
List of Acronyms xi
List of Definitions xiii
Executive Summary xvii
ES.l Industry Profile . xvii
ES.2 Regulatory Control Options and Costs . . . xix
ES.3 Economic Impact Analysis xx
ES.4 Regulatory Flexibility Analysis .... xxiii
1 Introduction 1-1
1.1 Scope and Purpose 1-1
1.2 Organization of the Report 1-2
2 Industry Profile 2-1
2.1 Production Processes 2-2
2.1.1 Production Wells and
Extracted Products 2-2
2.1.2 Dehydration Units 2-5
2.1.3 Tank Batteries 2-6
2.1.4 Natural Gas Processing
Plants 2-8
2.1.5 Natural Gas Transmission and
Storage Facilities 2-9
2.2 Products and Markets 2-9
2.2.1 Crude Oil 2-9
2.2.1.1 Reserves 2-9
2.2.1.2 Domestic Production . . 2-9
2.2.1.3 Domestic Consumption . . 2-13
2.2.1.4 Foreign Trade 2-13
2.2.1.5 Future Trends 2-16
2.2.2 Natural Gas 2-16
2.2.2.1 Reserves 2-16
2.2.2.2 Domestic Production . . 2-18
2.2.2.3 Domestic Consumption . 2-21
2.2.2.4 Foreign Trade . . . . . 2-21
2.2.2.5 Future Trends 2-23
2.3 Production Facilities 2-26
2.3.1 Production Wells 2-26
2.3.1.1 Gruy Engineering
Corporation Database . . 2-29
2.3.2 Dehydration Units 2-29
iii
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TABLE OF CONTENTS (continued)
Section Page
2.3.3 Tank Batteries 2-30
2.3.4 Natural Gas Processing
Plants 2-30
2.3.5 Natural Gas Transmission and
Storage Facilities 2-31
2.4 Firm Characteristics 2-31
2.4.1 Ownership 2-32
2.4.2 Size Distribution 2-33
2.4.3 Horizontal and Vertical
Integration 2-34
2.4.4 Performance and Financial
Status . 2-36
3 Regulatory Control Options and Costs of
Compliance 3-1
3.1 Model Plants 3-1
3.1.1 TEG Dehydration Units 3-2
3.1.2 Condensate Tank Batteries .... 3-3
3.1.3 Natural Gas Processing
Plants 3-4
3.1.4 Offshore Production Platforms . . 3-5
3.2 Control Options 3-6
3.3 Costs of Controls 3-8
4 Economic Impact Analysis 4-1
4.1 Modeling Market Adjustments 4-3
4.1.1 Facility-Level Effects 4-3
4.1.2 Market-Level Effects 4-6
4.1.3 Facility-Level Response to Control
Costs and New Market Prices ... 4-7
4.2 Operational Market Model 4-8
4.2.1 Network of Natural Gas Production
Wells and Facilities 4-9
4.2.1.1 Allocation of Production
Fields to Natural Gas
Processing Plants . . . 4-10
4.2.1.2 Assignment of Model Units 4-13
4.2.2 Supply of Natural Gas 4-15
4.2.2.1 Domestic Supply . . . , 4-15
4.2.2.2 Foreign 4-20
4.2.2.3 Market Supply 4-21
4.2.3 Demand for Natural Gas 4-22
4.2.4 Incorporating Regulatory Control
Costs 4-24
4.2.4.1 Affected Entities . . . 4-24
4.2.4.2 Natural Gas Supply
Decisions 4-25
IV
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Section
TABLE OF CONTENTS (continued)
Page
4.2.5 Model Baseline Values and Data
Sources 4-26
4.2.6 Computing Market Equilibria . . . 4-26
4.3 Regulatory Impact Estimates 4-29
4.3.1 Market-Level Results 4-29
4.3.2 Industry-Level Results 4-29
4.3.2.1 Pos t-Regulatory
Compliance Cost .... 4-32
4.3.2.2 Revenue, Production Cost,
and Profit Impacts . . . 4-33
4.3.3 Economic Welfare Impacts 4-34
5 Firm-Level Analysis 5-1
5.1 Analyze Owners' Response Options .... 5-3
5.2 Financial Impacts of the Regulation . . 5-5
5.2.1 Baseline Financial
Statements 5-7
5.2.2 With-Regulaticn Financial
Statements 5-8
5.2.3 Profitability Analysis 5-16
References R-l
Appendix
A Gruy Engineering Corporation's Oil
Wellgroups by State A-l
B Gruy Engineering Corporation's Gas
Wellgroups by State B-l
C Derivation and Interpretation of Supply
Function Parameter £ C-l
D Natural Gas Market Model Summary D-l
E Approach to Estimating Economic Welfare Impacts E-l
F Data Summary of Companies Included in
Firm-Level Analysis: 1993 F-l
v
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LIST OF FIGURES
Number Page
2-1 Crude oil and natural gas production flow diagram 2-3
2-2 Summary of processes at a tank battery .... 2-7
2-3 Summary of processes at natural gas processing
plant 2-8
4-1 Facility unit cost functions 4-5
4-2 Effect of compliance costs on facility
cost functions . 4-6
4-3 Natural gas market equilibria with and without
compliance costs 4-7
4-4 Theoretical supply function of natural gas
producing well 4-19
5-1 Characterization of owner responses to
regulatory action 5-6
5-2 Distribution of total annual compliance
cost to sales ratio for sample companies . . . 5-12
VI1
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Vlll
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LIST OF TABLES
Number Page
ES-1 Summary of Annual Control Costs for Major
and Area Sources by Model Plant xx
ES-2 Summary of Selected Economic Impact Results
by Regulatory Scenario xxii
2-1 Total U.S. Proved Reserves of Crude Oil,
1976 Through 1993 2-11
2-2 U.S. Crude Oil Reserves by State and Area,
1993 2-12
2-3 U.S. Crude Oil Production, 1982-1992 2-13
2-4 Total U.S. Crude Oil Consumption and Price
Levels, 1980-1992 2-14
2-5 Summary of U.S. Foreign Trade of Crude Oil,
1983-1992 2-15
2-6 Supply, Demand, and Price Projections for
Crude Oil, 1990-2010 2-16
2-7 U.S. Proved Reserves of Dry Natural
Gas, 1976 Through 1993 2-17
2-8 U.S. Natural Gas Reserves by State and Area,
1993 2-19
2-9 U.S. Natural Gas Production and Wellhead
Price Levels, 1980-1992 2-20
2-10 U.S. Natural Gas Consumption by End-Use
Sector, 1980-1992 2-22
2-11 U.S. Natural Gas Price by End-Use Sector,
1980-1992 2-23
2-12 Historical Summary of U.S. Natural Gas
Foreign Trade, 1973-1993 2-24
2-13 Supply, Demand, and Price Projections for
Natural Gas, 1993-2010 2-25
2-14 Number of Crude Oil and Natural
Gas Wells, 1983-1992 2-26
2-15 U.S. Onshore Oil and Gas Well Capacity by
Size Range, 1989 2-27
2-16 Distribution of U.S. Gas Wells by State, 1993 . 2-28
2-17 U.S. Natural Gas Processing
Facilities, 1987-1993 2-31
2-18 U.S. Natural Gas Processing Plants, Capacity,
and Throughput as of January 1, 1994,
by State 2-32
2-19 Firm Size for SIC 1311 by Range
of Employees, 1992 2-34
2-20 Top 20 Oil and Natural Gas Companies, 1993 . . 2-37
2-21 Performance Measures for OGJ Group, 1993 . . . 2-39
2-22 Performance of Top 10 Gas Pipeline
Companies, 1994 2-39
3-1 Model TEG Dehydration Units 3-3
3-2 Model Condensate Tank Batteries 3-4
ix
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LIST OF TABLES (Continued)
Number Page
3-3 Model Natural Gas Processing Plants 3-5
3-4 Model Offshore Production Platforms 3-6
3-5 Summary of Control Options by Model Plant and
HAP Emission Point 3-7
3-6 Total and Affected Population of TEG Units by
Model Type 3-8
3-7 Total and Affected Population of Condensate
Tank Batteries by Model Type 3-9
3-8 Total and Affected Population of Natural Gas
Processing Plant by Model Type 3-9
3-9 Regulatory Control Costs per Unit for the Oil
and Natural Gas Production Industry by Control
Option and Model Plant '. . 3-10
3-10 Summary of Annual Costs for Major and
Area Sources by Model Plant 3-13
4-1 List of States by Exchange Status of Natural
Gas, 1993 4-12
4-2 Summary of Allocation of Production Wells,
Processing Plants, and Model Units for 1993
by State 4-16
4-3 Short-Run Supply Elasticity Estimates for
Natural Gas by EPA Region 4-20
4-4 Short-Run Demand Elasticity Estimates for
Natural Gas by End-User Sector 4-23
4-5 Baseline Equilibrium Values for Economic
Model: 1993 4-27
4-6 Summary of Natural Gas Market Adjustments
by Regulatory Scenario 4-30
4-7 Industry-Level Impacts by Regulatory Scenario . 4-32
4-8 Economic Welfare Impacts by Regulatory
Scenario 4-35
5-1 SBA Size Standards by SIC Code for the Oil
and Natural Gas Production Industry 5-3
5-2 Dun and Bradstreet's Benchmark Financial
Ratios by SIC Code for the Oil and Natural
Gas Production Industry 5-9
5-3 Distribution of Model TEG Units by Firm's
Level of Natural Gas Production 5-11
5-4 Calculations Required to Set up
With-Regulation Financial Statements 5-14
5-5 Key Measures of Profitability 5-17
5-6 Summary Statistics for Key Measures of
Profitability in Baseline and With
Regulation by Firm Size Category 5-18
x
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LIST OF ACRONYMS
API American Petroleum Institute
ATAC Average total (avoidable) cost
Bcf Billion cubic feet
BID Background information document
BOE Barrels of oil equivalent
BOPD Barrels of oil per day
bpd Barrels per day
BTB Black oil tank battery
Btu British thermal unit
cf (d) Cubic feet (per day)
CIS Commonwealth of Independent States
CTB Condensate tank battery
D&B Dun and Bradstreet
DEC Diethylene glycol
DOE Department of Energy
EG Ethylene glycol
EIA Energy Information Administration
FERC Federal Energy Regulatory Commission
GRI Gas Research Institute
HAPs Hazardous air pollutants
IPAA Independent Petroleum Association of America
ISEG The Innovative Strategies and Economics Group
LDAR Leak detection and repair
xi
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LPG Liquid petroleum gas
MACT Maximum achievable control technology
Mbpd Thousand barrels per day
MC Marginal cost
Mcf(d) Thousand cubic feet (per day)
Mmbpd Million barrels per day
MMBtu Million British thermal units
MMcf(d) Million cubic feet (per day)
MMS Minerals Management Service
NAFTA North American Free Trade Agreement
NESHAP National Emission Standard for Hazardous Air
Pollutants
NGL Natural gas liquids
NGPA Natural Gas Policy Act
NGPP Natural gas processing plant
OGJ Oil and Gas Journal
OPEC Organization of Petroleum Exporting Countries
RCRA Resource Conservation and Recovery Act
SBA Small Business Administration
SIC Standard Industrial Classification
TB Tank battery
Tcf (d) Trillion cubic feet (per day)
TEG Triethylene glycol
TREG Tetraethylene glycol
xn
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LIST OF DEFINITIONS
API Gravity--the gravity adopted by American Petroleum
Institute for measuring the density of a liquid, expressed in
degrees. It is converted from specific gravity by the
following equation:
Degrees API gravity = 141.5/specific gravity - 131.5
Black Oil Tank Battery--the collection of process equipment
used to separate, treat, store, and transfer streams from
production wells primarily consisting of crude oil with
little, if any, natural gas.
City Gate—the final destination of gas products prior to
direct distribution to end users, such as homes, businesses,
and industries.
Condensate Tank Battery--The collection of process equipment
used to separate, treat, store, and transfer streams from
production wells consisting of condensate and natural gas.
Condensates--hydrocarbons that are in a gaseous state under
reservoir conditions (prior to production), but that become
liquid during the production process.
Dry Gas—natural gas whose water content has been reduced
through dehydration, or natural gas that contains little or no
commercially recoverable liquid hydrocarbons.
End-user Price—the delivered price paid by residential,
commercial, industrial, and electric utility consumers for
natural gas.
Extracted Stream—the untreated mixture of gas, oil,
condensate, water, and other liquids recovered at the
wellhead.
Glycol Dehydration--absorption process in which a liquid
absorbent, a glycol, directly contacts the natural gas stream
and absorbs water vapor in a contact tower or absorption
column. The glycol becomes saturated with water and is
Introduction to Oil and Gas Production. American Petroleum
Institute. 1983.
xiii
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circulated through a boiler where the water vapor is boiled
off.
Gruy "Wellgroups"—Gruy Engineering Corp. developed
"wellgroups, " or model production wells, for both oil and gas
wells in 37 areas across the U.S. For each geographic area,
wellgroups are defined by well depth ranges and by production
rate in each depth range.
Natural Gas Processing Plant--a facility designed to (1)
achieve the recovery of natural gas liquids from the stream of
natural gas, which may or may not have been processed through
lease separators and field facilities, and (2) control the
quality of the natural gas to be marketed.*
Natural Gas--a mixture of hydrocarbons and varying quantities
of nonhydrocarbons that exist either in gaseous phase or in
solution with crude oil from underground reservoirs.
Offshore Production Platforms—facilities used to produce,
treat, and separate crude oil, natural gas, and produced water
in offshore areas.
Producing Field--an area consisting of a single reservoir or
multiple reservoirs all grouped on, or related to, the same
geological structure feature and/or stratigraphic condition.*
Production Well—a hole drilled into the earth, usually cased
with pipe for the recovery of crude oil, condensate, and
natural gas.
Proved Crude Oil Reserves—the estimated amount of crude oil
that can be found and developed in future years from known
reservoirs under current prices and technology.
Proved Natural Gas Reserves—the estimated amount of gas that
can be found and developed in future years from known
reservoirs under current prices and technology.
Pump Stations—facilities designed to transport crude oil from
tank batteries to refineries.
Stripper Wells—those production wells that produce less than
10 bpd or 60 Mcf per day.
Wellhead Price—represents the wellhead sales price, including
charges for natural gas plant liquids subsequently removed
from the gas, gathering and compression charges, and State
production, severance, and/or similar charges.
Introduction to Oil and Gas Production. American Petroleum
Institute. 1983.
xiv
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Wet Gas—unprocessed or partially processed natural gas
produced from a reservoir that contains condensable
hydrocarbons.
xv
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EXECUTIVE SUMMARY
The petroleum industry is divided into five distinct
sectors: (1) exploration, (2) production, (3) transportation,
(4) refining, and (5) marketing. The proposed National
Emission Standard for Hazardous Air Pollutants (NESHAP)
establishes controls for the products and processes of the
production and transportation sectors of the petroleum
industry. Specifically, the oil and natural gas production
and natural gas transmission and storage source categories
include the separation, upgrading, storage, and transfer of
extracted streams that are recovered from production wells.
Thus, it includes the production and custody transfer up to
the refinery stage for crude oil and up to the city gate for
natural gas. This report evaluates the economic impacts of
additional pollution control requirements for the oil and
natural gas production and natural gas transmission and
storage source categories that are designed to control
releases of hazardous air pollutants (HAPs) to the atmosphere.
ES.l INDUSTRY PROFILE
Production occurs within the contiguous 48 United States,
Alaska, and at offshore facilities in Federal and State
waters. In the production process, extracted streams from
production wells are transported from the wellhead (through
offshore production platforms in the case of offshore wells)
to tank batteries for separation of crude oil, natural gas,
condensates, and water from the product. Crude oil products
are then transported to refineries, while natural gas products
are directed to gas processing plants and then to final
transmission lines at city gates. The equipment required in
xvii
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the production of crude oil and natural gas includes
production wells (including offshore production platforms),
dehydration units, tank batteries, natural gas processing
plants, and underground storage facilities.
Because oil is an international commodity, the U.S.
production of crude oil is affected by the world crude oil
price, the price of alternative fuels, and existing
regulations. Domestic oil production is currently in a state
of decline that began in 1970. U.S. production in 1992
totaled only 7.2 million barrels per day (MMbpd)--the lowest
level in 30 years.
Natural gas production trends are distinct from those of
crude oil. Production has been increasing since 1986 mainly
due to open access to pipeline transportation that has
resulted in more marketing opportunities for producers and
greater competition, leading to higher production. Also
contributing to the increase in production are significant
improvements in drilling productivity as well as more
intensive utilization of existing fields since 1989. Natural
gas consumers include residential and commercial customers, as
well as industrial firms and electric utilities. Since 1986,
natural gas consumption has shown relatively steady growth,
which is projected to continue through the year 2010.
The oil and natural gas production industry is
characterized by large (major) oil companies on one level and
smaller independent producers on another level. Because of
the existence of major oil companies, the industry possesses a
wide dispersion of vertical and horizontal integration.
Several oil companies achieve full vertical integration in
that they own and operate facilities that are involved in each
of the five sectors within the petroleum industry.
Independent companies, by definition, are involved in only a
subset of these five sectors. Horizontal integration also
XVlll
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exists in that major and independent firms may own and operate
several crude oil and natural gas production and processing
facilities.
ES.2 REGULATORY CONTROL OPTIONS AND COSTS
The Background Information Document (BID) details the
technology basis for the national emission standards on major
and area sources. Model plants were developed to evaluate the
effects of various control options on the oil and natural gas
production industry- Selection of control options was based
on the application of presently available control equipment
and technologies and varying levels of capture consistent with
different levels of overall control. The BID presents a
summary of the control options for each of the following model
plants:
• triethylene glycol (TEG) dehydration units,
• condensate tank batteries (CTB)
• natural gas processing plants (NGPP), and
• offshore production platforms (OPP).
Table ES-1 summarizes the annual compliance costs
associated with the regulatory requirements for each model
plant by source category. Major sources of HAP emissions are
controlled based on the MACT floor, as defined in the BID.
The Agency has determined that a glycol dehydration unit must
be collocated at a facility for that facility to be designated
as a major source. Therefore, the MACT floor may apply to
stand-alone TEG units, condensate tank batteries, and natural
gas processing plants. Black oil tank batteries and offshore
production platforms are not considered since TEG units are
not typical of the operations at black oil tank batteries and
are completely controlled at offshore production platforms.
EPA has also determined a need to control area sources based
on GACT standards. Thus, area sources will be required to
place controls on model TEG units with natural gas throughput
xix
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TABLE ES-1.
SUMMARY OF ANNUAL CONTROL COSTS FOR MAJOR AND
AREA SOURCES BY MODEL PLANT
Cost per model unit
Model Plant
Major source
Area source
TEG dehydration units
TEG-A
TEG-B
TEG-C
TEG-D
TEG-E
Condensate tank batteries
CTB-E
$12,989
$12,937
$12,790
$12,790
$12,088
CTB-F
CTB-G
CTB-H
Natural gas processing plants
NGPP-A
NGPP-B
NGPP-C
$19,660
$24,973
$25,071
$46,747
$61,823
$81,083
—
—
• —
—
—
—
between 3 and 5 MMcfd that emit 1 mg or more of benzene per
year.
ES.3 ECONOMIC IMPACT ANALYSIS
This economic impact analysis assesses the market-,
facility-, and industry-level impact of the proposed NESHAP on
the oil and natural gas production industry. According to the
BID, black oil tank batteries will not incur control costs so
that only condensates processed at condensate tank batteries
will be directly affected by the regulation. Condensates
represent less than 5 percent of total U.S. crude oil
production.* Thus, this analysis does not include a model to
assess the regulatory effects on the world crude oil market
because the anticipated changes in the U.S. supply are not
likely to influence world prices. Consequently, the economic
'Oil and Natural Gas Production: An Industry Profile. U.S.
Environmental Protection Agency, OAQPS, Research Triangle Park, NC. October
1994. p. 4.
XX
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analysis focuses on the regulatory effects on the U.S. natural
gas market that is modeled as a national, perfectly
competitive market for a homogeneous commodity.
To estimate the economic impacts of the regulation, a
multi-dimensional Lotus spreadsheet model was developed
incorporating various data sources to provide an empirical
characterization of the U.S. natural gas industry for a base
year of 1993--the latest year for which supporting technical
and economic data were available. The exogenous shock to the
economic model is the imposition of the regulations and the
corresponding control costs.
A competitive market structure was incorporated to
compute the equilibrium prices (wellhead and end user) at
which the supply and demand balance for natural gas output.
Domestic supply is represented by a detailed characterization
of the production flow of natural gas through a network of
production wells and processing facilities. Demand for
natural gas by end-use sector is expressed in equation form,
incorporating estimates of demand elasticities from the
economic literature. Although the model includes a foreign
component of U.S. natural gas supply (i.e., imports), it does
not incorporate U.S. exports of natural gas that are observed
at insignificant levels. The model analyzes market
adjustments associated with the imposition of the regulation
by employing a process of tatonnement whereby prices approach
equilibrium through successive correction modeled as a
Walrasian auctioneer.
As presented in Table ES-2, the major outputs of this
model are market-level impacts, including price and quantity
adjustments for natural gas and the impacts on foreign trade,
and industry-level impacts, including the change in revenues
and costs, adjustments in production, closures, and changes in
employment. The market adjustments associated with the
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TABLE ES-2. SUMMARY OF SELECTED ECONOMIC IMPACT
RESULTS BY REGULATORY SCENARIO
Item
Market-level impacts
Prices (%)
Wellhead
End-user
Domestic production (%)
Industry-level impacts
Change in revenues ($106)
Change in costs (10*)
Change in profits ($106)
Closures
Production wells
Natural gas processing plants
Employment losses
Economic welfare impacts ($106)
Change in consumer surplus
Change in producer surplus
Domestic
Foreign
Change in economic welfare
Major and
area
sources
0
0
-0
$3
$18
-$15
0
0
0
-$o
-$15
-$15
$0
-$16
.0012%
.0006%
.0004%
.2
.7
.5
.5
.5
.5
.1
.0
Major
sources
only
0
0
-0
$3
$7
-$4
0
0
0
-$o
-$4
-$4
$0
-$4
.0008%
.0004%
.0003%
.0
.4
.4
.3
.3
.4
.1
.6
Area
sources
only
0.
0.
-0.
$0.
$11.
-$11
0
0
0
-SO.
-$11
-$11
$0
-$11
0004%
0002%
0001%
2
3
.2
2
.1
.2
.3
regulation are negligible in percentage terms (less than 0.01
percent) as well as in comparison to the observed trends in
the U.S. natural gas market. For example, between 1992 and
1993, the average annual wellhead price increased by 14
percent, while domestic production of natural gas rose by 3
percent.
Furthermore, the market adjustments in price and quantity
allow calculation of the economic welfare impacts (i.e.,
changes in the aggregate economic welfare as measured by
consumer and producer surplus changes). These estimates
represent the social cost of the regulation. For major and
area sources combined, the annual social cost of the
regulation is $16 million. This measure of social cost is
preferred to the national cost estimates from the engineering
analysis because it accounts for the market adjustments and
xxi i
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the associated deadweight loss to society of the reallocation
of resources.
ES.4 REGULATORY FLEXIBILITY ANALYSIS
Environmental regulations such as the proposed NESHAP for
the oil and natural gas production and the natural gas
transmission and storage industry affect all businesses, large
and small, but small businesses may have special problems in
complying with such regulations. The Regulatory Flexibility
Act (RFA) of 1980 requires that special consideration be given
to small entities affected by Federal regulation. Under the
1992 revised EPA guidelines for implementing the Regulatory
Flexibility Act, an initial regulatory flexibility analysis
(IRFA) and a final regulatory flexibility analysis (FRFA) will
be performed for every rule subject to the Act that will have
any economic impact, however small, on any small entities that
are subject to the rule, however few, even though EPA may not
be legally required to do so. The Small Business Regulatory
Enforcement Fairness Act (SBREFA) of 1996 further amended the
RFA by expanding judicial and small business review of EPA
rulemaking. Although small business impacts are expected to
be minimal due to the size cutoff for TEG dehydration units,
this firm-level analysis addresses the RFA requirements by
measuring the impacts on small entities.
Potentially affected firms include entities that own
production wells and/or processing plants and equipment
involved in oil and natural gas production. Small firms
involved exclusively in the natural gas transmission source
category are not likely to be affected by the proposed rule.
Based on financial information from the Oil and Gas Journal
and financial ratios from Dun and Bradstreet, this analysis
characterizes the financial status of a sample of 80 firms
potentially affected by the regulation. Firms in this sample
include major and independent producers of oil and natural gas
in addition to interstate pipeline and local distribution
companies primarily involved in natural gas. According to
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Small Business Administration general size standard
definitions for SIC codes, a total of 39 firms included in
this analysis, or 48.8 percent, are defined as small. With
regulation, the change in measures of profitability are
minimal with no overall disparity across small and large
firms, while the likelihood of financial failure is unaffected
for both small and large firms. Therefore, there is no
evidence of any disproportionate impacts on small entities due
to the proposed NESHAP on the oil and natural gas production
industry.
xxiv
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SECTION 1
INTRODUCTION
The U.S. Environmental Protection Agency (EPA or the
Agency) is developing an air pollution regulation for reducing
emissions generated by the oil and natural gas production and
natural gas transmission and storage source categories. EPA
has developed a National Emission Standard for Hazardous Air
Pollutants (NESHAP) for each category of major and area
sources under the authority of Section 112(d) of the Clean Air
Act as amended in 1990. The Innovative Strategies and
Economics Group (ISEG) of EPA contributes to this effort by
providing analyses and supporting documents that describe the
likely economic impacts of the proposed standards on directly
and indirectly affected entities.
1.1 SCOPE AND PURPOSE
This report evaluates the economic impacts of pollution
control requirements for the oil and natural gas production
and natural gas transmission and storage source categories
that are designed to control releases of hazardous air
pollutants (HAPs) to the atmosphere. The Clean Air Act's
purpose is "to protect and enhance the quality of the Nation's
air resources" (Section 101[b]). Section 112 of the Clean Air
Act as amended in 1990 establishes the authority to set
national emission standards for the 189 HAPs listed in this
section of the Act.
A major source is defined as a stationary source or group
of stationary sources located within a contiguous area and
under common control that emits, or has the potential to emit
considering control, 10 tons or more of any one HAP or 25 tons
1-1
-------
or more of any combination of HAPs. An area source is any
stationary source that is not a major source. Special
provisions in Section 112(n)(4) for oil and gas wells and
pipeline facilities affect major source determinations for
these facilities and also indicate under what circumstances
the Agency may regulate oil and gas production wells as an
area source category.
For HAPs, the Agency establishes Maximum Achievable
Control Technology (MACT) standards. The term "MACT floor"
refers to the minimum control technology on which MACT can be
based. For existing major sources, the MACT floor is the
average emissions limitation achieved by the best performing
12 percent of sources (if the category or subcategory includes
30 or more sources), or the best performing five sources (if
the category or subcategory includes fewer than 30 sources).
MACT can be more stringent than the floor, considering costs,
nonair quality health and environmental impacts, and energy
requirements. The Clean Air Act gives discretion to the
Agency when setting standards under Section 112(d) for area
sources. Standards for area sources may be based either on
MACT, as for major sources, or on generally available control
technology (GACT).
1.2 ORGANIZATION OF THE REPORT
The remainder of this report is divided into four
sections that support and provide details on the methodology
and results of this analysis. The sections include the
following:
• Section 2 introduces the reader to the oil and natural
gas production and natural gas transmission and
storage source categories. It begins with an overview
of the oil and natural gas industry and presents data
on products and markets, production units, and the
companies that own and operate the production and
storage units.
1-2
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Section 3 reviews the model plants, regulatory control
options, and associated costs of compliance as
detailed in the draft Background Information Document
(BID) prepared in support of the proposed regulations.
Section 4 describes the methodology for assessing the
economic impacts of the proposed regulation and the
analysis results.
Section 5 explains the methodology for assessing the
company-level impacts of the proposed regulation
including an initial regulatory flexibility analysis
to evaluate the small business effects of the
regulation.
1-3
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SECTION 2
INDUSTRY PROFILE
The petroleum industry is divided into five distinct
sectors: (1) exploration, (2) production, (3) transportation,
(4) refining, and (5) marketing. The NESHAP considers
controls for the products and processes of the production and
transportation sectors of the petroleum industry.
Specifically, the oil and natural gas production and natural
gas transmission and storage source categories include the
separation, upgrading, storage, and transfer of extracted
streams that are recovered from production wells. Thus, it
includes the production and custody transfer up to the
refining stage for crude oil and up to the city gate for
natural gas.
Most crude oil and natural gas production facilities are
classified under SIC code 1311—Crude Oil and Natural Gas
Exploration and Production, while most natural gas
transmission and storage facilities are classified under
SIC 4923—Natural Gas Transmission and Distribution. The
outputs of the oil and natural gas production industry—crude
oil and natural gas—are the inputs for larger production
processes of gas, energy, and petroleum products. In 1992, an
estimated 594,189 crude oil wells and 280,899 natural gas
production wells operated in the United States. U.S. natural
gas production was 18.3 trillion cubic feet (Tcf) in 1993,
continuing the upward trend since 1986, while U.S. crude oil
production in 1992 was 7.2 million barrels per day (MMbpd),
which is the lowest level in 30 years. The leading domestic
oil and gas producing states are Alaska, Texas, Louisiana,
California, Oklahoma, New Mexico, and Kansas.
2-1
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The remainder of this section provides a brief
introduction to the oil and natural gas production industry.
The purpose is to give the reader a general understanding of
the technical and economic aspects of the industry that must
be addressed in the economic impact analysis. Section 2.1
provides an overview of the oil and natural gas production
processes employed in the U.S. with an emphasis on those
affected directly by the regulation. Section 2.2 presents
historical data on crude oil and natural gas including
reserves, production, consumption, and foreign trade. Section
2.3 summarizes the number of production facilities by type,
location, and other parameters, while Section 2.4 provides
general information on the potentially affected companies that
own oil and natural gas production facilities.
2.1 PRODUCTION PROCESSES
Production occurs within the contiguous 48 United States,
Alaska, and at offshore facilities in Federal and State
waters. Figure 2-1 shows that, in the production process,
extracted streams from production wells are transported from
the wellhead (through offshore production platforms in the
case of offshore wells) to tank batteries to separate crude
oil, natural gas, condensates, and water from the product.
Crude oil products are then transported through pump stations
to a refinery, while natural gas products are directed to gas
processing plants and then to final transmission lines at city
gates. The equipment required in the production of crude oil
and natural gas includes production wells (including offshore
production platforms), separators, dehydration units, tank
batteries, and natural gas processing plants.
2.1.1 Production Wells and Extracted Products
The type of production well used in the extraction
process depends on the region of the country in which the well
2-2
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"Dry-
natural gas
Onshore
Oil/Gas
Well
Offshore
Oil/Gas
Well
Extracted
streams
and
recovered
products
Offshore Production
Platform
Condensate
Tank Battery
•Wet"
natural gas
Black Oil
Tank Battery
Condensates
Natural Gas
Processing Plant
1
Marketable
natural gas
"Dry"
natural gas
City Gate
i
Crude
Oil
Refinery
Figure 2-1. Crude oil and natural gas production flow diagram.
2-3
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is drilled and the composition of the well stream. The
recovered natural resources are naturally or artificially
brought to the surface where the products (crude oil,
condensate, and natural gas) are separated from produced water
and other impurities. Offshore production platforms are used
to extract, treat, and separate recovered products in offshore
areas. Processes and operations at offshore production
platforms are similar to those located at onshore facilities
except that offshore platforms generally have little or no
storage capacity because of the limited available space.1
Each producing well has its own unique properties-in that
the composition of the well stream (i.e., crude oil and the
attendant gas) is different from that of any other well. As a
result, most wells produce a combination of oil and gas;
however, some wells can produce primarily crude oil and
condensate with little natural gas, while others may produce
only natural gas. The primary extracted streams and recovered
products associated with the oil and natural gas industry
include crude oil, natural gas, condensate, and produced
water. These are briefly described below.
Crude oil can be broadly classified as paraffinic,
naphthenic, or intermediate. Paraffinic (or heavy) crude is
used as an input to the manufacture of lube oils and kerosene.
Naphthenic (or light) crude is used as an input to the
manufacture of gasolines and asphalt. Intermediate crudes are
those that do not fit into either category. The
classification of crude oil is determined by a gravity measure
developed by the American Petroleum Institute (API). API
gravity is a weight per unit volume measure of a hydrocarbon
liquid as determined by a method recommended by the API. A
heavy or paraffinic crude is one with an API gravity of 20° or
less, and a light or naphthenic crude, which flows freely at
atmospheric temperatures, usually has an API gravity in the
range of the high 30s to the low 40s.2
2-4
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Natural gas is a mixture of hydrocarbons and varying
quantities of nonhydrocarbons that exist either in gaseous
phase or in solution with crude oil from underground
reservoirs. Natural gas may be classified as wet or dry gas.
Wet gas is unprocessed or partially processed natural gas
produced from a reservoir that contains condensable
hydrocarbons. Dry gas is natural gas whose water content has
been reduced through dehydration, or natural gas that contains
little or no commercially recoverable liquid hydrocarbons.
Condensates are hydrocarbons that are in a gaseous state
under reservoir conditions (prior to production), but which
become liquid during the production process. Condensates have
an API gravity in the 50° to 120° range.3 According to
historical data, Condensates account for approximately 4.5 to
5 percent of total crude oil production.
Produced water is recovered from a production well or is
separated from the extracted hydrocarbon streams. More than
90 percent of produced water is reinjected into the well for
disposal and to enhance production by providing increased
pressure during extraction. An additional 7 percent of
produced water is released into surface water under provisions
of the Clean Water Act. The remaining 3 percent of produced
water extracted from production wells is disposed of as waste.
In addition to the products discussed above, other
various hydrocarbons may be recovered through the processing
of the extracted streams. These hydrocarbons include mixed
natural gas liquids, natural gasoline, propane, butane, and
liquefied petroleum gas.
2.1.2 pehydration Units
Once the natural gas has been separated from the crude
oil or condensate and water, residual water is removed from
2-5
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the natural gas by dehydration to meet sales contract
specifications or to improve heating values for fuel
consumption. Liquid desiccant dehydration is the most
widespread technology used for natural gas with the most
common process being a basic glycol system. Glycol
dehydration is an absorption process in which a liquid
absorbent, a glycol, directly contacts the natural gas stream
and absorbs the water vapor that is later boiled off. Glycol
units in operation today may use ethylene glycol (EG),
diethylene glycol (DEC), triethylene glycol (TEG), and
tetraethylene glycol (TREG).4
Dehydration units are used at several processing points
in the process to remove water vapor from the gas once it has
been separated from the crude oil or condensate and water.
Locations where dehydration may occur include the production
well site, the condensate tank battery, the natural gas
processing plant, aboveground and underground storage
facilities upon removal, and the city gate.
2.1.3 . Tank Batteries
A tank battery refers to the collection of process
equipment used to separate, treat, store, and transfer crude
oil, condensate, natural gas, and produced water. As shown in
Figure 2-2, the extracted products enter the tank battery
through the production header, which may collect the product
from many production wells. Process equipment at a tank
battery may include separators that separate the product from
basic sediment and water; dehydration units; heater treaters,
free water knockouts, and gunbarrel separation tanks that
basically remove water and gas from crude oil; and storage
tanks that temporarily store produced water and crude oil.5
Tank batteries are classified as black oil tank batteries
if the extracted stream from the production wells primarily
2-6
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Gas
Oil or
Condensate
Pipeline
Production
Wells
Extracted
Streams ^
Separation
Produced
Water _
Storage
Tanks
^ Disposal or
Beneficial Use
Pipeline
Figure 2-2. Summary of processes at a tank battery
2-7
-------
consists of crude oil that has little, if any, associated gas.
In general, any associated gas recovered at a black oil tank
battery is flared. Condensate tank batteries are those that
process extracted streams from production wells consisting of
condensate and natural gas. Dehydration units are part of the
process equipment at condensate tank batteries but not at
black oil tank batteries.
2.1.4
Natural Gas Processing Plants
Natural gas that is separated from other products of the
extracted stream at the tank battery is then transferred via
pipeline to a natural gas processing plant. As shown in
Figure 2-3 the main functions of a natural gas processing
plant include conditioning the gas by separation of natural
gas liquids (NGL) from the gas and fractionation of NGLs into
separate components, or desired products that include ethane,
propane, butane, liquid petroleum gas, and natural gasoline.
Generally, gas is dehydrated prior to other processes at a
plant. Another function of these facilities is to control the
quality of the processed natural gas stream. If the natural
gas contains hydrogen sulfide and carbon dioxide, then
Nat
G
i
Swee
Open
i
ural
is
eninQ ^ nnhifrfrttirtn
Mions ucnyaraiion
r
Sulfur
Recovery
Gas
Natural
^ r. .• GaS ^
Liquids
Pressurized
Tanks "*
1
Pipeline
Fractionation —
i '
Storage
Tanks
Pipeline
— ^ Pipeline
Transfer
Operations
Figure 2-3.
Summary of processes at natural gas
processing plant.
2-8
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sweetening operations are employed to remove these
contaminants from the natural gas stream immediately after
separation and dehydration.
2.1.5 Natural Gas Transmission and Storage Facilities
After processing, natural gas enters a network of
pipelines and storage systems. The natural gas transmission
and storage source category consists of gathering lines,
compressor stations, high-pressure transmission pipeline, and
underground storage sites.
Compressor stations are any facility which supplies
energy to move natural gas at increased pressure in
transmission pipelines or into underground storage.
Typically, compressor stations are located at intervals along
a transmission pipeline to maintain desired pressure for
natural gas transport. These stations will use either large
internal combustion engines or gas turbines as prime movers to
provide the necessary horsepower to maintain system pressure.
Underground storage facilities are subsurface facilities
utilized for storing natural gas which has been transferred
from its original location for the primary purpose of load
balancing, which is the process of equalizing the receipt and
delivery of natural gas. Processes and operations that may be
located at underground storage facilities include compression
and dehydration.
2.2 PRODUCTS AND MARKETS
Crude oil and natural gas have historically served two
separate and distinct markets. Oil is an international
commodity, transported and consumed throughout the world.
Natural gas, on the other hand, is typically consumed close to
where it is produced. Final products of crude oil are used
2-9
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primarily as engine fuel for automobiles, airplanes, and other
types of vehicles. Natural gas, on the other hand, is used
primarily as boiler fuel for industrial, commercial, and
residential applications.
2.2.1 Crude Oil
The following subsections provide historical data on the
U.S. reserves, production, consumption, and foreign trade of
crude oil.
2.2.1.1 Reserves. The Department of Energy defines oil
reserves as "oil reserves that data demonstrate are capable of
being recovered in the future given existing economic and
operating conditions."6 Table 2-1 provides total U.S. crude
oil reserves for 1976 through 1993.7 Crude oil reserves
continued their decline for the sixth consecutive year in
1993, dropping by 788 million barrels (3.3 percent) to 2.3
billion barrels. Low oil prices and decreased drilling
activity are the major factors for these recent declines.
Table 2-2 presents the U.S. proved reserves of crude oil
as of December 31, 1993, by State or producing area.8 As this
table indicates, five areas currently account for 80 percent
of the U.S. total proved reserves of crude oil with Texas
leading all other areas, followed closely by Alaska,
California, the Gulf of Mexico, and New Mexico. Texas,
Alaska, and California accounted for roughly 82 percent of the
overall decline in crude oil reserves from 1992 to 1993.
Meanwhile, the Gulf of Mexico Federal Offshore had an oil
reserve increase of 237 million barrels.
2.2.1.2 pomestic Production. Because oil is an
international commodity, the U.S. production of crude oil is
affected by the world crude oil price, the price of
2-10
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TABLE 2-3. U.S. CRUDE OIL -PRODUCTION, 1982-1992
Year
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
Crude oil production
(MMbpd)
8.65
8.69
8.88
9.00
8.68
8.35
8.14
7.61
7.36
7.42
7.17
Source: U.S. Department of Energy. Petroleum
Supply Annual 1992. DOE/EIA-0340(92)-1
Vol. 1. May 1993.
2.2.1.3 Domestic Consumption^ Crude oil is the primary
input to the production of several petroleum products.
Consequently, the demand for crude oil is derived from the
demand of these final products. Final petroleum products
include motor gasoline, diesel fuel, jet fuel, and fuels for
the industrial, residential, and commercial sectors as well as
for electric utilities. Historical crude oil consumption
trends for 1980 through 1992 are shown in Table 2-4.10<11 As
shown in this table, a slight upturn in demand occurred in
1988, and consumption then remained fairly constant through
1992.
2.2.1.4 Foreign Trade. The world oil market is unique
in that it is dominated by the Organization of Petroleum
Exporting Countries (OPEC), which applies the following
2-13
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TABLE 2-4.
TOTAL U.S. CRUDE OIL CONSUMPTION AND PRICE
LEVELS, 1980-1992
Crude oil domestic
wellhead price
($ /barrel)
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
Domestic
consumption
(MMbpd)
17.06
16.06
15.30
15.23
15.73
15.73
16.28
16.67
17.28
17.33
16.99
16.70
17.00
Current
dollars
21.6
31.8
28.5
26.2
25.9
24.1
12.5
15.4
12.6
15.9
20.0
16.5
16.0
Constant
1990
dollars
34.2
45.7
38.6
34.4
32.6
29.3
14.9
17.7
13.9
16.8
20.0
15.8
14.7
Sources: U.S. Department of Energy. Petroleum Supply Annual 1992.
DOE/EIA-0340(92)-1. Vol. 1. May 1993.
U.S. Department of Energy. Natural Gas Annual 1991.
DOE/EIA-013K91) . Washington, DC. October 1992.
economic principle: if supply is restricted, prices will
rise. OPEC accounts for 38 percent of the world oil supply,
while the U.S. accounts for 12 percent. Supplies from the
OPEC exert a significant influence on domestic crude oil
foreign trade levels. In February 1992, OPEC reimposed quotas
on individual country output. The new quota signified a
reduction in production intended to alter world oil prices.
Any future additions to OPEC supply could reduce world crude
oil prices. Additionally, if supplies to the world oil supply
from the Commonwealth of Independent States (CIS) continue to
decline, excess OPEC supplies can be absorbed without a
significant crude oil price reduction.
2-14
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As Table 2-5 demonstrates, U.S. imports of crude oil have
increased steadily since 1983 at an average annual growth rate
of 9.6 percent, while U.S. exports have steadily declined at
an average of 4 percent annually.12 This has resulted in a net
import level in 1992 of 6 MMbpd. Oil imports are projected to
exceed 8.2 MMbpd in 1993. This annual growth rate of 4.7
percent is measurably higher than the 2.9 percent rate
registered in 1992.13 Total oil imports are predicted to reach
10.1 MMbpd by the year 2000. This predicted rise in imports
of crude oil corresponds to an average annual increase of 3.4
percent. The import dependency ratio is forecast to rise to
55 percent in 2000, compared to 48 percent in 1993.14 As a
result of the historical decline in domestic production and
increases in demand levels, net imports of crude oil are
expected to continue to increase.
TABLE 2-5.
SUMMARY OF U.S. FOREIGN TRADE OF CRUDE OIL,
1983-1992
Year
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
Imports
(MMbpd)
3.10
3.23
3.08
4.13
4.60
5.06
5.79
5.87
5.78
6.07
Domestic
crude oil
consump-
tion
(MMbpd)
15.23
15.73
15.73
16.28
16.67
17.28
17.33
16.99
16.70
17.00
Import
percent-
age of
domestic
consump-
tion
20.3
20.5
19.6
25.4
27.6
29.3
33.4
34.5
34.6
35.7
Exports
(MMbpd)
0.16
0.18
0.20
0.15
0.15
0.15
0.14
0.11
0.12
0.09
Domestic
crude oil
output
(MMbpd)
8.6
8.9
9.0
8.7
8.3
8.1
7.6
7.4
7.4
7.2
Export
percent-
age of
domestic
output
2.0
2.0
2.2
1.7
1.8
1.9
1.8
1.5
1.6
1.3
Source: U.S. Department of Energy. Annual Energy Review 1991. DOE/EIA-
0384(91) . June 1992.
2-15
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2.2.1.5 Future Trends. Table 2-6 presents the U.S.
Department of Energy's annual projections of crude oil
production, consumption, and world oil price from 1993 through
2010 based on two rates of economic growth and two possible
oil price scenarios.15 U.S. crude oil supply is predicted to
continue to decline between 1993 and 2010, due to low levels
of drilling activities in recent years. The range of
projections for 2010 is from 6.2 to 3.6 MMbpd. According to
the Independent Petroleum Association of America (IPAA), U.S.
crude oil production is predicted to continue its decline from
7.0 MMbpd in 1993 to 6 MMbpd by 2000.16 This will be the
lowest oil output level since 1950.
TABLE 2-6.
SUPPLY, DEMAND, AND PRICE PROJECTIONS FOR CRUDE
OIL, 1993-2010
Alternative projections to
Item
Production (MMbpd)
Consumption" (MMbpd)
World oil price
(1993 $/barrel)
Actual
1993
6.85
15.30
16.12
High
economic
growth
5.57
15.9
24.99
Low
economic
growth
5.23
15.9
23.29
High
oil
price
6.20
15.8
28.99
2010
Low
oil
price
3.58
16.00
14.65
"Consumption is measured by U.S. refinery capacity.
Source: U.S. Department of Energy. Annual Energy Outlook 1995.
DOE/EIA-0383(95). January 1995.
2.2.2
Natural Gas
The following subsections provide historical data on the
U.S. reserves, production, consumption, and foreign trade of
natural gas.
2.2.2.1 Reserves. Proved reserves of natural gas are
the estimated amount of gas that can be found and developed in
2-16
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future years from known reservoirs under current prices and
technologies.17 Table 2-7 provides total U.S. natural gas
reserves for 1976 through 1993.18 Although natural gas
discoveries were up considerably in 1993, increased production
along with lower revisions and adjustments (resulting from new
information about known gas reservoirs) led to a decline in
overall natural gas reserves of 2.6 Tcf to total 162.4 Tcf.
This decline reflects a 1.6 percent change in reserves from
the 1992 level.
TABLE 2-7. U.S. PROVED RESERVES OF DRY NATURAL GAS,
1976 THROUGH 1993
(billion cubic feet [Bcf] at 14.73 psia and 60° F)
Year
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Total discoveries
14,603
18,021
14,704
14,473
17,220
14,455
11,448
13,521
11,128
8,935
7,175
10,350
10,032
12,368
7,542
7,048
8,868
Production
18.843
18,805
19,257
18,699
18,737
17,506
15,788
17,193
15,985
15,610
16,114
16,670
16,983
17,233
17,202
17,423
17,789
Proved reserves
213,278"
207,413
208,033
200,997
199,021
201,730
201,512
200,247
197,463
193,369
191,586
187,211
168,024
167,116
169,346
167.062
165,015
162 ,415
'Based on following year data only.
Source: U.S. Department of Energy. Energy Information Administration.
U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves:
1993 Annual Report. October 1994.
2-17
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Table 2-8 presents the U.S. proved reserves of natural
gas as of December 31, 1993, by State or producing area.19'20
As indicated by this table, the five leading gas producing
areas of Texas, the Gulf of Mexico, Oklahoma, Louisiana, and
New Mexico all had declines in proved reserves from 1992 to
1993 totaling 2.6 Tcf. These declines were partially offset
by substantial increases in Virginia and Colorado, where gas
reserves increased by 942 Bcf over 1992.
2.2.2.2 Domestic Production. Natural gas production
trends are distinct from those of crude oil. As shown in
Table 2-9, production has been increasing since 1986.21'22 This
trend can be partially attributed to open access to pipeline
transportation, which has resulted in more marketing
opportunities for producers and greater competition, leading
to higher production. Traditionally, most natural gas sold at
the wellhead was sold under long-term, price-regulated
contracts and purchased by pipeline companies. These pipeline
companies in turn resold it to local distribution companies
(from the "wellhead" to the "city gate"). Therefore, the
pipelines transported natural gas as part of a larger package
of "bundled" services that include acquisition and
transportation. Local distribution companies then distribute
gas to residential, commercial, and industrial customers and
electric utilities (from the "city gate" to the "burner tip").
The end-user price thus reflected the cost of acquisition plus
the cost of transport and other services along with the
regulator-specified fair rate of return on investment.
The Natural Gas Policy Act (NGPA) of 1978 and subsequent
Federal Energy Regulatory Commission (FERC) orders throughout
the 1980s promoting open access transportation have
dramatically altered the industry organization of the U.S.
2-18
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TABLE 2-8.
U.S. NATURAL GAS RESERVES BY STATE AND AREA,
(Bcf)
1993
State/area
Alaska
Alabama
Arkansas
California
Colorado
Florida
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
Texas
Utah
Virginia
West Virginia
Wyoming
Federal offshore
Pacific (California)
Gulf of Mexico
(Louisiana)
Gulf of Mexico (Texas)
Other states
Total, lower 48 States
Total, U.S.
Proved Total
reserves discoveries and
12/30/92 adjustments
9,725
5,870
1,752
2,892
6,463
55
10,302
1,126
10,227
1,290
873
875
20,339
329
567
1,161
14,732
1,533
38,141
2,018
904
2,491
11,305
28,186
1,136
20,006
7,044
93
163,584
173,309
657
-371
-9
169
922
12
264
-22
830
75
38
-141
1,019
-43
75
66
1,246
328
4,736
358
454
286
824
4,096
32
3,128
936
13
15,165
15,822
Production
396
287
188
262
406
8
694
68
1,516
147
111
50
1,419
22
57
121
1,879
139
5,030
178
36
179
742
4,696
45
3,383
1,268
10
18,245
18,641
Proved
reserves
12/30/93
9,986
5,212
1,555
2,799
6,979
59
9,872
1,036
9,541
1.218
800
684
19,939
264
585
1,106
14,099
1,722
37,847
2,198
1,322
2,598
11,387
27,586
1,123
19,751
6,712
96
160,504
170,490
Sources: U.S. Department of Energy, Petroleum Supply Annual 1992.
DOE/EIA-0340(92)-1. Vol. 1. May 1993.
U.S. Department of Energy. Natural Gas Annual 1991.
DOE/EIA-013K91) . Washington, DC October 1992.
2-19
-------
TABLE 2-9.
U.S. NATURAL GAS PRODUCTION AND WELLHEAD PRICE
LEVELS, 1980-1992
Average annual wellhead
($/Mcf)
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
Domestic
production
(Tcf)
20
19
17
16
17
16
16
16
17
17
17
17
18
.18
.96
.82
.09
.47
.45
.06
.62
.10
.31
.81
.87
.47
Current
dollars
1
2
2
2
2
2
1
1
1
1
1
1
1
.6
.0
.5
.6
.7
.5
.9
.7
.7
.7
.7
.6
.8
price
Constant
1990
dollars
2
2
3
3
3
3
2
2
1
1
1
1
1
.5
.9
.4
.4
.3
.0
.3
.0
.9
.8
.7
.5
.7
Sources: U.S. Department of Energy. Petroleum Supply Annual 1992.
DOE/EIA-0340(92)-1. Vol. 1. May 1993.
U.S. Department of Energy. Natural Gas Annual 1991.
DOE/EIA-013K91) . Washington, DC. October 1992.
market for natural gas by separating the marketing and
transport functions of interstate pipeline companies.* With
the separation of transportation from production in the
industry, much of the natural gas is purchased directly from
producers, and the pipeline companies principally provide
transportation services for their customers. Independent
*These Federal Energy Regulatory Commission orders include FERC Order
No. 380, which effectively eliminated the requirement that customers of
interstate pipelines purchase any minimum quantity of natural gas,.and FERC
Order No. 636, which mandates that pipelines must separate gas sales from
transportation, thereby allowing open access to pipeline transportation for
gas producers and customers.
2-20
-------
brokers and other marketers service these transactions and
bypass the traditional marketing structure.*'23
Also contributing to the increase in production shown in
Table 2-9 are significant improvements in drilling
productivity as well as more intensive utilization of existing
fields since 1989. Because of lower prices in 1990 and 1991,
however, producers have curtailed drilling programs and have
sought ways to cut production costs, for example, by more
intensive development of profitable onshore fields.
2.2.2.3 Domestic Consumption. Table 2-10 displays
natural gas consumption by end user from 1980 to 1992, while
Table 2-11 presents end-user prices for natural gas for the
same time period.24'25 Natural gas users include residential
and commercial customers, as well as industrial firms and
electric utilities. Since 1986, natural gas consumption has
shown relatively steady growth, which is projected to continue
through the year 2010. Because some consumers can substitute
certain petroleum products for natural gas, prices of oil and
gas often move in the same direction. Low crude oil prices
after the 1986 price collapse, for example, effectively pushed
competing gas prices lower.
2.2.2.4 Foreign Trade. On the international market,
the U.S. and Canada are the world's leading producers of
natural gas, accounting for more than 59 percent of the
worldwide gas processing capacity (the U.S. accounts for
nearly 42 percent alone) and more than 57 percent of world
natural gas production. Table 2-12 displays the level of
imports and exports of natural gas as well as the import share
Based on USDOE/EIA information for 1991, 84 percent of natural gas
was transported to the market for marketers, local distribution companies
(LDCs), and end users (45 percent for independent brokers and other
marketers, 32 percent for local distribution companies, and 7 percent
directly to end users) as compared with only 3 percent in 1982. The
remaining 16 percent in 1991 was purchased at the wellhead by interstate
pipeline companies for distribution.
2-21
-------
TABLE 2-10.
U.S. NATURAL GAS CONSUMPTION BY END-USE
SECTOR, 1980-1992
End-user consumption (Tcf)
Year Residential
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
4
4
4
4
4
4
4
4
4
4
4
4
4
.75
.55
.63
.38
.56
.43
.31
.31
.63
.78
.39
.56
.70
Commercial
2
2
2
2
2
2
2
2
2
2
2
2
2
.61
.52
.60
.43
.52
.43
.32
.43
.67
.71
.62
.73
.77
Industrial
7
7
5
5
6
5
5
5
6
6
7
7
7
.17
.13
.83
.64
.15
.90
.58
.95
.38
.82
.02
.23
.64
Electric
utilities
3
3
3
2
3
3
2
2
2
2
2
2
2
.68
.64
.23
.91
.11
.04
.60
.84
.64
.79
.79
.79
.77
Other"
1
1
1
1
1
1
1
1
1
1
1
1
1
.66
.57
.71
.47
.61
.47
.41
.67
.71
.70
.90
.75
.85
Total
19.88
19.40
18.00
16.84
17.95
17.28
16.22
17.21
18.03
18.80
18.72
19.05
19.75
"Includes natural gas consumed as lease, plant, and pipeline fuel.
Source: Energy Statistics Sourcebook, 8th ed. PennWell Publishing Co.
September 1993.
of U.S. domestic consumption and the export share of U.S.
marketed production for the years 1973 through 1993. North
American gas trade is a major factor in the competitive U.S.
natural gas market. Natural gas imports no longer serve as a
marginal source of supply but are actively competing for
market share. As shown in Table 2-12, imports increased by 6
percent to 2.3 Tcf from 1992 to 1993 providing 11 percent of
U.S. domestic consumption.26 Canadian suppliers account for
most of the natural gas imports to the United States.
Although no significant changes in gas trade with Mexico are
expected in the near future, the North American Free Trade
Agreement (NAFTA) will assist in developing and integrating
the Mexican gas industry.27
2-22
-------
TABLE 2-11. U.S. NATURAL GAS PRICE BY END-USE SECTOR,
1980-1992
End-use sector ($/Mcf)
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
Residential
$3.68'
$4.29
$5.17
$6.06
$6.12
$6.12
$5.83
$5.54
$5.47
$5.64
$5.80
$5.82
$5.86
Commercial
$3.39
$4.00
$4.82
$5.59
$5.55
$5.50
$5.00
$4.77
$4.63
$4.74
$4.83
$4.81
$4.87
Industrial
$2.56
$3.14
$3.87
$4.18
$4.22
$3.95
$3.23
$2.94
$2.95
$2.96
$2.93
$2.69
$2.81
Electric
utilities
$2.27
$2.89
$3.48
$3.58
$3.70
$3.55
$2.43
$2.32
$2.33
$2.43
$2.39
$2.18
$2.37
Average
$2.91
$3.51
$4.32
$4.82
$4.85
$4.72
$4.13
$4.05
$4.09
$4.22
$4.20
NA
NA
Source: Energy Statistics Sourcebook,
September 1993.
8th ed. Perm Well Publishing Co.
Historically, imports of natural gas have increased at an
average annual growth rate of 10.5 percent. Increases in
natural gas imports have been driven by increased U.S. demand
and additions to interstate pipeline capacity in 1991 and
1992. Exports have doubled since 1983 although yearly
fluctuations have occurred. Net import levels have steadily
increased over this time period to 1.79 Tcf in 1992.
According to the IPAA, total gas imports'/ mainly from Canada,
are expected to rise to 3.1 Tcf by 2000, up from 2.2 Tcf in
1992. This is an average increase of nearly 6 percent each
year.
2.2.2.5 Future Trends. Currently, the domestic natural
gas production industry is in transition from a period
2-23
-------
TABLE 2-12.
HISTORICAL SUMMARY OF U.S. NATURAL GAS FOREIGN
TRADE, 1973-1993
(Bcf)
Year
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Total Total
imports exports
1,032
959
953
963
1,011
965
1,253
984
903
933
918
843
949
750
992
1,293
1,381
1,532
1,773
2,137
2,350
.9
.2
.0
.8
.0
.5
.4
.8
.9
.3
.4
.0
.7
.5
.5
.8
.5
.3
.3
.5
.1
77.2
76.8
72.7
64.7
55.6
52.5
55.7
48.7
59.4
51.7
54.6
54.8
55.3
61.3
54.0
73.6
106.9
85.6
129.2
216.3
140.2
Net imports
as a
percentage
Net Total of total
imports consumption consumption
955.7
882.5
880.3
899.1
955.4
913.0
1,197.7
936.0
844.6
881.6
863.6
788.3
894.4
689.2
938.5
1,220.2
1,274.6
1,446.7
1,644.1
1,921.2
2,209.9
22,
21,
19,
19,
19,
19,
20,
19,
19,
18,
16,
17,
17,
16,
17,
18,
18,
18,
19,
19,
20,
049.4
223.1
537.6
946.5
520.6
627.5
240.8
877.3
403.9
001.1
834.9
950.5
280.9
221.3
210.8
029.6
800.8
716.3
129.4
726.2
219.0.
4.
4.
4.
4.
4.
4.
5.
4.
4.
4.
5.
4.
5.
4.
5.
6.
6.
7.
8.
9.
10
3
2
5
5
9
7
9
7
4
9
1
4
2
2
5
8
8
7
6
7
.9
Exports
as a
percentage
Marketed of marketed
production production
22,
21,
20,
19,
20,
19,
20,
20,
20,
18,
16,
18,
17,
16,
17,
17,
18,
18,
18,
18,
19,
647.6
600.5
108.7
952.4
025.5
974.0
471.3
379.7
177.0
519.7
822.1
229.6
197.9
858.7
432.9
918.5
095.1
593.8
585.8
616.9
251.0
0.3
0.4
0.4
0.3
0.3
0.3
0.3
0.2
0.3
0.3
0.3
0.3
0.3
0.4
0.3
0.4
0.6
0.5
0.7
1.2
0.7
"Preliminary data.
Notes: Totals may not equal sum of components due to independent
rounding. Geographic coverage is the continental United States
including Alaska.
Source: U.S. Department of Energy. Energy Information Administration.
Natural Gas Monthly U.S. Natural Gas Imports and Exports—1993.
August 1994.
of overcapacity to one near full capacity utilization. Since
1985, demand has grown in response to low prices while
drilling activity remained depressed, lowering the gap that
2-24
-------
existed between demand and supply levels. While the U.S. has
a relatively large potential gas reserve base available for
development, current low market prices must increase to
stimulate new drilling activity and meet projected demand
growth. Natural gas supplies are expected to continue to
increase through the 1990s, slowing near 2000 as
deliverability through existing pipelines constrains the
development of some gas markets.28
Table 2-13 presents the U.S. Department of Energy's
annual projections of natural gas production, consumption, and
wellhead prices from 1993 to 2010 based on three rates of
economic growth. U.S. natural gas production and consumption
are projected to increase steadily over the projection
period.29 The range of projections for 2010 is from 19.89 to
21.91 Tcf. According to the IPAA, natural gas production is
expected to increase through the year 2000 at an average
annual rate of 1.1 percent, reaching nearly 20 Tcf by the year
2000, up from an expected level of 18.3 Tcf in 1993.30
TABLE 2-13. SUPPLY, DEMAND, AND PRICE PROJECTIONS
FOR NATURAL GAS, 1993-2010
Alternative projections to 2010
Production
(Tcf)
Consumption
(Tcf)
Wellhead price
(1993 $/Mcf)
Actual
1993
18.35
20.21
2.02
Base case
economic
growth
20.88
24.59
3.39
High
economic
growth
21.91
25.85
3.74
Low
economic
growth
14.89
23.18
3.01
Source: U.S. Department of Energy. Annual Energy Outlook
1995. DOE/EIA-0383(95). January 1995.
2-25
-------
2.3 PRODUCTION FACILITIES
The following subsections provide details on the
operating facilities of the oil and natural gas production
industry including production wells, dehydration units, tank
batteries, and natural gas processing plants.
2.3.1 Production Wells
Table 2-14 displays the number of crude oil and natural
gas wells in operation from 1983 to 1992.31 In 1992, an
estimated 594,200 crude oil wells operated in the United
States, and 280,900 natural gas production wells. For
offshore production, an estimated 3,841 oil and gas production
platforms operated in 1991 and were associated with a total of
33,000 wells. Natural gas production wells have increased in
number steadily since 1983, while crude oil wells show more
volatility.
TABLE 2-14. NUMBER OF CRUDE OIL AND NATURAL
GAS WELLS, 1983-1992
Year
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
Natural gas
producing wells
170,300
193,900
214,100
219,100
214,600
217,800
232,100
241,100
265,100
280,900
Crude oil
producing wells
603,300
620,800
646,600
628,700
621,200
623,600
606,900
602,400
610,200
594,200
Source: U.S. Department of Energy. Natural Gas
1992: Issues and Trends. DOE/EIA-0560(92)
Washington, DC. March 1993.
2-26
-------
Table 2-15 details the distribution of oil and gas well
capacity by production of barrels per month.32 Small
production wells dominate the industry. Stripper wells are
defined as those production wells that produce less than 10
bpd or 60 Mcf per day. In 1989, over 80 percent of the oil
wells produced less than 10 bpd or 0 to 300 barrels per month,
and over 78 percent of the gas wells produced within the same
range. The remaining production wells produce over a wide
range, from levels of 301 barrels per month to over 5,000
barrels per month.
TABLE 2-15.
U.S. ONSHORE OIL AND GAS WELL CAPACITY BY SIZE
RANGE, 1989
Size range
(barrels/
month)
0-60
61-100
101-200
201-300
301-400
401-500
501-600
601-1000
1001-2000
2001-5000
5001-Over
Total
Number
of
oil wells
306.032
67,150
76,926
47,263
20,631
21,433
13,044
29,992
22,134
9,735
3.555
617,895
Percentage
of
total
49.5
10.9
12.4
7.6
3.3
3.5
2.1
4.9
3.6
1.6
0.6
100.0
Number
of
gas wells
135,231
24,049
28,144
17,765
10,859
6,957
5,442
12,400
10,042
6,365
3.806
261,060
Percentage
of
total
51.8
9.2
10.8
6.8
4.2
2.7
2.0
4.7
4.0
2.4
100.0
Source: Gruy Engineering Corporation. Estimates of RCRA Reauthorization
Economic Impacts on the Petroleum Extraction Industry. Prepared
for the American Petroleum Institute. July 20, 1991.
Table 2-16 presents the distribution of U.S. natural gas
producing wells by state at the end of 1993.33 According to
World Oil, for 1993, a total of 286,168 natural gas producing
wells operated at onshore and offshore locations in the
2-27
-------
TABLE 2-16. DISTRIBUTION OF U.S. GAS WELLS BY STATE, 1993
State
Alabama
Alaska
Arkansas
California
Colorado
Federal DCS
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
Others
Total U S
1993 gas wells
3,395
157
2,914
1,072
6,372
3,532
384
1,327
14,200
12,836
13,214
3,174
552
2,900
60
27,832
5,951
104
34,581
28,902
31,100
38
620
47,245
1,164
1,340
38,280
2,880
42
286 168
Percentage of
total (%)
1.19
0.05
1.02
0.37
2.23
1.23
0.13
0.46
4.9.6
4.49
4.62
1.11
0.19
1.01
0.02
9.73
2.08
0.04
12.08
10.10
10.87
0.01
0.22
16.51
0.41
0.47
13.38
1.01
0.01
100.00
Source: Producing Gas Well Numbers are up Once Again. World Oil.
February 1993. Vol. 214, No.2.
2-28
-------
continental U.S. and Alaska. As shown, Texas accounts for
approximately 16.5 percent of U.S. natural gas wells with
47,245. A continued increase in U.S. natural gas wells is
expected for 1994 based on increases in gas prices.
2.3.1.1 Gruv Engineering Corporation Database. Based on
lease data, the Gruy Engineering Corporation developed
"wellgroups" for both oil and gas wells in each of 37
different geographic areas across the United States.34 For
each geographic area, wellgroups are defined by well depth and
then by production rate in each depth range. Four depth
ranges were employed for oil wells: 0 to 2,000 feet; 2,001 to
6,000 feet; 6,001 to 10,000 feet; and deeper than 10,000 feet.
Three depth ranges were developed for gas wells: 0 to 4,000
feet; 4,001 to 10,000 feet; and deeper than 10,000 feet.
Furthermore, 11 production ranges were used for both oil and
gas wells, expressed in barrels of oil equivalent (BOB), where
one barrel of oil equals one BOB that equals 10 Mcf. The
production rate ranges in BOB per month are 0 to 60; 61 to
100; 101 to 200; 201 to 300; 301 to 400; 401 to 500; 501 to
600; 601 to 1,000; 1,001 to 2,000; 2,001 to 5,000; and greater
than 5,000. Therefore, each of the 37 geographic areas was
divided into a possible 44 oil wellgroups and 33 gas
wellgroups. The result of Gruy's analysis provides 1,004 oil
wellgroups and 643 gas wellgroups (some regions had no wells
of certain types). Appendix A provides data on the oil
wellgroups developed by Gruy Engineering for each geographic
area, and Appendix B provides data on the natural gas
wellgroups.
2.3.2 Dehydration Units
The Gas Research Institute (GRI) estimates that the U.S.
may have 40,000 or more glycol dehydration units. TEG and EG
dehydration units account for approximately 95 percent of this
total, with solid desiccant dehydration units accounting for
2-29
-------
the remaining 5 percent.35 The primary application of solid
desiccant dehydration units is to dehydrate natural gas
streams at cryogenic natural gas processing plants.
For TEG dehydration units, stand-alone units dehydrate
natural gas from an individual well or several wells, and
units are collocated at condensate tank batteries and natural
gas processing plants. Available information indicates that,
on average, there is one TEG dehydration unit per condensate
tank battery and two or four dehydration units (TEG, EG, or
solid desiccant) per natural gas processing plant, depending
on throughput capacity.36'37
2.3.3 Tank Batteries
According to the BID, approximately 94,000 tank batteries
operated in the U.S. as of 1989.38 Furthermore, over 85
percent of tank batteries, or an estimated 81,000 facilities,
are classified as black oil tank batteries. The remaining
13,000 tank batteries are classified as condensate tank
batteries.
2.3.4 Natural Gas Processing Plants
Table 2-17 shows the number of natural gas processing
facilities in operation from 1987 to 1993 in the United
States.39 Over this time period the number of natural gas
processing plants has declined by over 10 percent, or a total
of 82 plants over 7 years. Table 2-18 provides the number of
natural gas processing facilities as of January 1, 1994, the
total processing capacity, and 1993 throughput level by
State.40 The States with the largest number of natural gas
processing plants are Texas, Oklahoma, Louisiana, Colorado,
and Wyoming, while the top states in terms of natural gas
processing capacity are Texas, Louisiana, Alaska, Kansas, and
Oklahoma.
2-30
-------
TABLE 2-17. U.S. NATURAL GAS PROCESSING
FACILITIES, 1987-1993
Year
1987
1988
1989
1990
1991
1992
1993
Number of facilities
810
760
745
751
748
735
728
Source: Gas Processing Report. Oil and Gas
Journal. £2(24). June 1994.
2.3.5 Natural Gas Transmission and Storage Facilities
There are an estimated 300,000 miles of high-pressure
transmission pipelines and approximately 1990 compressor
stations in the U.S. In addition, the natural gas industry
operates over 300 underground storage sites.
2.4 FIRM CHARACTERISTICS
A regulatory action to reduce pollutant discharges from
facilities producing crude oil and natural gas will
potentially affect the business entities that own the
regulated facilities. In the oil and natural gas production
industry, facilities comprise those sites where plant and
equipment extract and process extracted streams and recovered
products to produce the raw materials crude oil and natural
gas. Companies that own these facilities are legal business
entities that have the capacity to conduct business
transactions and make business decisions that affect the
facility.
2-31
-------
TABLE 2-18. U.S. NATURAL GAS PROCESSING PLANTS, CAPACITY,
AND THROUGHPUT AS OF JANUARY 1, 1994, BY STATE
State
Alabama
Alaska
Arkansas
California
Colorado
Florida
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania
Texas
Utah
West Virginia
Wyoming
Total U.S.
Number of plants
9
3
3
29
50
2
22
3
72
28
6
6
34
6
1
94
2
293
14
7
41
725
Natural
Capacity
785.0
7,775.0
878.0
1,044.0
1,596.5
890.0
5,122.0
141.0
18,334.4
4,731.9
884.2
19.5
2,889.0
122.9
20.0
4,656.8
14.0
17,259.5
624.9
398.9
3.783.7
71,971.2
gas (MMcfd)
1993 throughout
700.7
6,502.0
520.5
658.5
1,128.6
622.0
3,778.4
117.9
11,869.4
858.6
209.5
6.8
2,122.2
83.2
8.8
2,857.5
8.3
12,002.5
416.2
337.9
2.973.6
47,783.1
Source: "Worldwide Gas Processing Report
21(24):49110. June 13, 1994.
," Oil & Gas Journal.
2.4.1
Ownership
The oil and natural gas industry may be divided into
different segments that include producers, transporters, and
distributors. The producer segment may be further divided
between major and independent producers. Major producers
include large oil and gas companies that are involved in each
2-32
-------
of the five industry activities: (1) exploration,
(2) production, (3) transportation, (4) refining, and
(5) marketing. Independent producers include smaller firms
that are involved in some but not all of the five activities.
Transporters are comprised of the pipeline companies, while
distributors are comprised of the local distribution
companies.
During 1992, almost 7,700 companies owned the 9,391
establishments operating within SIC code 1311 (Crude Oil and
Natural Gas).41 For SIC 1311, the top 8 firms in 1992
accounted for 43.2 percent of the value of shipments, while
the top 16 firms accounted for almost 60 percent.
Furthermore, the top 8 firms accounted for 64 percent of
industry crude oil production and 37 percent of industry
natural gas production, while the top 16 firms accounted for
77.7 percent of industry crude oil production and 58.3 percent
of industry natural gas production.42
Through the mid-1980s, natural gas was a secondary fuel
for many producers. However, now it is of primary importance
to many producers. The Independent Petroleum Association of
America reports that 70 percent of its members' income comes
from natural gas production.43 In 1993, gas production
revenues exceeded oil production revenues for the first time,
accounting for 56 percent ($38 billion) of total oil and gas
industry production revenues. Higher wellhead prices for
natural gas, increased efficiency, and lower production costs
have all contributed to increased natural gas production and
improvements in producer revenues.44
2.4.2 Size Distribution
The Small Business Administration (SBA) defines Criteria
for defining small businesses (firms) in each SIC. Table 2-19
lists the primary SICs to be affected by the proposed
2-33
-------
TABLE 2-19.
NUMBER AND PROPORTION OF FIRMS IN SMALL BUSINESS
CATEGORY (BY SIC CODE)
SIC
Code
SIC
Description
SBA size
standard in
number of
employees or
annual sales
Number
of firms
Number of
firms
meeting
SBA
standard
Percentage
of firms
meeting
SBA
standard
1311 Crude
petroleum and
natural gas
1381
1382
2911
4922
4923
Drilling oil
and gas wells
Oil and gas
exploration
services
Petroleum
refining
Natural gas
transmission
Gas
4924
transmission
and
distribution
Natural gas
distribution
500
500
$5 million
1,500
$5 million
$5 million
500
429
132
176
141
79
74
121
372
100
77
98
11
6
71
87%
76%
44%
70%
14%
8%
59%
Source: Ward's Business Directory. Volume 2. Washington, DC. 1993.
regulations and their corresponding small business criteria.
SICs 1311 and 1381 have the highest percentage of small
businesses--87 percent and 76 percent respectively—and
SICs 4922 and 4123 have the lowest percentage—8 percent and
14 percent respectively.45
2.4.3 Horizontal and Vertical Integration
Because of the existence of major oil companies, the
industry possesses a wide dispersion of vertical and
horizontal integration. The vertical aspects of a firm's size
reflect the extent to which goods and services that can be
bought from outside are produced in house, while the
2-34
-------
horizontal aspect of a firm's size refers to the scale of
production in a single-product f-irm or its scope in a
multiproduct one.
Vertical integration is a potentially important dimension
in analyzing firm-level impacts because the regulation could
affect a vertically integrated firm on more than one level.
The regulation may affect companies for whom oil and natural
gas production is only one of several processes in which the
firm is involved. For example, a company owning oil arid
natural gas production facilities may ultimately produce final
petroleum products, such as motor gasoline, jet fuel, or
kerosine. This firm would be considered vertically integrated
because it is involved in more than one level of requiring
crude oil and natural gas and finished petroleum products. A
regulation that increases the cost of oil and natural gas
production will ultimately affect the cost of producing final
petroleum products.
Horizontal integration is also a potentially important
dimension in firm-level analyses for any of the following
reasons:
• A horizontally integrated firm may own many facilities
of which only some are directly affected by the
regulation.
• A horizontally integrated firm may own facilities in
unaffected industries. This type of diversification
would help mitigate the financial impacts of the
regulation.
• A horizontally integrated firm could be indirectly as
well as directly affected by the regulation. For
example, if a firm is diversified in manufacturing
pollution control equipment (an unlikely scenario), the
regulation could indirectly and favorably affect it.
In addition to the vertical and horizontal integration
that exists among the large firms in the industry, many major
producers often diversify within the energy industry and
2-35
-------
produce a wide array of products unrelated to oil and gas
production. As a result, some of the effects of control of
oil and gas production can be mitigated if demand for other
energy sources moves inversely compared to petroleum product
demand.
In the natural gas sector of the industry, vertical
integration is limited. Production, transmission, and local
distribution of natural gas usually occur at individual firms.
It is more likely that natural gas producers will sell their
output either to a firm that will subject it to additional
purification processes or directly to a pipeline for transport
to. an end user. Several natural gas firms operate multiple
facilities. However, natural gas wells are not exclusive to
natural gas firms only. Typically wells produce both oil and
gas and can be owned by a natural gas firm or an oil company.
Of the independents' total revenues, 72 percent is
derived from natural gas output, and the remaining 28 percent
is from crude oil production. Unlike the large integrated
firms that have several profit centers such as refining,
marketing, and transportation, most independents have to rely
only on profits generated at the wellhead from the sale of oil
and natural gas. Overall, the independent producers sell
their output to refineries or natural gas pipeline companies.
They are typically not vertically integrated but may own one
or two facilities, indicating limited horizontal integration.
2.4.4 Performance and Financial Status
In a special addition of the Oil and Gas Journal (OGJ),
financial and operating results for the top 300 oil and
natural gas companies are reported.46 Table 2-20 lists
selected statistics for the top 20 companies in 1993.47 The
results presented in the table reflect lower crude oil and
petroleum prices in 1993, which suppressed revenues. However,
2-36
-------
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higher natural gas prices, consumption, and production, as
well as increased consumption of petroleum production, offset
these trends. Total assets for the top 300 companies fell in
1993 for the third consecutive year, a reflection of continued
industry restructuring and consolidation with mergers,
acquisitions, and liquidations. As a result, the number of
publicly held companies was slashed. The top 300 companies,
however, represent a large portion of the U.S. oil and gas
industry and indicate changes and trends in industry activity
and operating performance.
Net income for OGJ's top 300 companies jumped
75.5 percent in 1993 to $18.3 billion, while total revenues
fell 3.9 percent to $475.1 billion. Other measures of
financial performance for the group showed improvement in
1993. Capital and exploration spending totaled $50.3 billion,
up 1.8 percent from 1992. In addition, the number of U.S. net
wells drilled rose 24.4 percent to 8,656. Table 2-21 provides
1993 performance highlights for the OGJ's group of 22 large
U.S. oil companies.48 Earnings for the group jumped sharply in
1993, increasing by 78.6 percent from 1992. Performance in
1993 restored group profits to the 1991 level even though
total revenues for the group fell 3.8 percent to $436.3
billion in 1993. Lower crude oil and petroleum product prices
were the main factors in the observed decline in revenues.
A more recent issue of OGJ reported on the economic
status of all 110 major and nonmajor" natural gas pipeline
companies in 1994.*9 Table 2-22 reports the sales volume,
operating revenues, and net income for the top 10 U.S. natural
gas pipeline companies in 1994. Operating revenues of the top
'Major pipeline companies are those whose combined gas sold for resale
and gas transported for a fee exceeded 50 bcf at 14.37 psi (60 degrees F) in
each of the three previous calendar years. Nonmajors are natural gas pipeline
companies not classified as majors and whose total gas sales of volume
transactions exceeded 200 MMcf at 14.73 psi (60 degrees F) in each of the
three previous calendar years.
2-38
-------
TABLE 2-21. PERFORMANCE MEASURES FOR OGJ GROUP, 1993
Performance measure
1993 highlights
Total assets
Net profits
Return on equity
Return on total assets
Capital/exploration spending
Net liquids production
Net natural gas production
Crude runs to stills
Liquid reserves
Natural gas reserves
$385.4 billion, down 1 percent
$16.2 billion, up 78.6 percent
10.1 percent, up 4.8 points
3.9 percent, up 1.9 points
$38.8 billion, down 5.8 percent
8.4 million bpd, down 2 percent
30 bcfd, up 0.7 percent
15.6 million bpd, up 1.2 percent
32 billion bbl, up 1.7 percent
140.2 tcf, up 0.6 percent
Source: "Profits for OGJ Group Show
and Gas Journal. 92(24):25-
Big Gain in 1993; Revenues Dip." Oil
30. June 13, 1994.
TABLE 2-22. PERFORMANCE OF TOP 10a GAS PIPELINE COMPANIES,
1994
Company
"Tennessee Gas Pipeline Co.
Natural Gas Pipeline of America
ANR Pipeline Co.
Texas Eastern Transmission Corp.
Panhandle Eastern Pipe Line Co.
Transcontinental Gas Pipe Line
Corp.
Northern Natural Gas Co .
El Paso Natural Gas Co.
CNG Transmission Corp.
Florida Gas Transmission Co.
Total 1994
Total All Companies 1994
Total All Companies 1993
Net Income
($000)
489,984
158,165
152,057
148,887
112,910
110,726
97,570
92,978
88,055
78,166
1,529,498
2,373,245
1,113,303
Operating
Revenues
($000)
1,065,285
1,046,660
152,057
832,405
384,771
1,590,962
702,567
669,439
488,754
175,731
7,108,631
16,547,531
21,746,475
'Based on net income.
Source: "U.S. Interstate Pipelines Ran More Efficiently in 1994". Oil and
Gas Journal, p. 39-58. November 27, 1995.
2-39
-------
10 companies equaled $7,108,631 and represented 43 percent of
the total operating revenues for major and nonmajor companies,
which had declined by 24 percent from the previous year. Net
income for the top 10 was over $1.5 billion and represented
almost 65 percent of the total net income for all major and
nonmajor companies. Despite the overall decline in operating
revenues, the total net income for the 100 companies rose by
37 percent from 1993 to 1994.
2-40
-------
SECTION 3
REGULATORY CONTROL OPTIONS AND COSTS OF COMPLIANCE
The BID details the available technologies on which this
NESHAP is based. Model plants were developed to evaluate the
effects of various control options on the oil and natural gas
production and natural gas transmission and storage source
categories. Control options were selected based on the
application of presently available control equipment and
technologies and varying levels of capture consistent with
different levels of overall control. Section 3.1 presents a
brief description of the model plants. Section 3.2 provides
an overview of the control options, and Section 3.3 summarizes
the compliance costs associated with the regulatory control
options.
3.1 MODEL PLANTS
The large number of production, processing, and storage
facilities in the oil and natural gas industry necessitates
using model plants to simulate the effects of applying the
regulatory control options to this industry. A model plant
does not represent any single actual facility; rather it
represents a range of facilities with similar characteristics
that may be affected by the regulation. Each model plant is
characterized by facility type, size, and other parameters
that influence the estimates of emissions and control costs.
Model plants developed for the oil and natural gas production
and natural gas transmission and storage source categories are
• TEG dehydration units,
• tank batteries that handle condensate (CTB),
3-1
-------
• natural gas processing plants (NGPP), and
• offshore production platforms (OPP).
The following subsections identify these model plants and
provide the estimated capacity, throughput, and population for
each unit.*
3.1.1 TEG Dehydration Units
As shown in Table 3-1, the engineering analysis
establishes five model TEG dehydration units based on natural
gas throughput capacity.50 These model units are defined in
the following manner:
• TEG unit A: <;5 MMcfd,
• TEG unit B: >5 MMcfd and <20 MMcfd,
• TEG unit C: >20 MMcfd and <;50 MMcfd,
• TEG unit D: >50 to 500 Mmcfd, and
• TEG unit E: >500 Mmcfd.
The total estimated number of TEG dehydration units is
just below 30,000 units. In addition, Table 3-1 includes the
number of TEG dehydration units by application (i.e., stand-
alone, condensate tank battery, natural gas processing plant,
offshore production platform, and natural gas transmission and
storage facilities). The estimated number of TEG dehydration
units by application is assumed to be one TEG dehydration unit
per condensate tank battery and offshore production platform
used in the separation of the well stream and two to four
dehydration units (TEG, EG, or solid desiccant) per natural
gas processing plant, depending on throughput capacity and
type of processing configuration, to dry the gas to required
specifications. In addition, model TEG units were distributed
within the natural gas transmission and storage source
category consistent with their natural gas design and
throughput capacities.
"No model plants are developed for natural gas transmission and storage
facilities because the only HAP emission point of concern for these facilities
is a process vent at an associated TEG dehydration unit.
3-2
-------
TABLE 3-1. MODEL TEG DEHYDRATION UNITS
Model plant
A
Capacity (MMcfd) <5
Throughput (MMcfd) 0.3
Estimated
population
Stand-alone 24,000
@ Condensate 12,000
tank battery
@ Natural gas
processing plant
@ Offshore
production
platform
@ Natural gas 200
transmission and
underground
storage
TOTAL 36,200
B
5 to
20
10
200
500
66
260
125
1,151
C
20 to
50
35
25
100
110
40
35
300
D
>50 to
500
100
20
70
54
10
154
E Total
>500
500
24,245
12.670
230
300
1C 370
10 37,815
Source: Natural Emission Standards for Hazardous Air Pollutants for Source
Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information for Proposed
Standards. U.S. Environmental Protection Agency. Research
Triangle Park, NC. July 1996.
Note: MMcfd = million cubic feet per day.
3.1.2 Condensate Tank Batteries
As shown in Table 3-2, the engineering analysis
establishes four model condensate tank batteries based on
natural gas throughput capacity. These model units are
defined as follows:
CTB E: *5 MMcfd,
CTB F: >5 MMcfd and <;20 MMcfd,
CTB G: >20 MMcfd and <;50 MMcfd,
CTB H: >50 MMcfd.
and
3-3
-------
TABLE 3-2. MODEL CONDENSATE TANK BATTERIES
Model plant
Capacity (MMcfd)
Throughput (MMcfd)
Estimated population
E
£5
1
12,000
F
5 to 20
10
500
G
20 to 50
35
100
H
>50
100
70
Total
12,670
Source: Natural Emission Standards for Hazardous Air Pollutants for Source
Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information for Proposed
Standards. U.S. Environmental Protection Agency. Research
Triangle Park, NC. July 1996.
Note: Mmcfd = million cubic feet per day.
Condensate tank batteries generally have a TEG dehydration
unit as a process unit within the overall system design of the
tank battery. The estimated number of condensate tank
batteries operating in the U.S. is close to 13,000, or 15
percent of all tank batteries.51
3.1.3 Natural Gas Processing Plants
As shown in Table 3-3, the engineering analysis
establishes three model natural gas processing plants based on
natural gas throughput capacity. These model units are
defined as follows:
NGPP A: <;20 MMcfd,
• NGPP B: >20 MMcfd and slOO MMcfd,
NGPP C: >100 MMcfd.
Although the population of TEGs and tank batteries must be
estimated, the OGJ provides detailed information on U.S.
natural gas processing plants. As of January 1, 1994, the
U.S. had approximately 700 natural gas processing plants. The
OGJ's annual survey of natural gas processing plants
3-4
-------
TABLE 3-3. MODEL NATURAL GAS PROCESSING PLANTS
Model plant
A
Capacity (MMcfd) «20 20
Throughput
Estimated
Source: U
(Mmcfd) 10
population 260
. S. Environmental Protection Agency.
B
to 100
70
300
Natural
C
>100
200
140
Emission
Total
700
Standards
for Hazardous Air Pollutants for Source Categories: Oil and
Natural Gas Production and Natural Gas Transmission and Storage—
Background Information for Proposed Standards. Office of Air
Quality Planning and Standards. Research Triangle Park, NC. July
1996.
Note: MMcfd = million cubic feet per day.
identifies each plant by State, design capacities, and
estimated 1993 throughput.52 The estimates of the number of
natural gas processing plants corresponding to each size range
shown in Table 3-3 are based on this annual survey.
3.1.4 Offshore Production Platforms
As shown in Table 3-4, the engineering analysis
establishes two model offshore production platforms based on
crude oil productive capacity of those located in state water
areas. These model units are defined in the following manner:
• OPP A: State water areas with 1,000 bpd capacity, and
• OPP B: State water areas with 5,000 bpd capacity.
As discussed in the BID, approximately 300 offshore
production platforms are located in State water and therefore
subject to EPA's jurisdiction for air emissions regulations.
The model characterization of these platforms is based on data
from the Minerals Management Service (MMS) of the U.S.
Department of Interior.53
3-5
-------
TABLE 3-4. MODEL OFFSHORE PRODUCTION PLATFORMS
Model plant
Small
Medium
Total
Location
Capacity (BOPD)
Throughput (BOPD)
Estimated population
State waters
1,000
200
260
State waters
5,000
2,000
40
300
Source: Natural Emission Standards for Hazardous Air Pollutants for Source
Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information for Proposed
Standards. U.S. Environmental Protection Agency. Research
Triangle Park, NC. July 1996.
Note: BOPD = barrels of oil per day.
3.2 CONTROL OPTIONS
Sources of HAP emissions in oil and natural gas
production include the glycol dehydration unit process vents,
storage vessels, and equipment leaks. Table 3-5 summarizes
the control options under evaluation for HAP emission points
within the model units in the oil and natural gas production
and natural gas transmission and storage source categories.54
The control options include the use of certain equipment
(e.g., installation of a cover or fixed roof for tanks) and
work standards (e.g., leak detection and repair [LDAR]
programs for fugitive emission sources). Control options that
areT applicable to each potential HAP emission point at model
plants are fully detailed in the BID.
Major sources of HAP emissions are controlled based on
the MACT floor, as defined by the control options in
Table 3-6. The Agency has determined that a glycol
dehydration unit must be collocated at a facility for the
facility to be designated as a major source. Therefore, the
MACT floor may apply to stand-alone TEG units, condensate tank
3-6
-------
TABLE 3-5.
SUMMARY OF CONTROL OPTIONS BY MODEL PLANT AND HAP
EMISSION POINT
Model
plant/unit
HAP emission
point
Control option
Control
efficiency (%)
TEG dehydration Reboiler vent
unit
Condenser with flash 95
tank in design
Condenser without 50
flash tank
Combustion 98
System optimization Variable
Tank battery
Open-top
storage tank
Cover and vent to 95%
control device or
redirect
99
Natural gas
processing
plant
Offshore
production
platforms
Fixed roof
storage tank
Equipment leaks
Fixed roof
storage tank
Equipment
leaks
Equipment leaks
Vent to 95% control
device or redirect
LDARa
Vapor collection and
redirect
LDAR
LDAR
95
70
95
70
70
* Leak detection and repair program based on one of the following:
• Control Techniques Guideline (CTG) document applicable to natural
gas/gasoline processing plants,
• New Source Performance Standard (NSPS) applicable to onshore
natural gas processing plants constructed or modified after
1/20/84, or
• Hazardous Organic NESHAP (HON) regulatory negotiation applicable
to synthetic organic chemical manufacturing facilities.
Source: Natural Emission Standards for Hazardous Air Pollutants for Source
Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information for Proposed
Standards. U.S. Environmental Protection Agency. Research
Triangle Park, NC. July 1996.
batteries, natural gas processing plants, and storage
facilities. Black oil tank batteries and offshore production
platforms are not considered since TEG units are not typical
of the operations at black oil tank batteries and are
completely controlled at offshore production platforms. EPA
has also determined a need to control area sources based on
GACT standards. Thus, area sources will be required to place
3-7
-------
controls on model TEG units with natural gas throughput
between 3 and 5 MMcfd that emit I mg or more of benzene per
year.
The engineering analysis contained in the BID document
projects the number of major and area sources of HAP emissions
by model plant. Tables 3-6, 3-7, and 3-8 provide the
percentage and number of affected units by model type--TEG
dehydration unit, condensate tank battery, and natural gas
processing plant.
TABLE 3-6.
TOTAL AND AFFECTED POPULATION OF TEG UNITS BY
MODEL TYPE
Model TEG Unit
Item
Total population
Percent affected
Major sources
Area sources
Affected units
Stand-alone
@ Condensate TB
@ NGPP
@ storage facility
Total
A
36,200
0.0%
2.6%
941
0
0
0
941
B
1,151
22.7%
0.0%
138
109
14
0
261
C
300
50.3%
0.0%
25
100
26
0
151
D
154
18.2%
0.0%
20
5
3
0
28
E
10
50.0%
0.0%
0
0
0
5
5
Total
37,615
445
941
1,124
214
43
5
1,386
3.3 COSTS OF CONTROLS
The BID describes in detail the cost estimates for
control options that are applicable to each potential HAP
emission point at model plants. Cost estimates are expressed
3-8
-------
TABLE 3-7. TOTAL AND AFFECTED POPULATION OF CONDENSATE
TANK BATTERIES BY MODEL TYPE
Model condensate tank battery
Item
Total population
Percent affected
Major sources
Area sources
Affected units
Major sources
Area sources
Total
E
12,000
0%
0%
0
0
0
F
500
21.8%
0%
109
0
109
G
100
10.0%
0%
10
0
10
H
70
7.1%
0%
5
0
5
Total
12,670
1.0%
0%
124
0
124
TABLE 3-8. TOTAL AND AFFECTED POPULATION OF NATURAL GAS
PROCESSING PLANTS BY MODEL TYPE
Model NGPP
Item
Total population
Percent affected
Major sources
Area sources
Affected units
Major sources
Area sources
Total
A
260
2.7%
0%
7
0
7
B
300
1.3%
0%
4
0
4
C
140
0.7%
0%
1
0
1
Total
700
1.7%
0%
12
0
12
in July 1993 dollars. Table 3-9 summarizes the total and
annualized capital costs; operating expenses; monitoring,
inspection, recordkeeping, and reporting costs (maintenance
costs); and total annual cost for each control option by model
plant. The annualized capital cost is calculated using a
capital recovery factor of 0.1098 based on an equipment life
3-9
-------
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of 15 years and a 7 percent discount rate.55 The total annual
cost is calculated as the sum of the annualized capital cost;
operating expenses; and the monitoring, inspection,
recordkeeping, and reporting costs.
In addition, product recovery is presented in Table 3-9
as an annual cost credit where applicable. Product recovery
credits were calculated by multiplying the mass of product
recovered by the product value for each control option.
Recovered liquid, condensate, and crude oil were assigned a
value of $18 per barrel, while recovered gas product was
assigned different dollar amounts depending on its use;
Recycled product for further processing and sale was valued at
$2 per Mcf, recovered gas hydrocarbons for use as a fuel
supplement were valued at. $1.30 per Mcf, and gas hydrocarbons
directed to an incinerator or flare were assigned no value.56
Table 3-10 summarizes the annual control costs for major
and area sources expressed per model plant. The annual costs
for model condensate tank batteries and natural gas processing
plants are appropriately weighted given the percentage of
affected units subject to the various control options and
include the costs of TEG dehydration units present at each
model type. One TEG unit is assigned to each model CTB based
on throughput capacity so that a TEG unit A is assigned to
each CTB E, a TEG unit B is assigned to each CTB F, a TEG unit
C is assigned to each CTB G, and a TEG unit D is assigned to
each CTB H. The allocation of TEG units to model NGPPs is
such that a model NGPP A is assigned two TEG B units, a model
NGPP B is assigned three model TEG C units, and a model NGPP C
is assigned three model TEG D units.
3-12
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TABLE 3-10.
SUMMARY OF ANNUAL CONTROL COSTS FOR MAJOR AND
AREA SOURCES BY MODEL PLANT
.Model Plant
Cost per model unit
Major source
Area source
TEG dehydration units
TEG-A
TEG-B
TEG-C
TEG-D
TEG-E
Condensate tank batteries
CTB-E
CTB-F
CTB-G
CTB-H
Natural gas processing plants
NGPP-A
NGPF-B
NGPP-C
$12,989
$12,937
$12,790
$12,790
$19,660
$24,973
$25,071
$46,747
$61,823
$81,083
$12,088
3-13
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SECTION 4
ECONOMIC IMPACT ANALYSIS
Implementing the controls will directly affect the costs
of production in the oil and natural gas production industry.
However, these initial effects will be felt throughout the
economy--downstream by consumers of refined petroleum products
and natural gas and upstream by suppliers of inputs to the
industry. As demonstrated in Section 3, facilities in this
industry will be affected by the regulation differently,
depending on the products (crude oil, condensates, natural
gas) they process, the processing equipment they currently
employ, and the level of throughput. Facility-level
production responses to the additional regulatory costs will
determine the market-level impacts of the regulation.
Specifically, the cost of the air pollution controls may force
the premature closing of some facilities or may cause
facilities to alter current production levels.
Section 3 indicates that black oil tank batteries will
not incur control costs as a result of the proposed
regulation. Thus, only condensates processed at condensate
tank batteries will be directly affected by the regulation,
which represents less than 5 percent of total U.S. crude oil
production.57 Crude oil is an international commodity,
transported and consumed throughout the world. Most economic
models of world crude oil markets consider the OPEC as a
price-setting residual supplier, facing a net demand for crude
oil that is the difference between the world demand and the
non-OPEC supply of crude oil.58'59 Accordingly, the U.S. may
be seen as a price taker on the world oil market with no power
to influence the world price in any significant way. This
analysis does not include a model to assess the regulatory
4-1
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effects on the world crude oil market because not only will
less than 5 percent of U.S. crude oil production be affected
but changes in the U.S. supply are not likely to influence
world prices. Therefore, this analysis focuses on the
regulatory effects on the U.S. natural gas market.
As discussed in Section 2, the natural gas industry has
undergone fundamental changes in recent years including a
restructuring of the interstate pipeline industry and a
diminishing of excess productive capacity. These changes have
resulted in increased competition within the natural gas
industry. Accordingly, producers of natural gas can respond
to changes in demand and price levels fairly easily because
their product is often sold directly to the end user.
Open access to pipeline transportation created regional
spot markets for natural gas through local and regional
competition between pipelines for gas supplies and between
producers for gas sales. Doane and Spulber find that open
access, or the "unbundling" of pipeline services, has
integrated regional wellhead markets into a national market
for natural gas.60 The regional wellhead markets are linked by
the action of buyers, who are interested in the delivered
price of natural gas (i.e., the sum of the wellhead price and
the transportation and transaction costs of obtaining gas).
Buyers have the opportunity to evaluate costs of purchasing
gas from different regions and transporting it along different
pipeline systems. To the extent that natural gas producers
compete across regions to supply the same customers, the
regional wellhead markets combine to form a national market.61
Based on this research, the U.S. market for natural gas was
modeled as a national, perfectly competitive market for a
homogeneous commodity.
This economic impact analysis assesses the market-,
industry-, and societal-level impact of the proposed
4-2
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regulation. A variety of approaches may be used to quantify
and evaluate economic impacts; they reflect a variety of
underlying paradigms. The neoclassical model provides the
state-of-the-art paradigm for regulatory analysis and
establishes the framework for the subsequent empirical
modeling. The remainder of this section provides a conceptual
overview of the production relationships involving the natural
gas industry, the details of an operational market model to
assess the regulation, and the results of the economic
analysis.
4.1 MODELING MARKET ADJUSTMENTS
Standard concepts in microeconomics are employed to model
the supply of natural gas and the impacts of the regulation on
production costs and output decisions. The following
subsections examine the impact of the regulations that affect
operating costs for producing wells in the U.S. natural gas
industry. Together they provide an overview of the basic
economic theory of the effect that regulations have on
production decisions and of the concomitant effect on natural
gas prices. The three main elements are the regulatory
effects on the production well or "facility," market response,
and facility-market interactions.
4.1.1 Facility-Level Effects
At any point in time, the costs that a firm faces can be
classified as either unavoidable (sunk) or avoidable. In the
former category, we include costs to which the firm is
committed and that must be paid regardless of any future
actions of the firm.* The second category, avoidable costs,
For instance, debt incurred to construct a production well or
processing facility must be repaid regardless of the production plan and
even if the well or facility ceases operation prior to full repayment,
unless the range of viable alternatives includes the declaration of
bankruptcy by the owners.
4-3
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describes any costs that would be foregone by ceasing
production. Avoidable costs can also be viewed as the full
opportunity costs of operating the facility. These costs can
be further refined to distinguish between costs that vary with
the level of production and those that are independent of the
production level.* The determination of both the avoidability
and the variability of firms' costs is essential to analyzing
economic responses to the proposed regulation.
Figure 4-1 illustrates the classical U-shaped structure
of production costs with respect to natural gas production.
Let ATAC be the average total (avoidable) cost curve and MC
the marginal cost of producing natural gas, which intersects
ATAC at its minimum point. All these curves are drawn
conditional on input prices and the technology in place at the
production well. Thus, all firms have some flexibility via
their decision to operate, at a given output rate, or to close
the well. But they do not have the full flexibility to vary
the size and composition of their existing capital stock at
the production well or processing facility (i.e., to change
technology beyond that needed to comply with the regulatory
alternative).
The well's supply function for natural gas is that
section of the marginal cost curve bounded by the quantities
Q,,^ and Q,,^. Q^ is the largest feasible production rate that
can be sustained at the facility given the technology and
other fixed factors in place, regardless of the output price.
Qmin is the minimum economically feasible production rate,
which is determined by the minimum of the ATAC curve, which
coincides with the price ?_<... Suppose the market price of
For example, production factors such as labor, materials, and
capital (except in the short run) vary with the level of output, whereas
expenditures for facility security and administration may be independent of
production levels but avoidable if the well or processing facility closes
down.
4-4
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$/Q
P1
mm
ATAC
Qmi
Q/t
•min
'max
Figure 4-1. Facility unit cost functions.
natural gas is less than Pmin. In this case, the firm's best
response is to close the well and not produce natural gas
because P < ATAC implies that total revenue would be less than
total avoidable costs if the well operated at the associated
output levels below Qmin.*
Now consider the effect of the regulatory control costs.
These proposed costs are all avoidable because a firm can
choose to cease operation of the facility and thus avoid
incurring the costs of compliance. These costs of compliance
include the variable component consisting of the operating and
maintenance costs and the nonvariable component consisting of
the compliance capital equipment acquired for the regulatory
option. Incorporating the regulatory control costs will
involve shifting upward the ATAC and MC curves as shown in
Figure 4-2 by the per-unit compliance cost (operating and
This characterization of the economics regarding the operating
decision agrees with that described in Reference 6.
4-5
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$/Q
P'm
Qmin Q'mm
Q/t
Figure 4-2. Effect of compliance costs on
facility cost functions.
maintenance plus annualized capital). Therefore, the supply
curve for each production well shifts upward with marginal
costs, and a new (higher) minimum operating level (Q min) is
determined by a new (higher) P',^.
4.1.2
Market-Level Effects
The competitive structure of the market is an important
determinant of the regulation's effect on market price and
quantity. As discussed above, it was assumed that natural gas
prices are determined in perfectly competitive markets. As
illustrated in Figure 4-3, without the regulation, the market
quantity and price of natural gas (Q0, P0) are determined by
the intersection of the market demand curve (D) and the market
supply curve (S). The market supply curve is determined by
the horizontal summation of the individual facility supply
curves. Imposing the regulation increases the costs of
producing natural gas for individual suppliers and, thus,
shifts the market supply function upward to S' (see
Figure 4-3). The supply shifts for natural gas cause the
4-6
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$/Q
P,
PO
Q/t
Figure 4-3. Natural gas market equilibria with
and without compliance costs.
market price to rise and market quantity to fall at the new
with-regulation equilibrium.
4.1.3 Facility-Level Response to Control Costs and New
Market Prices
In evaluating the market effects for natural gas, the
analysis must distinguish between the initial effect of the
regulation and the net effect after the market has adjusted.
Initially, the cost curves at all affected wells producing
natural gas shift upward by the amount of the appropriate unit
costs of the regulation. However, the combined effect across
these producers causes an upward shift in the market supply
curve for natural gas, which pushes up the price. Determining
which shift dominates for a particular production well depends
on the relative magnitude of the well-specific unit control
costs of the regulation and the change in market price.
Given changes in market prices and costs, operators of
production wells will elect to either
4-7
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• continue to operate, adjusting production and input
use based on new prices and costs, or
• close the production' well if revenues do not exceed
operating costs.
The standard closure evaluation is based on the comparison of
revenues to the opportunity costs of production. If operators
of production wells anticipate that these costs with the
controls will exceed revenues, they will close the well.
Production well closures directly translate into quantity
reductions. However, these quantity reductions will not be
the only source of output change in response to the
regulation. The output of production wells that continue
operating with regulation will also change as will the
quantity supplied from foreign sources. Affected facilities
that continue to produce may increase or decrease their output
levels depending on the relative magnitude of their unit
control costs and the changes in market prices. Unaffected
U.S. producers will not face an increase in compliance costs,
so their response to higher product prices is to increase
production. Foreign producers, who do not incur higher
production costs because of the regulation, will respond in
the same manner as the unaffected U.S. facilities.
The approach described above provides a realistic and
comprehensive view of the regulation's effect on responses at
the facility-level as well as the corresponding effect on
market prices and quantities for natural gas. The next
section describes the specifics of the operational market
model."
4.2 OPERATIONAL MARKET MODEL
To estimate the economic impacts of the regulation, the
competitive market paradigm outlined above was
operationalized. The purpose of the model is to provide a
4-8
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structure for analyzing the market adjustments associated with
regulations to control air pollution from the oil and natural
gas production industry. The model is a multi-dimensional
Lotus spreadsheet incorporating various data sources to
provide an empirical characterization of the U.S. natural gas
industry for a base year of 1993—the latest year for which
supporting technical and economic data were available.
To implement this model, the production wells and natural
gas production facilities to be included in the analysis were
identified and characterized, the supply and demand sides of
the U.S. natural gas market were specified, supply and demand
specifications were incorporated into a market model
framework, and market adjustments due to imposing regulatory
compliance costs were estimated.
4.2.1 Network of Natural Gas Production Wells and
Facilities
Because of the large number of producing wells, operating
units, and processing plants in the oil and natural gas
production industry, it is not possible to simulate the
effects of imposing the regulatory control costs at each and
every facility in the industry. The following section
describes the methods employed in linking the EPA engineering
model plants (as described in Section 2) with the wellgroups
developed by Gruy Engineering Corporation (as discussed in
Section 2.3.1.1 and provided in Appendixes A and B) to
construct the model units of analysis that constitute the
"facilities" for use in the economic model of the U.S. natural
gas industry.
To apply the Gruy Engineering Corporation data to the
economic analysis, it was necessary to make appropriate
adjustments to those databases. First, to ensure consistent
units of measure between Gruy and supporting data sources, all
units of natural gas production were converted to thousands of
4-9
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cubic feet per day (Mcfd). Next, because the Gruy report
reflects 1989 data, it was necessary to adjust the number of
gas wells to reflect 1993 data, the base year of this
analysis. The 1993 gas wells, as shown in Table 2-16, were
allocated across the Gruy well cohorts in each state in the
same proportion as their distribution in the Gruy database.
Gas well production rates (Mcfd/well) were calculated based on
the Gruy data. These rates were not altered for the analysis
because no evidence suggested that production rates have
changed since 1989. Natural gas production was recalculated
by multiplying the production rates per well by the 1993
number of producing wells in each cohort. These adjustments
are reflected in Appendix B.
To facilitate the analysis, the producing field was
determined to be the relevant unit of production. Thus, the
individual Gruy gas wells were integrated into producing
fields of homogeneous well types rather than employing units
of production at the individual well level. The number of
wells in each wellgroup, or cohort, was distributed as evenly
as possible to each of the fields. Rather than allocate parts
of a well, the number of wells was distributed as integer
values so that some like fields have an additional well. The
oil wells, however, were included in the analysis at the
wellgroup level as a single cohort, thereby representing one
or more fields.
4.2.1.1 Allocation of Production Fields to Natural Gas
Processing Plants. Once the production fields for each state
were established, each field needed to be assigned to one of
the 720 U.S. natural gas processing plants listed in the
OGJ's63 Oil and gas production fields were randomly allocated
to the natural gas processing plants within a State given the
plane-level natural gas processing throughput for 1993 as
provided in the OGJ survey. However, in many cases, natural
gas that is extracted in one State is processed in another
4-10
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State. Table 4-1 shows which states produce more gas than
they process (excess suppliers), process more than they
produce (excess demanders), or process exactly what they
produce. Because of this interstate flow of natural gas, it
was necessary to allocate the production fields of States with
excess supply to the processing plants within that State first
and then assign the unallocated fields to States with excess
demand. The step-by-step allocation process was as follows:
1) Assign uniform random numbers between 0 and 1 to each
production field using the @RAND function in Lotus
1-2-3.
2) Sort the production fields by their random•number.
3) Allocate production fields to a processing plant until
the 1993 processing level at that plant is matched
(exactly or as close as possible).
4) Continue to the next processing plant within that
state repeating Step 3 until the 1993 processing
levels at all processing plants within the State are
satisfied.
Those states with excess supply were assumed to only
process gas extracted from fields within that State.
Production fields that were not allocated to a processing
plant within their State are then assigned to the next closest
State with excess demand based on the location of existing
pipelines. The steps outlined above were repeated for the
excess demand states until all production fields had been
allocated to processing plants.
After allocating the production fields to the processing
plants, like field types that were assigned to the same
processing plant were combined by summing the number of wells
across these fields. This further aggregation is justified
since baseline and with-regulation costs per unit are the same
within wellgroups, natural gas processing plants, and their
combination. After this adjustment was completed, just over
4-11
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TABLE 4-1.
LIST OF STATES BY EXCHANGE STATUS OF
NATURAL GAS, 1993
Export
Import
No exchange
Alabama
Arizona
California
Illinois
Indiana
Kentucky
Michigan
Mississippi
Montana
Nebraska
New Mexico
New York
North Dakota
Oklahoma
Ohio
Oregon
Pennsylvania
South Dakota
Tennessee
Texas—North
Texas--Gulf Coast
Texas—West
Utah
Virginia
West Virginia
Arkansas
Colorado
Florida
Kansas
Louisiana
Wyoming
Alaska
Note: Exporting States produced more natural gas in 1993 than that
processed within the State, importing States processed more natural
gas in 1993 than that produced within the State, while States with no
exchange processed and produced an equal amount of natural gas in
1993.
4-12
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8,000 production field groupings supplied the 691 processing
plants.*
4.2.1.2 Assignment of Model Units. Once production
fields had been assigned to natural gas processing plants, it
became necessary to assign natural gas processing equipment to
the production fields and natural gas processing plants.
Processing equipment includes TEG dehydration units and
condensate tank batteries (CTB). TEG units may be stand-alone
units or they may exist at condensate tank batteries or
natural gas processing plants. The following sections discuss
the model units defined in the engineering analysis and the
methods employed in allocating these units to the production
fields and natural gas processing plants for the economic
analysis.
Stand-alone TEG units. For this analysis, a stand-alone
TEG unit was assigned to gas production fields that are deeper
than 4,000 feet. This assignment was based on the assumption
that wells that are less than 4,000 feet deep produce "dry
gas" and do not need a stand-alone TEG unit. Data supporting
this assumption are found in the U.S. Department of Energy
report entitled, "Costs and Indices for Domestic Oil and Gas
Field Equipment and Production Operations: 1990-1993." This
report provides cost information for natural gas lease
equipment by type of well, and dehydrators and their
corresponding cost estimates are only listed for well types
greater than 4,000 feet deep.64
*
For gas production fields with well depth greater than
4,000 feet, stand-alone TEG units were assigned based on the
throughput of each field (i.e., a production field producing
25 MMcfd is assigned a model TEG unit C). To approximate the
Total does not sum to 720 since those plants in OGJ processing
survey that indicated no throughput for 1993 were excluded from the
analysis.
4-13
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engineering estimates of the number of model units, it was
necessary to convert some model C and D units initially
assigned to production fields into multiple model A and B
units. Thus, randomly selected model C and D units were
converted to model A and B units according to the ratio of
average throughput per unit (as expressed in MMcfd) (i.e., one
model C unit is equivalent to 125 model A units, one model D
is equivalent to 350 model A units, and one model D unit is
equivalent to 10 model B units) ,65
Condensate tank batteries and associated TEG units.
Model condensate tank batteries were assigned to production
fields based on the throughput of each field (i.e., if a field
produces 2 MMcfd of natural gas, it was assigned a model CTB
E). One TEG unit was assigned to each condensate tank battery
based on throughput capacity so that a TEG unit A was assigned
to each CTB E, a TEG unit B was assigned to each CTB F, a TEG
unit C was assigned to each CTB G, and a TEG unit D was
assigned to each CTB H. To approximate the engineering
estimates of the number of model units, it was necessary to
convert some model CTB F, G, and H units initially assigned to
production fields into multiple model E units. Thus, randomly
selected model F, G, and H units were converted to model E
units according to the ratio of average throughput per unit
(as expressed in MMcfd) (i.e., one model F unit is equivalent
to 10 model E units, one model G is equivalent to 35 model E
units, and one model H unit is equivalent to 100 model E
units)."
TEG units at natural eras processing plants. TEG
dehydration units are also employed at NGPPs. For this
analysis, the allocation of model TEG units to model NGPPs was
based on the engineering analysis so that a model NGPP A is
assigned two model TEG B units, a model NGPP B was assigned
three model TEG C units, and a model NGPP C was assigned three
model TEG D units.
4-14
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After completing the assignment of model units, every
"facility" began with a model production well and ended with a
model natural gas processing plant (e.g., model production
well 1 - TEG dehydration unit A at CTB E - Natural gas
processing plant A). As a result, the level of domestic
production is equal to the level of natural gas processed at
natural gas processing plants during 1993 as provided by the
OG&J processing survey. Table 4-2 provides a summary of the
network of production wells and production facilities by State
for 1993. Because of the uncertainty related to the actual
combinations of production well and processing plants, the
production well-processing facility combinations developed by
RTI to reflect the base year data of 1993 will not be unique--
there are likely other possible combinations of production
wells and processing facilities that are consistent with the
base year data.
4.2.2 Supply of Natural Gas
Producers of natural gas have the ability to vary output
in the face of production cost changes. Production well-
specific upward sloping supply curves for natural gas are
developed to allow domestic producers to vary output in the
face of regulatory control costs. The following sections
provide a description of the production technology
characterizing production at U.S. natural gas fields and the
corresponding supply functions, as well as the foreign
component of U.S. natural gas supply (i.e., imports).
4.2.2.1 Domestic Supply. For this analysis, the
generalized Leontief technology was assumed to characterize
natural gas production at all producing fields. This
formulation allows for projection of supply curves for natural
gas at the field level. In.general, the supply function of a
4-15
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natural gas producing field resulting from the generalized
Leontief technology is:
1/2
(4.1)
z [ r
where
q.j = annual production of natural gas (Mcf) for field
j = 1 to n,
r = national wellhead price of natural gas,
3 = negative supply parameter (i.e., 3 < 0), and
Yj = productive capacity of field j.
Figure 4-4 illustrates the theoretical supply function of
Equation (4.1). As shown, the upward-sloping supply curve is
specified over a productive range with a lower bound of zero
R2
that corresponds with a shutdown price equal to and an
4Y/
upper bound given by the productive capacity of q^ that is
approximated by the supply parameter YJ • The curvature of the
supply function is determined by the 3 parameter (see Appendix
C for a discussion of the derivation and interpretation of
this parameter).
To specify the supply function of Eq. (4-1) for this
analysis, the 3 parameter is computed by substituting the
market supply elasticity for natural gas (£), the wellhead
price of natural gas (r), and the production-weighted average
annual production level of natural gas per well (q) into the
following equation:
f 1 1-1 /2
(4.2)
The market-level supply elasticity for natural gas is assumed
to be 0.2624, which reflects the production-weighted average
4-18
-------
$/q«
qi Ti = q| q,/t
Figure 4-4. Theoretical supply function of natural gas
producing well.
supply elasticity estimated across EPA regions as shown in
Table 4-3." The 1993 wellhead price of natural gas is $2.01
per Mcf and the production-weighted average annual level of
natural gas production per well based on the Gruy database is
131,496 Mcf. The 3 parameter is calculated by incorporating
these values into Equation (4.2) resulting in an estimate of
the 3 parameter equal to -195,674.
Unlike the product-specific 3, the individual supplier-
level elasticity of supply is not constant, but varies across
each producing field with the level of production, q.j. For
high production fields, the elasticity of supply will be low
reflecting the low responsiveness to price changes of large
wells due to high overhead expenses and low extraction costs
as described in the literature. For low production fields,
the elasticity of supply will be high reflecting the high
responsiveness to price changes of "stripper" wells. Since
stripper wells produce a small product volume and have low
4-19
-------
TABLE 4-3. SHORT-RUN SUPPLY ELASTICITY ESTIMATES
FOR NATURAL GAS BY EPA REGION
EPA
Weighted
Source :
Region
1
2
3
4
5
6
average
U.S. Department
Estimates of short-run
elasticities
0.852
0.263
0.207
0.122
0.118
0.463
0.2624
of Energy. Documentation of the
Oil and Gas Supply Module. DOE/EIA-M063. Energy
Information Administration, Oil and Gas Analysis
Branch. Washington, DC. March 1994.
overhead expenses, producers usually respond to fluctuations
in price of oil or gas by ceasing production when revenues
fall below operating costs, and possibly resuming production
when it is profitable.68 As a result, domestic capacity
utilization fluctuates mainly as stripper wells are changed
from idle to production status.
The intercept of the supply function, YJ/ approximates
productive capacity and varies across producing fields. This
parameter does not influence the field's production
responsiveness to price changes as does the 3 parameter.
Thus, the parameter YJ is used to calibrate the model so that
each field's supply equation is exact using the Gruy data.
4.2.2.2 Foreign. The importance of including foreign
imports in the economic model is highlighted by the
significant level of U.S. importation of natural gas that
currently reflects over 10 percent of U.S. domestic
consumption. Thus, the model specifies a general formula for
the foreign supply for natural gas that is:
4-20
-------
q
1 = A1 [r]'1 (4.3)
where
qr = foreign supply of natural gas (Mcf ) ,
A1 = positive constant, and
£: = foreign supply elasticity for natural gas.
Difficulty in estimating foreign trade elasticities has
long been recognized and precludes inclusion of econometric
estimates (new or existing) . International trade theory
suggests that foreign trade elasticities are larger than
domestic elasticities. In fact, at the limit, the foreign
trade elasticities are infinite, reflecting the textbook case
of price-taking in world markets by small open economy
producers and consumers. For this analysis, a value of 0.852
is assumed for the import supply elasticity, which is the
highest domestic supply elasticity estimate from Table 4-3 .
The multiplicative foreign supply parameter, A1, is determined
by backsolving given estimates of the import supply
elasticities, 1993 wellhead price, and the quantities of U.S.
imports 1993 .
4.2.2.3 Market Supply. The market supply of natural
gas (Qs) is the sum of supply from all natural gas producers,
i.e. ,
Qs = q1 + E<3/ (4.4)
where q1 is foreign supply of natural gas and q* is the
j
domestic supply of natural gas, which is the sum of natural
gas production across all U.S. producing fields (j).
4-21
-------
4.2.3 Demand for Natural
Natural gas end users include residential and commercial
customers, as well as industrial firms and electric utilities.
These customer groups have very different energy requirements
and thus quite different service needs. Therefore, the model
specifies a general formula for the demand of natural gas by
end-use sector (q?) , that is,
nd
q^ = Bia [pj "* (4.5)
where
Pi = the end-user price for sector I,
rii = the demand elasticity for end-use sector I,
Bi = a positive constant
The multiplicative demand parameter, B?, calibrates the demand
equation so that each end-use sector replicates its observed
1993 level of consumption given data on price and the demand
elasticity.
Table 4-4 provides the estimates of the demand elasticity
by end-use sector that are employed in the model.69 In a
survey of price elasticities of demand for natural gas,
Al-Sahlawi found that short-run elasticities of demand range
from -0.035 to -0.686 in the residential sector and -0.161 to
-0.366 in the commercial sector.70 As shown in Table 4-4, this
analysis employs the mid-point of the range for each of these
end-use sectors. Industrial demand for natural gas is a
derived demand resulting from producers optimizing the
relative use of fuels that comprise the energy input to the
production function. Based on time-series data across 9 U.S.
states, Beierlin, Dunn, and McConnor used a combination of
error components and seemingly unrelated regression to
4-22
-------
TABLE 4-4. SHORT-RUN DEMAND ELASTICITY ESTIMATES
FOR NATURAL GAS BY END-USER SECTOR
Estimate of the short-run
End-use sector demand elasticity
Residential -0.3605
Commercial -0.2635
Industrial -0.6100
Electric utility' -1.0000
" Value is assumed due to lack of literature estimates of this parameter
for electric utilities. Higher absolute value than other sectors
because of greater fuel-switching capabilities.
Source: Al-Sahlawi, Mohammed A. "The Demand for Natural Gas: A Survey of
Price and Income Elasticities," Energy Journal Vol. 10, No. 1,
January 1989.
estimate a short-run elasticity of -0.61 for natural gas.71 To
the best of our knowledge there exist no studies that estimate
short-run demand elasticities for electric utilities. Because
electric utilities have greater fuel switching capabilities
than other end-users, we assume a more responsive short-run
elasticity of -1 for this group in the model.
The total market demand for natural gas (QD) is the sum
across all consuming end-use sectors, i.e.,
(4.6)
An additional component of natural gas consumption is that
used as lease, plant, and pipeline fuel. This consumption is
fairly constant over time varying only with fluctuations of
natural gas production. For the purposes of this analysis,
this component is treated as an additional end-use sector
consuming at a constant amount without and with the
regulation.
4-23
-------
4.2.4 Incorporating Regulatory Control Costs
The starting point for assessing the market impact of the
regulations is to incorporate the regulatory control costs
into the natural gas production decision. The regulatory
control costs for each model unit are presented in Table 3-9
of Section 3. An additional aspect of the regulation is the
product recovery credit received by natural gas producers as a
result of adding the controls. These credits do not directly
affect the production decisions as do the costs of adding the
pollution controls. Rather these credits are added revenues
that each producer gains after complying with the regulation.
Regulatory scenarios are developed so that the model may
assess the impacts by source category. Thus, the three
regulatory scenarios analyzed are
• major and area sources combined,
• major sources only, and
• area sources only.
The focus of incorporating regulatory control costs into
the model structure is to appropriately assign the costs to
the natural gas flows directly affected by the imposition of
HAP emission controls. This assignment includes the
identification of affected entities and determination of their
control costs and the inclusion of these costs in the
production decision of each affected entity.
4.2.4.1 Affected Entities. For this analysis, affected
units were randomly selected given the percentages provided in
Tables 3-7 through 3-9 of Section 3 and then assigned the
appropriate compliance costs. Specifically, the following
steps were undertaken:
• Each production field was assigned a uniform random
value between 0 and 1 using the 0RAND function in
Lotus 1-2-3.
4-24
-------
• Affected units were determined to be those with a
random value below the percentage affected as given in
Tables 3-7 through 3-9 for each model type (for
example, since 30 percent of model TEG unit A's are
affected under the area source rule, it follows that a
model TEG unit A with a uniform random value less than
or equal to 0.3 is affected, but one with a uniform
random value greater than 0.3 is unaffected).
• Total annual compliance costs, as shown in Table 3-9,
were assigned to affected units and aggregated across
model units for each "facility," or production field-
processing plant combination.
The total annual compliance costs are expressed at the model
unit level and must be converted to a per Mcf basis for
inclusion in the model, i.e., application to affected product
flows. To avoid double counting, compliance costs assigned to
natural gas processing plants are further allocated to the
multiple production fields providing natural gas according to
their share of total natural gas processed at the plant. The
total annual compliance costs per Mcf (G.J) for each affected
production field j are computed as the sum of total annual
compliance costs for affected TEG unit(s), condensate tank
battery, and natural gas processing plant divided by the
annual production level of the field.
4.2.4.2 Natural Gas Supply Decisions. The production
decisions at the individual producing fields are affected by
the total annual compliance costs, c.,, which reflect the shift
in marginal cost and are expressed per Mcf of natural gas.
If the producing field serves an affected stand-alone TEG
unit, condensate tank battery, or natural gas processing
plant, then its supply equation will be directly affected by
the regulatory control costs, which enter as a net price
change, i.e., r.. - c^. Thus, the supply function for producing
fields, assuming the generalized Leontief production
technology becomes:
1/2
(4.7)
= Yj —
r.-c.
4-25
-------
The discussion above assumes that producing natural gas is
profitable. However, in confronting the decision to comply
with the regulation, a producer's optimal choice could be to
produce zero output (i.e., close the production field). As
shown in Figure 4-4, if the net wellhead price (r^ -c^) falls
B2
below the shutdown price of ——, then the producing field's
4Yj2
production response for the supply equation given the
regulatory control costs will be less than or equal to zero
(i.e., q.j < 0) .
4.2.5 Model Baseline Values and Data Sources
Table 4-5 provides the 1993 baseline equilibrium values
for wellhead and end-user prices, domestic and foreign
production, and consumption by end-use sector.72 The level of
domestic production is equivalent to the level of natural gas
processed at natural gas processing plants during 1993 as
obtained from the Oil and Gas Journal's processing survey.73
The consumption level for lease, plant, and pipeline fuel was
adjusted to ensure that national production and consumption
levels were exact for the model's 1993 characterization of the
U.S. natural gas market.
4.2.6 Computing Market Equilibria
This section provides a summary of the model structure
and a description of the equilibria computations of the model.
A complete list of exogenous and endogenous variables, as well
as the model equations, is given in Appendix D.
Producers' responses and market adjustments can be
conceptualized as an interactive feedback process. Producers
4-26
-------
TABLE 4-5. BASELINE EQUILIBRIUM VALUES FOR
ECONOMIC MODEL: 1993
Item
Producers
Domestic
Foreign
Total
Consumers
Residential
Commercial
Industrial
Electric utility
Other
Average /total
Price"
($/Mcf)
$2.01
$2.01
$2.01
$6.15
$5.16
$3.07
$2.61
N/A
$4.16
Quantity
(MMcf }
17,440,586
2,350,115
19,790,701
4,956,000
2,906,000
7,936,000
2,682,000
1,310,701
19,790,701
a For producers, price reflects the national wellhead price. For
consumers, price reflects the appropriate national end-user price.
b For producers, quantity reflects the total production level. For
consumers, quantity reflects the appropriate level of consumption.
Source: Department of Energy. Natural Gas Monthly. Energy
Information Administration, Washington, DC. October 1994.
face increased production costs due to compliance, which
causes individual production responses; the cumulative effect,
which leads to a change in the wellhead price that all
producers (affected and unaffected) face; and the end-user
price that all consumers face, which leads to further
responses by producers (affected and unaffected) as well as
consumers and thus new market prices, and so on.* The new
equilibria after imposition of these regulatory control costs
is the result of a series of iterations between producer and
consumer responses and market adjustments until a stable
End-user prices are determined by adding the new wellhead price to
the absolute markup for each end-user.
4-27
-------
market price arises where total market supply equals total
market demand, i.e.,
Qs = QD .
This process is simulated given the producer and consumer
response functions and market adjustment mechanisms to arrive
at the post-compliance equilibria.
The process for determining equilibrium prices (and
outputs) with the increased production cost is modeled as a
Walrasian auctioneer. The auctioneer calls out a wellhead
price for natural gas (indirectly yielding end-user prices)
and evaluates the reactions by all participants (producers and
consumers, both foreign and domestic) comparing quantities
supplied and demanded to determine the next price that will
guide the market closer to equilibrium, i.e., market supply
equal to market demand. An algorithm is developed to simulate
the auctioneer process and find a new equilibrium price and
quantity for natural gas. Decision rules are established to
ensure that the process will converge to an equilibrium, in
addition to specifying the conditions for equilibrium. The
result of this approach is a combination of wellhead price and
end-user prices with the proposed regulation that equilibrates
supply and demand for the U.S. natural gas market.
The algorithm for deriving the with-regulation
equilibrium can be generalized to five recursive steps:
1) Impose the control cost on the production wells,
thereby affecting their supply decisions.
2) Recalculate the market supply of natural gas.
3) Determine the new wellhead price via the price
revision rule and add appropriate markups to arrive
at end-user prices.
4) Recalculate the supply function of producing fields
and foreign suppliers with the new wellhead price,
resulting in a new market supply of natural gas.
Evaluate end-use consumption levels at the new end-
4-28
-------
user prices, resulting in a new market demand for
natural gas.
Return to Step 3, and repeat steps until equilibrium
conditions are satisfied (i.e., the ratio of market
supply to market demand is equal to 1).
4.3 REGULATORY IMPACT ESTIMATES
The model results can be summarized as market- and
industry- and societal-level impacts due to the regulation.
4.3.1 Market-Level Results
Market-level impacts include the market adjustments in
price (wellhead and end-user) and quantity for natural gas,
including the changes in international trade flows. Table 4-6
provides the market adjustments for each regulatory scenario.
As shown, the percent changes in wellhead and end-use prices
for each regulatory scenario are less than 0.01 percent, with
the major and area sources accounting for comparable shares of
the overall impacts. The market adjustments associated with
the regulation are also negligible in comparison to the
observed trends in the U.S. natural gas market. For example,
between 1992 and 1993, the average annual wellhead price
increased by 14 percent, while domestic production of natural
gas rose by 3 percent.74 The increase in foreign imports of
natural gas is also inconsequential totaling less than 0.01
percent for each regulatory scenario.
4.3.2 Industry-Level Results
Industry-level impacts include an evaluation of the
changes in revenue, costs, and profits; the post-regulatory
compliance cost; production well and natural gas processing
plant closures; and the Change in employment attributable to
the change in industry output. Workers' dislocation costs
associated with industry-wide job losses are also computed.
4-29
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Table 4-7 summarizes these industry-level impacts by
regulatory scenario.
TABLE 4-7. INDUSTRY-LEVEL IMPACTS BY REGULATORY SCENARIO
Major and
area
sources
Major
sources
only
Area
sources
only
Oil and Natural Gas Production Catecrorv
Change in revenues ($106)
Market adjustments
Product recovery
Change in costs ($106)
Post-regulatory
control costs
Costs of production
adjustment
Change in profits ($106)
Closures
Production wells
Natural gas processing
plants
Employment loss
Natural Gas Transmission and
Compliance Costs ($106)
$3.
$0.
$3.
$18.
$18.
-$0.
-$15.
0
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0
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$0.
2
2
0
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9
2
5
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$2
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$7
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$11.
$11.
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0
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1
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4
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4.3.2.1 Post-Recmlatory Compliance Cost. For each
regulatory scenario, the post-regulatory compliance cost at
each facility can be calculated as the product of the total
annual compliance cost per unit (c.j) and the new output rate
(q*'). At the industry-level, the post-regulatory compliance
cost for major and area sources combined is roughly
$19 million and reflects the sum of the total annual
compliance cost across all facilities continuing to operate in
the post-compliance equilibrium. Thus, the post-compliance
cost is not necessarily equal to the estimated compliance
costs before accounting for market adjustments. They differ
because producing wells may close thereby deciding not to bear
4-32
-------
the costs of compliance, and output rates may change at
affected producing wells.
4.3.2.2 Revenue. Production Cost, and Profit Impacts.
The economic model generates information on the change in
individual and market quantities and market price in the oil
and natural gas production industry. This allows computation
of the change in total revenue and total cost at the industry
level. For major and area sources combined, the total
increase in revenue is $3.2 million and includes the change in
product revenue associated with market adjustments ($0.2
million), which is the difference between baseline product
revenue and post-compliance product revenue, and the added
revenue associated with the product recovery credits ($3.0
million). The total increase in production cost is $18.7
million and reflects the post-compliance costs of production
minus the baseline costs of production, which will account for
the increase in costs due to the regulation ($18.9 million)
and the decrease in costs due to the lower output rate ($0.2
million). These costs amount to just 0.004 percent of the
total revenues in 1993 of the 300 largest publicly traded oil
and natural gas producing companies in the U.S.75'76 The
changes in total revenue and total cost are used to measure
the profitability impact of the regulations which indicates a
loss of $15.5 million at the industry level due to regulation.
The cost estimates for the 5 major sources in the natural gas
transmission and storage category were not included in the
market model and are reported separately. They amount to just
over $46,000 annually which represents only 0.2 percent of the
total revenues of the 110 largest gas pipeline companies in
1993.77
The economic model also uses changes in industry revenues
and costs to project closures of producing wells and natural
gas processing plants and to assess employment impacts in the
4-33
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industry. (No closure or employment effects are estimated to
occur.)
4.3.3 Economic Welfare Impacts
The value of a regulatory policy is traditionally
measured by the change in economic welfare that it generates.
Welfare impacts resulting from the regulatory controls on the
oil and natural gas production industry will extend to the
many consumers and producers of natural gas. Consumers of
natural gas will experience welfare impacts due to the
adjustments in price and output of natural gas caused by the
imposition of the regulations. Producer welfare impacts
result from the changes in product revenues to all producers
associated with the additional costs of production and the
corresponding market adjustments. The theoretical approach
used in applied welfare economics to evaluate policies is
presented in Appendix E and indicates our approach to
estimation of the changes in economic welfare.
The market adjustments in price and quantity in the oil
and natural gas production industry were used to calculate the
changes in aggregate economic welfare using applied welfare
economics principles. Table 4-8 shows the estimated economic
welfare change associated with each regulatory scenario.
These estimates represent the social cost of the regulation.
For major and area sources combined, the social cost of the
regulation is $15.96 million with producers of natural gas
incurring over 95 percent of the total burden. An alternative
measure of the social cost is the total annual compliance cost
as estimated by the engineering analysis. However, that
measure fails to account for market adjustments and the fact
that facilities may close and not incur the regulatory costs.
Thus, the main difference between the engineering estimate of
social cost and that derived through economic welfare analysis
4-34
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TABLE 4-8. ECONOMIC WELFARE IMPACTS BY REGULATORY
SCENARIO ($106)
Major and Major Area sources
area sources sources only only
Change in consumer surplus
Change in producer surplus
Domestic
Foreign
Change in economic welfare
-$0.49
-$15.46
-$15.52
$0.06
-$15.96
-$0.32
-$4.33
-$4.36
$0.04
-$4.64
-$0.18
-$11.14
-$11.16
$0.02
-$11.31
is the deadweight loss to society of the reallocation of
resources.
4-35
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SECTION 5
FIRM-LEVEL ANALYSIS
A regulatory action to reduce air emissions from the oil
and natural gas production industry will potentially affect
owners of the regulated entities. Firms or individuals that
own the production wells and processing facilities are legal
business entities that have the capacity to conduct business
transactions and make business decisions that affect the
facility. The legal and financial responsibility for
compliance with a regulatory action ultimately rests with
these owners who must bear the financial consequences of their
decisions. Thus, an analysis of the firm-level impacts of the
proposed EPA regulation involves identifying and
characterizing affected entities, assessing their response
options by modeling or characterizing the decision-making
process, projecting how different parties will respond to a
regulation, and analyzing the consequences of those decisions.
Analyzing firm-level impacts is important for two reasons:
• Even though a production well or processing facility is
projected to be profitable with the regulation in
place, financial constraints affecting the firm owning
the facility may mean that the plant changes ownership.
• The Regulatory Flexibility Act (RFA) requires that the
impact of regulations on all small entities, including
small companies, be assessed.
Environmental regulations such as the proposed NESHAP for
the oil and natural gas production industry affect all
businesses, large and small, but small businesses may have
special problems in complying with such regulations. The RFA
of 1980 requires that special consideration be given to small
entities affected by Federal regulation. Under the 1992
5-1
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revised EPA guidelines for implementing the RFA, an initial
regulatory flexibility analysis (IRFA) and a final regulatory
flexibility analysis (FRFA) will be performed for every rule
subject to the Act that will have any economic impact, however
small, on any small entities that are subject to the rule,
however few, even though EPA may not be legally required to do
so. In 1996, the Small Business Regulatory Enforcement
Fairness Act (SBREFA) was passed, which further amended the
RFA by expanding judicial review of agencies' compliance with
the RFA and by expanding small business review of EPA
rulemaking.
Although small business impacts are expected to be
minimal due to the size cutoffs for TEG dehydration units,*
this firm-level analysis addresses the RFA requirements by
measuring the impacts on small entities in the oil and natural
gas production source category. For reasons discussed below,
it is assumed that there will be no small business impacts on
the natural gas transmission and storage source category.
Small entities include small businesses, small
organizations, and small governmental jurisdictions and may be
defined using the criteria prescribed in the RFA or other
criteria identified by EPA. Small businesses are typically
defined using Small Business Association (SBA) general size
standard definitions for Standard Industrial Classification
(SIC) codes. Firms involved in the oil and natural gas
production industry include producers (majors and
independents), transporters (pipeline companies), and
distributors (local distribution companies) that are covered
by various SIC codes. The relevant industries include SICs
1311 (Crude Petroleum and Natural Gas), 1381 (Drilling Oil and
Gas Wells), 1382 (Oil and Gas Exploration Services), 2911
*TEG dehydration units that process less than 3 MMcfd are not expected
to be affected by the regulation. It follows that the smaller owners would
likely own only units of this type.
5-2
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(Petroleum Refining), 4922 (Natural Gas Transmission), 4923
(Gas Transmission and Distribution) and 4924 (Natural Gas
Distribution). The SBA size standards for these industries
are shown in Table 5-1.
TABLE 5-1. SBA SIZE STANDARDS BY SIC CODE FOR THE OIL AND
NATURAL GAS PRODUCTION INDUSTRY
SBA size standard in
number of
SIC code Description employees/annual
sales
1311
1381
1382
2911
4922
4S23
4924
Crude Petroleum and Natural Gas
Drilling Oil and Gas Wells
Oil and Gas Exploration Services
Petroleum Refining
Natural Gas Transmission
Natural Gas Transmission and
Distribution
Natural Gas Distribution
500
500
$5 million
1,500
$5 million
$5 million
500
The general steps involved in analyzing company-level
impacts include identifying and analyzing the possible options
facing owners of affected facilities and analyzing the impacts
of the regulation including impacts on small companies and
comparing them to impacts on other companies.
5.1 ANALYZE OWNERS' RESPONSE OPTIONS
In reality, owners' response options to the impending
regulation potentially include the following:
• installing and operating pollution control equipment,
• closing or selling the facility, and
• complying with the regulation via process and/or input
substitution (versus control equipment installation).
This analysis assumes that the owners of an affected facility
will pursue a course of action that maximizes the value of the
5-3
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company, subject to uncertainties about actual costs of
compliance and the behavior of other companies.
The market model presented in Section 4 models the
facility- and market-level impacts for natural gas producing
wells and processing facilities under the owners' first two
options listed above. Evaluating facility and market impacts
under the third option listed above requires detailed data on
production costs and input prices; costs and revenues
associated with alternative services/products; and other owner
motivations, such as legal and financial liability concerns,
and is beyond the scope of this analysis. Consequently, this
analysis is based on the assumption that owners of oil and
natural gas production facilities respond to the regulation by
installing and operating pollution control equipment or
discontinuing operations at production wells or process
facilities that they own. The facility- and market-level
impacts, presented in Section 4, were used to assess the
financial impacts to the ultimate corporate owners of oil and
natural gas production facilities.
As a result of the proposed regulations, companies will
potentially experience changes in the costs of oil and natural
gas production as well as changes in the revenues generated by
providing these products. Both cost and revenue impacts may
be either positive or negative. The cost and revenue changes
projected to result from regulating each source category occur
at the facility level as a result of market adjustments. Net
changes in company profitability are derived by summing
facility cost and revenue changes across all facilities owned
by each affected company. The net impact on a company's
profitability may be negative (cost increases exceed revenue
increases) or positive (revenue increases exceed cost
increases).
5-4
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Figure 5-1 characterizes owners' potential responses to
regulatory actions. The shaded areas represent decisions made
at the facility level that are used as inputs to the company-
level analysis. For this analysis, companies are projected to
implement the cost-minimizing compliance option and continue
to operate their facilities. As long as the company continues
to meet its debt obligations, operations will continue.
Realistically, if the company cannot meet its interest
payments or is in violation of its debt covenants, the
company's creditors may take control of the exit decision and
forced exit may occur. If the market value of debt (DM) under
continued operations is greater than the liquidation value of
debt (DL), creditors would probably allow the facility to
continue to operate. Under these conditions, creditors may
renegotiate the terms of debt. If, however, the DM under
continued operations is less than DL, involuntary exit will
result and the facility will discontinue operations. Exit
will likely take the form of liquidation of assets or
distressed sale of the facility. These decisions are modeled
in terms of their financial impact to parent companies. The
decision to continue to operate may be accompanied by a change
in the financial viability of the company.
5.2 FINANCIAL IMPACTS OF THE REGULATION
This analysis evaluates the change in financial status by
computing the with-regulation financial ratios of potentially
affected firms and comparing them to the corresponding
baseline ratios. These financial ratios may include
indicators of liquidity, asset management, debt management,
and profitability. Although a variety of possible financial
ratios provide individual indicators of a firm's health, they
may not all give the same signals. Therefore, this analysis
focuses on changes in key measures of profitability (return on
sales, the return on assets, and the return on equity).
5-5
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Identify
Cost-Minimizing
Compliance Option
r
AVC
DM
DL
With-Reg Wellhead Price
Average Variable Cost
Market Value of Debt
Liquidation Value
of Debt
Indicates that decision
was modeled in the
market analysis
Nat. Gas Well
Closure
Implement
Cost-Minimizing
Compliance Option
Implement Cost-
Minimizing
Compliance Option
and Continue
Operations
Can firm
cover its debt
obligations?
Figure 5-1. Characterization of owner responses to
regulatory action.
5-6
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To assess the financial impacts on the oil and natural
gas production source category, this analysis characterizes
the financial status of a sample of 80 public firms
potentially affected by the regulation. Based on SBA size
standards from Table 5-1, a total of 39 firms in this sample
are defined as small, or 48.8 percent. Baseline financial
statements are developed based on financial information
reported in the OGJ and industry-level financial ratios from
Dun and Bradstreet (D&B). To compute the with-regulation
financial ratios, pro-forma income statements and balance
sheets reflecting the with-regulation condition of potentially
affected firms were developed based on projected with-
regulation costs (including compliance costs) and revenues
(including product recovery credits and the with-regulation
price and quantity changes projected using a market model).
The financial impacts on the natural gas transmission
source category are not assessed because no small entities are
expected to be affected. Only operations with throughput of
500 MMcfd or more will be affected by the proposed rule.2
Information reported in OGJ for the 110 largest gas pipeline
companies indicates that none of the companies with volumes in
the 500 MMcfd range would have qualified as small businesses
(less than $5 million in revenues) in 1994.78 For the
34 companies that did transmit volumes in that range in 1994,
even if all 5 of the TEG units expected to be affected by the
proposed rule were operated by the firm with the smallest
revenues, the annual compliance costs would only represent
0.34 percent of its revenues.
5.2.1 Baseline Financial Statements
Pro-forma income statements and balance sheets reflecting
the 1993 baseline condition of 80 potentially affected firms
2Based on model TEG units in Class E.
5-7
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were developed based on financial information reported in the
OGJ and industry-level financial ratios from D&B.79'80 This
analysis includes 49 firms that listed 1311 as their primary
SIC code, 8 firms under SIC 1382, 14 firms under SIC 2911,
8 firms under SIC 4922, and 1 firm under SIC 4924. Each of
these firms is publicly traded and listed in the OGJ300, which
includes estimates of total revenue, net income, total assets,
and shareholder equity. The remaining financial variables
needed to complete each firm's income statement and balance
sheet were computed using financial ratios computed from the
OGJ data and from the D&B benchmark financial ratios shown in
Table 5-2. Appendix F provides more detailed firm-by-firm
financial data for the 80 sample firms.
This analysis employed probability distributions of the
D&B benchmark ratios rather than point estimates to compute
the remaining financial variables. The probability
distributions for each financial ratio listed in Table 5-2
were generated using ©RISK, a risk analysis software add-on
for Lotus 1-2-3. In projecting the baseline financial
statements, the D&B benchmark ratios were modeled as a
triangular distribution with the median value reflecting the
most likely value of the distribution and the lower and upper
quartile values reflecting the 25th and 75th percentile values
of the distribution. ©RISK randomly selected a value from the
probability distribution of each financial ratio and combined
these values with the OGJ data to project the baseline income
statement and balance sheet for each firm.
5.2.2 With-Reaulation Financial Statements
Before adjusting the baseline financial statements, the
regulatory control costs must be mapped from processing
facilities to the firms that own them. Mapping the regulatory
costs to firms requires knowledge of the number of processing
facilities owned by each firm and the extent that they are
5-8
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TABLE 5-2. DUN AND BRADSTREET'S BENCHMARK FINANCIAL RATIOS
BY SIC CODE FOR THE OIL AND NATURAL GAS PRODUCTION INDUSTRY
SIC code/ financial ratio
1311-Crude Petroleum and Natural Gas
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
1381-Drilling Oil and Gas Wells
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
13 82 -Oil and Gas Exploration Services
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth {%)
2 9 11 -Petroleum Refining
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
4922-Natural Gas Transmission
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
Lower
quartile
0
0
84
133
0
1
92
123
0
0
77
129
0
1
97
220
0
0
105
264
.6
.8
.0
.5
.8
.0
.8
.5
.5
.8
.3
.9
.5
.1
.9
.1
.3
.8
.9
.7
Median
1.
1.
30.
64.
1.
1.
37.
74.
1.
1.
33.
70.
0.
1.
68.
169.
0.
1.
50.
175.
1
5
9
0
3
7
1
6
0
3
4
0
7
3
3
9
7
0
7
7
Upper
quartile
2
3
9
22
2
4
11
27
1
3
10
22
0
1
37
103
1
1
29
111
.3
.5
.7
.2
.7
.2
.2
.5
.9
.4
.0
.3
.9
.9
.7
.8
.0
.5
.4
.4
(continued)
5-9
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TABLE 5-2. DUN AND BRADSTREET'S BENCHMARK FINANCIAL RATIOS
BY SIC CODE FOR THE OIL AND NATURAL GAS PRODUCTION INDUSTRY
(CONTINUED)
SIC code /financial ratio
4923-Gas Transmission and Distribution
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
4924-Natural Gas Distribution
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
Lower
quartile
0
0
127
229
0
0
99
225
.3
.7
.6
.3
.4
.8
. 2
.0
Median
0
1
65
144
0
1
57
176
.7
.0
.6
.3
.7
.0
.9
.9
Upper
quartile
1
1
30
104
1
1
35
86
.1
.4
.4
.8
.1
.4
.4
.8
Source: Dun's Analytical Services. Industry Norms and Key Business
Ratios. Dun and Bradstreet, Inc. 1994.
affected by the regulation. The market model did not
explicitly link firms to their respective processing
facilities. Thus, this analysis relies on firm responses to
EPA's Air Emissions Survey Questionnaires to determine
ownership of TEG dehydration units and condensate tank
batteries and the OGJ's Special Report, "Worldwide Gas
Processing," to determine ownership of natural gas processing
plants operating in the U.S. as of January 1994.81
Table 5-3 provides the ratio of model TEG units to total
assets as computed from the EPA survey data. These ratios
reflect the average of firms within the natural gas production
groups as defined in the table. To estimate the number of
model TEG units for each firm, the total assets of the firm
were multiplied by the appropriate ratios. The number of
model CTBs for each firm was estimated according to the ratio
of CTBs to TEG units by model type. In addition, the number
5-10
-------
* u /o -
60% -
? 50% -
o 40% -
c
S 30% -
£ 20% -
10% -
0% -
*
,.
r
- Weighted Avg. = 0.090%
Maximum = 1.1% y
I — , ^
0.0% 0.1% 0.2% 0.3% 0.4% 0.5% 0.6% 0.7% 0.8% 0.9% 1.0% 1.1% 1.2%
Cost-Sales Ratio (%)
(a) Small Companies
I \J /o -
60% -
s* 50% -
o" 40% -
C
§ 30% -
cr
£ 20% -
10% -
0% -
•'•'
•"•"
1 Maximum = 0.187%
/
r
•
.0% 0.1% 0.2% 0.3% 0.4% 0.5% 0.6% 0.7% 0.8% 0.9% 1.0% 1.1% 1.2%
Cost-Sales Ratio (%)
(b) Large Companies
60% -
£ 50% -
o 40% -
S 30% -
£ 20% -
u.
10% -
0% -
^
'*
"^ Weighted Avg. = 0.013%
0.0% 0.1% 0.2% 0.3% 0.4% 0.5% 0.6% 0.7% 0.8% 0.9% 1.0% 1.1% 1.2%
Cost-Sales Ratio (%)
(c) Total, All Companies
Figure 5-2. Distribution of total annual compliance cost to
sales ratio for sample companies.
5-12
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TABLE 5-3. DISTRIBUTION OF MODEL TEG UNITS BY FIRM'S LEVEL
OF NATURAL GAS PRODUCTION
Model TEG units per
Natural gas
production
>500
175
100
Bcf
to 500 Bcf
to 175 Bcf
10 to 100 Bcf
<10
Bcf
0
0
0
0
1
A
.30259
.40071
.36200
.41223
.15830
($10
B
0
0
0
0
0
.05663
.07447
.09000
.02660
.00000
0
0
0
0
0
') of assets
C
.00890
.00355
.00600
.00000
.00000
0
0
0
0
0
D
.00405
.00532
.01800
.00665
.00000
of model natural gas processing plants owned by each firm was
estimated given the company name and 1993 throughput of
natural gas as provided in the OGJ.
In the absence of information on the number of affected
units owned by each firm, this analysis assumed that each TEG
unit, CTB, and processing plant owned by each firm is expected
to be affected by the regulation—the worst-case scenario for
each firm. Affected firms typically incur three types of
costs because of regulation: capital, operating, and
administrative. The capital cost is an initial lump sum
associated with purchasing and installing pollution control
equipment. Operating costs are the annually recurring costs
associated with operation and maintenance of control
equipment, while administrative costs are annually recurring
costs associated with emission monitoring, reporting, and
recordkeeping. Figure 5-2 provides an indication of the
burden of the regulatory costs on sample firms in the oil and
natural gas production source category by size. This figure
shows the distribution of total annual compliance cost
(annualized capital plus the annual operating and
administrative cost) as a percentage of baseline sales across
sample firms by size. As shown, the mean level of regulatory
burden for small firms in the sample if 0.09 percent of sales
5-11
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with a maximum level of 1.1 percent of sales. Alternatively,
the mean level of regulatory burden for large firms in the
sample is 0.01 percent of sales with a maximum level of
0.19 percent.
Several adjustments were made to the baseline financial
statements of each firm to account for the regulation-induced
changes at all facilities owned by the firm. Table 5-4 shows
the adjustments made to the baseline financial statements to
develop the with-regulation financial statements that form the
basis of this analysis.
In the annual income statement, the baseline annual
revenues are increased by the projected product recovery
credits earned by each firm and by the expected change in
operating revenues of less than 0.01 percent based on the
regulation induced market adjustments. Furthermore, the
baseline operating expenses are increased by the estimated
change in operating and maintenance costs across TEG units and
NGPPs owned by the firm, while the firms' other expenses also
increase due to the interest charges and depreciation
associated with the acquired pollution control equipment.
In the balance sheet, changes occur to only those firms
that incur capital control costs and are determined by the
manner in which firms acquire the pollution control equipment.
These firms face three choices in funding the acquisition of
capital equipment required to comply with the regulation.
These choices are
• debt financing,
• equity financing, or
• a mixture of debt and equity financing.
Debt financing involves obtaining additional funds from
lenders who are not owners of the firm: they include buyers
of bonds, banks, or other lending institutions. Compliance
5-13
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TABLE 5-4.
CALCULATIONS REQUIRED TO SET UP WITH-REGULATION
FINANCIAL STATEMENTS
Financial statement
category
Calculations
Income statement
Annual revenues
Cost of sales
Gross profit
Expenses due to
regulation
Other expenses
and taxes
Net income
Balance sheet
Baseline annual revenues + product recovery
credits + projected revenue change due to
market adjustments.
Baseline cost of sales + operating and
maintenance cost of regulation.
Annual revenues - cost of sales.
Interest: Projected share of capital costs
financed through debt times the debt interest
rate (7%) .
Depreciation: 7.5% times the annualized
capital costs.
(Gross profit - estimated expense due to
regulation) times the baseline ratio of other
expenses and taxes to gross profit.
Gross profit - estimated expense due to
regulation - other expenses and taxes.
Current assets
Fixed assets
Other noncurrent
assets
Total assets
Current
liabilities
.Concurrent
liabilities
Total liabilities
Net worth
Baseline current assets - [(1 - debt ratio)
times total capital cost].
Baseline fixed assets + total capital cost.
No change from baseline.
Current assets + fixed assets + other
noncurrent assets.
Baseline current liabilities + amortized
compliance cost financed through debt -
estimated interest expense.
Baseline noncurrent liabilities + (debt ratio
times total capital cost) - current portion of
debt.
Current liabilities + noncurrent liabilities.
Total assets - total liabilities.
Note: Depreciation expense is based on the first year's allowable deduction
for industrial equipment under the modified accelerated cost recovery
system.
costs not financed through debt are financed using internal or
external equity. Internal equity includes the current portion
of the company's retained earnings that are not distributed in
5-14
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the form of dividends to the owners (shareholders) of the
company, while external equity refers to newly issued equity
shares. Each source differs in its exposure to risk, its
taxation, and its costs. In general, debt financing is more
risky for the firm than equity financing because of the legal
obligation of repayment, while borrowing debt can allow a firm
to reduce its weighted average cost of capital because of the
deductibility of interest on debt for State and Federal income
tax purposes. The outcome is that a tradeoff associated with
debt financing for each firm exists and it depends on the
firm's tax rates, its asset structures, and their inherent
riskiness.
Leverage indicates the degree to which a firm's assets
have been supplied by, and hence are owned by, creditors
versus owners. Leverage should be in an acceptable range,
indicating that the firm is using enough debt financing to
take advantage of the low cost of debt, but not so much that
current or potential creditors are uneasy about the ability of
the firm to repay its debt. The debt ratio (d) is a common
measure of leverage that divides all debt, long and short
term, by total assets. Empirical evidence shows that capital
structure can vary widely from the theoretical optimum and yet
have little impact on the value of the firm.82 Consequently,
it was assumed that the current capital structure, as measured
by the debt ratio, reflects the optimal capital structure for
each firm. Thus, for this analysis, each firm's debt ratio
for 1993 determines the amount of capital expenditures on
pollution control technology that will be debt financed. That
portion not debt financed is assumed to be financed using
internal equity.
Thus, on the assets side of the balance sheet of affected
firms, current assets decline by (1-d) times the total capital
cost (EK), while the value of property, plant, and equipment
(fixed assets) increases by the total capital cost (i.e., the
5-15
-------
value of the pollution control equipment). Thus, the overall
increase in a firm's total assets is equal to that fraction of
the total capital cost that is not paid out of current assets
(i.e. , d*EK) .
The liabilities side of the balance sheet is affected
because firms enter new legal obligations to repay that
fraction of the total capital cost that is assumed to be debt
financed (i.e., d*EK) . Long-term debt, and thus total
liabilities, of the firm is increased by this dollar amount
less the interest expense paid during the year. Owner's
equity, or net worth at these firms, is increased by only the
amount of interest expense paid during the year due to the
offsetting increases in both total assets and total
liabilities regarding the acquisition of the pollution control
equipment. Moreover, working capital at each affected firm,
defined as current assets minus current liabilities,
unambiguously falls because of the decline in current assets
and the increase in current liabilities.
Comparison of the baseline and with-regulation financial
statements of firms in the U.S. oil and natural gas production
industry provides indicators of the potential disparity of
economic impacts across small and large firms. These
indicators include the key measures of profitability (return
on sales, return on assets, and return on equity) and changes
in the likelihood of financial failure or bankruptcy (as
measured by Altman's Z-score).
5.2.3 Profitability Analysis
Financial ratios may be categorized as one of five
fundamental types:
• liquidity or solvency
• asset management
• debt management
5-16
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• profitability
• market value 3
Profitability is the most comprehensive measure of the
firm's performance because it measures the combined effects of
liquidity, asset management, and debt management. Analyzing
profitability is useful because it helps evaluate both the
incentive and ability of firms in the oil and natural gas
production industry to incur the capital and operating costs
required for compliance. More profitable firms have more
incentive than less profitable firms to comply because the
annual returns to doing business are greater. In the extreme,
a single-facility firm earning zero profit has no incentive to
comply with a regulation imposing positive costs unless the
entire burden of the regulation can be passed along to
consumers. This same firm may also be less able to comply
because its poor financial position makes it difficult to
obtain funds through either debt or equity financing.
As shown in Table 5-5, three ratios are commonly used to
measure profitability: return on sales, return on assets, and
return on equity. For all these measures, higher values are
unambiguously preferred over lower values. Negative values
result if the firm experiences a loss.
TABLE 5-5. KEY MEASURES OF PROFITABILITY
Measure of profitability
Formula for calculation
Return on sales
Return on assets
Return on equity
Net income
Sales
Net income
Total assets
Net income
Owner's equity
5-17
-------
Table 5-6 provides the summary statistics for each of the
measures of profitability. The summary statistics include the
mean, minimum, and maximum values for each measure in the
baseline and with-regulation conditions across small, large,
and all firms included in this analysis. A comparison of the
values in baseline and after imposition of the regulation
provides much detail on the distributional changes in these
profitability measures across firms.
TABLE 5-6. SUMMARY STATISTICS FOR KEY MEASURES OF
PROFITABILITY IN BASELINE AND WITH-REGULATION BY
FIRM SIZE CATEGORY
Measure of
prof itabili ty/ summary
statistics
Return on sales
Mean
Minimum
Maximum
Return on assets
Mean
Minimum
Maximum
Return on equity
Mean
Minimum
Maximum
Baseline
Small
firms
8.05
-43.99
70.15
5.83
-10.34
62.22
9.00
-91.37
90.35
Large All
firms firms
3.71 5.82
-17.29
29.47
2.72 4.24
-7.16
16.59
6.16 7.54
-33.40
26.43
With
Small
firms
7.87
-44.30
69.82
5.76
-10.42
62.22
8.80
-91.78
89.85
regulation
Large
firms
3.66
-17.33
29.30
2.70
-7.18
16.49
6.10
-33.64
26.26
All
firms
5.71
4.19
7.41
As Table 5-6 illustrates, the mean return on sales
slightly declines for all firms after imposition of the
regulation from 5.82 percent to 5.71 percent. This slight
decline is shared across small and large firms. Further, the
mean return on assets declines to some extent for all firms
with regulation from 4.24 percent to 4.19 percent. This
inconsiderable decline in the mean return on assets is found
for small and large firms alike. As measured across all
firms, the with-regulation mean return on equity declines
slightly from 7.54 percent to 7.41 percent. As a group, the
financial impacts associated with the regulation are
5-18
-------
negligible and show no overall disproportionate impact across
small and large firms.
5-19
-------
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16. Ref. 14.
17. Ref. 6.
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19. Ref. 9.
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27. U.S. Department of Energy. Natural Gas 1994: Issues
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28. Haun, Rick R. U.S. Gas Processing Prospects to Improve
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30. Ref. 14.
31. U.S. Department of Energy. Natural Gas 1992: Issues
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1993.
32. Gruy Engineering Corporation. Estimates of RCRA
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Petroleum Institute. July 20, 1991.
33. "Producing Gas Well Numbers Still Climbing," World Oil.
215_(2):77, February 1994.
34. Ref. 32.
R-2
-------
35. Ref. 4, Table B-l.
36. Memorandum from Akin, Tom, EC/R Incorporated to Smith,
Martha E., EPA/CPB. July 30, 1993. Revised
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37. Memorandum from Viconovic, George, EC/R Incorporated,
to Smith, Martha E., EPA/CPB. April 8, 1993. Summary
of meeting with the Gas Research Institute.
38. Ref. 1, p. 2-3.
39. "Worldwide Gas Processing Report." Oil and Gas
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40. Ref. 39.
41. U.S. Department of Commerce. Census of Mineral
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Washington, DC. 1995. Table 1.
42. Ref. 41, Table 10.
43. Ref. 27.
44. Ref. 27.
45. Ward's Business Directory. Volume 2. Washington, DC.
1993.
46. "Total Earnings Rose, Revenues Fell in 1993 for OGJ300
Companies." Oil and Gas Journal. 9_2.(36) :49-75.
September 5, 1994.
47. Ref. 27.
48. "Profits for OGJ Group Show Big Gain in 1993; Revenues
Dip." Oil and Gas Journal. 9_2_ (24): 25-30 . June 13,
1994.
49. "U.S. Interstate Pipelines Ran More Efficiently in
1994." Oil and Gas Journal. November 27, 1995.
p. 39-58.
50. Ref. 1, Chapter 4.
51. Ref. 1, p. 2-4.
52. Ref. 39.
53. U.S. Department of the Interior/Minerals Management
Service. Federal Offshore Statistics: 1993 (OCS Report
MMS 94-0060). Herndon, VA. 1994.
R-3
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54. Ref. 1, Table 3-1.
55. Ref. 1.
56. Ref. 1.
57. U.S. Environmental Protection Agency. Oil and Natural
Gas Production: An Industry Profile. Office of Air
Quality Planning and Standards, Research Triangle Park,
NC. October 1994. p. 4.
58. Farzin, Yeganeh Hossein. Competition in the Market for
an Exhaustible Resource. Jai Press, 1986.
59. Crimer, Jacques. Models of the Oil Market. Harwood
Academic Publishers, 1991.
60. Ref. 23, p. 477-517.
61. Ref. 23.
62. Bradley, M.E., and Wood, A.R.O. "Forecasting Oilfield
Economic Performance," JPT. November 1994.
p. 965-971.
63. Ref. 39, p. 63-109.
64. U.S. Department of Energy. Costs and Indices for
Domestic Oil and Gas Field Equipment and Production
Operations: 1990-1993. Energy Information
Administration, Washington, DC. July 1994. Appendices
H through M.
65. Ref. 1, Table 4-1.
66. Ref. 1, Table 4-1.
67. U.S. Department of Energy. Documentation of the Oil
and Gas Supply Module (OGSM) DOE/EIA-M063. Energy
Information Administration, Oil and Gas Analysis
Branch, Washington, DC. March 1994.
68. Science Application International Corporation. The Oil
and Gas Exploration and Production Industry: Trends
1985-2000. Draft report prepared for the U.S.
Environmental Protection Agency, Office of Solid Waste.
April 1993.
69. Al-Sahlawi, Mohammed A. "The Demand for Natural Gas: A
Survey of Price and Income Elasticities," Energy
Journal 10(1) January 1989.
70. Ref. 69.
R-4
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71. Ref. 69.
72. U.S. Department of Energy. Natural Gas Monthly.
Energy Information Administration, Washington, DC.
Tables 18, 19, 20, and 21. October 1994.
73. Ref. 39, p. 63.
74. Ref. 72, Table 4.
75. Ref. 46.
76. Dun's Analytical Services. Industry Norms and Key
Business Ratios. Dun and Bradstreet, Inc. 1994.
77. Ref. 49.
78. Ref. 49.
79. Ref. 46.
80. Ref. 76.
81. Ref. 39.
82. Brigham, Eugene F., and Louis C. Gapenski. Financial
Management: Theory and Practice. 6th Ed. Orlando,
FL, The Dryden Press. 1991.
83. Ref. 82.
R-5
-------
APPENDIX A
GRUY ENGINEERING CORPORATION'S
OIL WELLGROUPS BY STATE
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE
State/
wellgroup
Alaska
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
AKOIL
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Depth
range
(Mft)
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10+
10+
10+
10+
10+
10+
10 +
10+
BOE
range
(BOE /mo)
0- 60
61- 100
201- 300
401- 500
601-1,000
1,0001-
2,000
2,001-5,000
5, 001-over
1,001-2,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
61- 100
101- 200
301- 400
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
Number
of
wells
4
2
2
1
1
6
23
67
1
2
1
5
2
3
1
1
2
5
14
27
613
2
2
1
1
6
11
31
704
Number
of
fields
3
2
2
1
1
4
7
10
1
1
1
1
2
1
1
1
3
3
5
6
7
2
2
1
1
6
6
9
10
Gas rate
per well
(Mcfd)
12
31
91
42
54
610
2,233
176,855
100
32,719
2
1
3
16
14
34
60
160
546
2,778
1,732,915
26
50
22
2
161
472
5,214
2,990,463
.43
.33
.17
.80
.17
.07
.33
.57
.50
.13
.20
.93
.33
.30
.10
.97
.73
.77
.37
.30
.13
.10
.03
.93
.03
.20
.47
.00
.67
Oil rate
per well
(Bd)
1
0
0
14
17
187
2,142
37,691
50
6,184
0
3
4
15
8
10
29
94
463
2,250
808,289
0
0
10
18
57
348
2,726
1,039,351
.33
.17
.70
.27
.53
.30
.23
.77
.27
.60
.27
.57
.97
.40
.90
.97
.93
.03
.40
.57
.93
.33
.67
.13
.10
.43
.40
.60
.67
(continued)
A-l
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellqroup
Alabama
ALOIL 1
ALOIL 2
ALOIL 3
ALOIL 4
ALOIL 5
ALOIL 6
ALOIL 7
ALOIL 8
ALOIL 9
ALOIL 10
ALOIL 11
ALOIL 12
ALOIL 13
ALOIL 14
ALOIL 15
ALOIL 16
ALOIL 17
ALOTL 18
ALOIL 19
ALOIL 20
ALOIL 21
ALOIL 22
ALOIL 23
ALOIL 24
ALOIL 25
ALOIL 26
ALOIL 27
ALOIL 28
ALOIL 29
ALOIL 30
ALOIL 31
ALOIL 32
ALOIL 33
Depth
range
(Mft)
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10+
10+
10+
10 +
10+
BOE
range
(BOE /mo)
0- 60
61- 100
101- 200
201- 300
301- 400
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
0- 60
201- 300
401- 500
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
101- 200
201- 300
301- 400
401- 500
501- 600
Number
of
wells
2
4
11
443
50
54
36
8
20
7
18
15
49
38
23
13
11
8
4
1
2
1
1
4
6
11
1
7
1
2
7
2
2
Number
of
fields
3
3
6
4
4
3
5
3
6
4
6
7
11
10
7
4
7
4
4
1
3
1
1
3
4
4
1
1
1
3
4 .
3
3
Gas rate
per well
(Mcfd)
0.00
5.13
6.13
324.13
0.00
188.63
138.47
107.40
2,093.50
1,808.80
3.07
61.97
148.47
1C3.07
124.03
4.90
214.97
19.50
156.30
162.50
0.00
0.00
0.40
1.07
5.53
37.53
13.03
0.10
0.00
0.17
31.53
6.30
8.33
Oil rate
per well
(Bd)
1.90
7.73
43.53
3,587.97
505.47
762.30
665.37
362.10
1,755.03
2,062.70
6.20
22.30
185.97
254.83
191.57
148.47
129.83
138.43
57.00
57.20
1.43
9.00
16.27
49.10
231.03
680.23
202.33
2.03
5.53
10.17
66.90
30.17
28.90
(continued)
A-2
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
ALOIL 34
ALOIL 35
ALOIL 36
ALOIL 37
Arkansas
AROIL 1
AROIL 2
AROIL 3
AROIL 4
AROIL 5
AROIL 6
AROIL 7
AROIL 8
AROIL 9
AROIL 10
AROIL 11
AROIL 12
AROIL 13
AROIL 14
AROIL 15
AROIL 16
AROIL 17
AROIL 18
AROIL 19
AROIL 20
AROIL 21
AROIL 22
AROIL 23
AROIL 24
AROIL 25
AROIL 26
AROIL 27
AROIL 28
AROIL 29
Depth
range
(Mft)
10+
10+
10+
10+
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
BOE
range
(BOE /mo)
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
Number
of
wells
7
12
25
33
1484
704
560
156
231
31
47
41
109
4
5
694
320
399
148
69
31
16
45
26
7
18
14
88
64
43
20
12
50
Number
of
fields
7
10
18
17
48
47
56
33
21
15
8
13
12
4
6
51
60
98
55
41
24
14
27
19
6
11
10
40
25
21
12
7
20
Gas rate
per well
(Mcfd)
113.43
382.23
1,557.57
4,389.67
28.77
7.93
26.17
138.67
32.70
38.27
227.73
3,222.50
0.00
178.27
912.30
1.97
9.87
46.00
119.83
11.33
70.40
3.70
410.07
106.53
159.07
55.43
61.17
213.93
284.63
581.80
179.23
343.30
1,652.83
Oil rate
per well
(Bd)
130.43
381.27
2,214.33
6,605.90
1,176.03
1,722.60
2,474.17
1,186.97
2,793.13
421.93
790.53
871.00
4,341.50
339.43
1,529.90
672.57
798.87
1,883.33
1,150.90
782.20
435.47
272.23
1,049.20
1,022.90
577.90
16.10
17.60
295.27
460.67
403.17
264.17
167.93
1,033.10
(continued)
A-3
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellqroup
AROIL 30
AROIL 31
AROIL 32
AROIL 33
AROIL 34
AROIL 35
AROIL 36
AROIL 37
AROIL 38
AROIL 39
AROIL 40
AROIL 41
Arizona
AZOIL 1
AZOIL 2
AZOIL 3
AZOIL 4
AZOIL 5
AZOIL 6
AZOIL 7
AZOIL 8
AZOIL 9
AZOIL 10
AZOIL 11
AZOIL 12
AZOIL 13
Depth
range
(Mft)
6-10
6-10
6-10
10+
10+
10+
10+
10+
10+
10+
10+
10+
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
California-Coastal and
CACNOIL 1
CACNOIL 2
CACNOIL 3
CACNOIL 4
CACNOIL 5
CACNOIL 6
CACNOIL 7
0-2
0-2
0-2
0-2
0-2
0-2
0-2
BOE
range
(BOE /mo)
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
201- 300
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
101- 200
301- 400
401- 500
601-1,000
2,001-5,000
0- 60
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
2,001-5,000
Northern
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
Number
of
wells
26
10
1
1
1
2
1
1
4
7
2
2
1
1
1
3
4
1
1
5
2
1
1
2
2
322
169
292
160
119
68
47
Number
of
fields
10
8
1
1
1
3
1
1
5
6
3
2
1
1
1
1
1
1
1
1
1
1
1
1
1
59
44
58
36
39
29
23
Gas rate
per well
(Mcfd)
2,247.10
3,947.77
1,600.67
3.37
8.30
7.50
94.53
5.63
245.33
1,394.40
1,465.73
2,320.40
4.17
7.83
44.47
56.30
4.40
0.00
5.77
94.73
34.83
0.00
69.10
55.03
0.00
131.83
395.40
1,228.53
1,031.03
1,348.27
567.50
522.53
Oil rate
per well
(Bd)
904.40
561.43
70.67
0.33
1.57
12.27
7.17
16.57
85.77
178.70
54.17
135.63
4.20
9.47
9.97
42.47
121.90
0.83
4.27
31.37
18.50
16.20
12.60
40.63
71.33
229.57
324.37
1,066.93
1,022.10
1,085.70
836.27
744.30
(continued)
A-4
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellaroup
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOTL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
Depth
range
(Mft)
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10+
10+
10+
10+
10+
10+
10+
10+
BOE
range
(BOE /mo)
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
Number
of
wells
113
94
31
8
279
221
569
357
234
204
115
301
141
59
3
49
33
118
86
71
61
51
106
117
67
13
6
8
17
23
38
31
24
60
Number
of
fields
27
19
6
5
50
38
52
47
36
36
34
41
33
16
4
21
15
24
29
21
21
21
24
23
17
7
5
4
5
8
7
6
8
11
Gas rate
per well
(Mcfd)
2,038.
3,100.
1,615.
2,942.
443.
900.
4,091.
3,096.
3,086.
2,938.
2,217.
5,214.
3,367.
2,295.
280.
36.
124.
814.
880.
874.
883.
S61.
3,073.
4,871.
7,494.
2,657.
2.
16.
64.
111.
373.
643.
574.
1,507.
60
00
53
90
53
30
27
80
40
60
93
47
53
00
53
93
63
27
03
43
33
67
13
77
27
97
50
20
67
93
03
10
00
80
Oil rate
per well
(Bd)
2,436
3,650
2,699
792
156
418
2,135
2,382
2,245
2,612
1,808
6,883
5,908
5,474
594
29
44
406
509
624
718
699
2,277
4,637
5,325
1,990
2
13
71
156
363
357
310
1,263
.70
.87
.20
.70
.53
.27
.80
.10
.27
.60
.53
.57
.23
.37
.67
.83
.20
.80
.93
.00
.00
.07
.73
.63
.87
.10
.50
.77
.73
.40
.70
.33
.73
.60
(continued)
A-5
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
• • Depth
State/ range
wellgroup (Mft)
CACNOIL 42
CACNOIL 43
CACNOIL 44
California-Los
CALAOIL 1
CALAOIL 2
CALAOIL 3
CALAOIL 4
CALAOIL 5
CALAOIL 6
CALAOIL 7
CALAOIL 8
CALAOIL 9
CALAOIL 10
CALAOIL 11
CALAOIL 12
CALAOIL 13
CALAOIL 14
CALAOIL 15
CALAOIL 16
CALAOIL 17
CALAOIL 18
CALAOIL 19
CALAOIL 20
CALAOIL 21
CALAOIL 22
CALAOIL 23
CALAOIL 24
CALAOIL 25
CALAOIL 26
CALAOIL 27
CALAOIL 28
CALAOIL 29
CALAOIL 30
10 +
10 +
10 +
Angeles
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
BOB
range
(BOB /mo)
1,001-2,000
2,001-5,000
5,001- Over
Basin
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2.001-5,000
5, 001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
Number
of
wells
63
36
3
382
291
591
396
232
177
111
273
174
48
1
189
176
493
415
282
230
176
396
239
59
1
60
35
112
83
75
67
32
86
Number
of
fields
10
7
1
29
24
37
40
32
30
24
37
30
20
1
30
30
39
38
37
34
29
44
32
19
1
19
21
22
29
28
24
24
29
Gas rate
per well
(Mcfd)
1,683.30
3,053.70
350.20
191.60
505.17
1,261.77
1,408.10
1,037.03
1,001.27
673.20
2,385.63
2,376.10
1,258.47
15.00
124.23
195.30
1,136.43
1,342.37
1,398.13
1,290.00
954.37
3,133.57
3,014.03
2,009.57
40.20
19.93
102.77
470.30
754.53
1,036.40
1,073.30
564.90
1,894.23
Oil rate
per well
(Bd)
2,602.90
3,251.53
565.37
319.37
631.47
2,516.60
2,896.70
2,493.33
2.395.53
1,881.97
6,438.13
7,559.20
4,424.30
192.43
128.73
377.67
2,154.20
3,011.63
2,921.70
3,135.20
3,027.90
9,435.87
9,753.57
4,674.80
168.53
36.80
67.87
451.67
540.47
706.13
812.03
490.37
1,951.50
(continued)
A-6
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
Depth
range
(Mft)
31
32
33
34
35
36
37
38
39
40
41
42
43
44
California-San
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
1
2
3
4
5
6
7
8
9'
10
11
12
13
14
15
16
17
16
19
6-10
6-10
6-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
Jose
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
BOE
range
(BOE /mo)
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
Basin
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
Number
of
wells
75
46
10
3
1
6
4
9
5
5
7
7
8
1
3812
2369
4493
3091
2474
2050
1541
3920
2971
1137
266
1280
865
1400
83C
447
303
254
660
Number
of
fields
21
11
5
1
1
6
4
6
5
4
5
6
4
1
77
56
54
45
32
34
24
31
24
20
9
57
52
55
53
40
31
26
27
Gas rate
per 'well
(Mcfd)
2,006
2,038
449
11
2
4
9
138
111
59
202
226
417
255
520
743
1,963
1,703
1,770
1,639
1,715
4,760
9,799
21,738
110,704
985
1,736
7,310
8,410
6,593
6,641
6,752
29,171
.37
.97
.97
.50
.40
.67
.43
.80
.77
.23
.73
.40
.00
.63
.23
.10
.40
.93
.13
.00
.33
.87
.00
.57
.47
.90
.33
.10
.87
.17
.60
.80
.67
Oil rate
per well
(Bd)
3
4
1
2
5
19
23
26
28
26
96
127
102
61
1
5
5
4
3
3
12
,183
,551
,982
1
2
30
22
74
62
67
138
339
749
225
,968
..237
,634
,541
,934
,980
,846
,300
,933
,768
,404
999
,862
,482
,453
,038
,468
,595
,5-79
.70
.50
.90
.00
.40
.67
.40
.40
.10
.57
.60
.47
.67
.73
.03
.23
.90
.70
.10
.40
.50
.23
.63
.57
.97
.33
.63
.23
.63
.97
.57
.77
.37
(continued)
A-7
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
CASJOIL 20
CAS JO I L 21
CASJOIL 22
CASJOIL 23
CASJOIL 24
CASJOIL 25
CASJOIL 26
CASJOIL 27
CASJOIL 28
CASJOIL 29
CASJOIL 30
CASJOIL 31
CASJOIL 32
CASJOIL 33
CASJOIL 34
CASJOIL 35
CASJOIL 36
CASJOIL 37
CASJOIL 38
CASJOIL 39
CASJOIL 40
CASJOIL 41
CASJOIL 42
CASJOIL 43
CASJOIL 44
Colorado
COOIL 1
COOIL 2
COOIL 3
COOIL 4
COOIL 5
COOIL 6
COOIL 7
COOIL 8
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10 +
10 +
10 +
10+
10 +
10+
10 +
10 +
10 +
10 +
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-?
BOE
range
(BOE /mo)
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
Number
of
wells
520
295
38
74
49
144
97
69
53
40
112
132
143
147
21
10
16
29
16
10
17
38
34
44
36
129
22
81
27
28
16
7
7
Number
of
fields
24
14
7
37
20
39
39
27
26
21
18
20
17
6
15
10
9
15
11
9
11
18
15
12
5
16
13
23
14
4
7
1^
4
Gas rate
per well
(Mcfd)
35,959.97
28,730.93
18,777.40
29.10
183.33
796.57
1,487.23
1,363.60
1,669.13
1,499.47
9,722.03
24,153.97
71,093.53
195,646.73
8.97
21.43
88.87
317.80
111.03
367.57
398.53
968.70
2,484.67
3,552.93
7,009.67
27.93
42.17
53.87
68.73
17.73
103.70
0.07
22.87
Oil rate
per well
(Bd)
16,932.00
18,800.80
6,337.57
47.93
82.57
476.60
529.43
548.13
557.60
469.27
1,802.73
3,472.83
8,207.40
46,313.93
5.90
16.10
58.83
160.43
124.33
84.97
261.17
786.50
1,253.27
4,144.37
17,150.97
84.53
49.13
356.40
190.63
333.57
206.53
114.30
14C.73
(continued)
A-8
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
COOIL 9
COOIL 10
COOIL 11
COOIL 12
COOIL 13
COOIL 14
COOIL 15
COOIL 16
COOIL 17
COOIL 18
COOIL 19
COOIL 20
COOIL 21
COOIL 22
COOIL 23
COOIL 24
COOIL 25
COOIL 26
COOIL 27
COOIL 28
COOIL 29
COOIL 30
COOIL 31
COOIL 32
Florida
FLOIL 1
FLOIL 2
FLOIL 3
FLOIL 4
FLOIL 5
FLOIL 6
FLOIL 7
FLOIL 8
FLOIL B
Depth
range
(Mft)
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
0-2
0-2
0-2
0-2
10+
10+
10+
10 +
10+
BOE
range
(BOE /mo)
1.001-2,000
2,001-5,000
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
61- 100
101- 200
201- 300
301- 400
501- GOO
Number
of
wells
4
3
429
840
857
230
148
88
56
121
129
127
39
270
407
975
418
146
101
44
98
76
430
10
1
1
1
1
1
1
3
4
2
Number
of
fields
3
3
73
88
162
92
67
47
35
52
30
17
6
93
89
129
85
51
39
25
45
23
13
5
1
2
1
1
1
1
1
4
3
Gas rate
per well
(Mcfd)
36.73
262.47
1,499.50
6,572.43
9,468.53
2,074 .53
2,344.77
391.80
756.70
3,415.87
1,656.30
5,416.67
8,031.40
919.70
3,349.77
18,818.13
14,182.10
6,468.87
5,963.23
2,357.63
6,765.77
7,984.73
16,352.83
1,247.17
3.07
65.40
9.80
834.57
32.17
42.17
22.20
65.47
34.43
Oil rate
per well
(Bd)
184.17
203.23
371.27
1,406.80
2,660.30
1,502.47
1,347.50
1,141.10
831.57
2,443.47
2,591.00
10,206.50
6,169.97
170.40
649.10
2,432.77
1,634.30
852.53
761.77
388.53
1,559.50
2,289.20
33,830.30
2,107.37
25.43
58.17
103.03
704.90
3.33
6.67
22.20
16.67
32.80
(continued)
A-9
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
FLOIL 10
FLOIL 11
FLOIL 12
FLOIL 13
Illinois
ILOIL 1
ILOIL 2
ILOIL 3
ILOIL 4
ILOIL 5
ILOIL 6
ILOIL 7
ILOIL 8
ILOIL 9
ILOIL 10
ILOIL 11
Indiana
INOIL 1
INOIL 2
INOIL 3
INOIL 4
INOIL 5
INOIL 6
INOIL 7
INOIL 8
INOIL 9
INOIL 10
INOIL 11
Kansas
KSOIL 1
KSOIL 2
KSOIL 3
KSOIL 4
KSOIL 5
Depth
range
(Mft)
10+
10 +
10+
10 +
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
BOE
range
(BOE/mo)
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
303- 400
Number
of
wells
7
19
39
44
5424
5421
14865
3006
1146
630
426
708
462
210
51
1205
1894
3062
677
274
155
73
119
66
17
7
11041
2824
2204
833
219
Number
of
fields
4
10
13
8
132
250
433
217
127
88
59
91
57
25
12
70
135
188
88
45
31
16
26
14
6
3
385
385
691
249
103
Gas rate
per well
(Mcfd)
107.20
550.03
1,984.73
20,896.33
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Oil rate
per well
(Bd)
89.23
693.73
3,422.67
15,087.57
937.07
2,275.20
12,122.03
6,760.17
3,960.70
2,966.17
2,504.30
5,807.33
6,916.80
6,499.63
5,835.70
202.17
683.73
2,394.47
1,402.87
851.43
658.17
387.33
901.87
874.80
486.60
350.93
6,667.47
5,559.90
8,269.37
5,269.77
1,873.87
(continued)
A-10
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOTL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOTL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
Kentucky
KYOIL
KYOIL
KYOIL
KYOIL
KYOIL
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
1
2
3
4
5
Depth
range
(Mft)
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
0-2
0-2
0-2
0-2
0-2
BOB
range
(BOB /mo)
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
61-
0-
61-
101-
201-
301-
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
100
60
100
200
300
400
Number
of
wells
125
74
93
69
11
4
7001
6754
8015
2524
955
508
292
556
320
107
21
15
10
137
66
25
15
6
21
16
10
5
4455
8494
5828
1181
502
Number
of
fields
67
40
56
44
10
3
565
989
893
373
206
147
234
153
69
12
10
8
45
30
18
11
5
10
7
6
1
95
243
227
83
38
Gas rate
per well
(Mcfd)
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
00
Oil rate
per well
(Bd)
1,430.
1,025.
1,761.
2,517.
637.
1,053.
7,051.
13,896.
29,623.
15,720.
8,413.
5,930.
4,034.
10,691.
10,400.
7,183.
4,623.
2.
4.
285.
327.
197.
175.
74.
397.
545.
704.
10.
328.
1,605.
3,071.
1,592.
1,047.
70
37
77
87
70
67
93
93
00
63
90
70
57
93
10
67
77
43
97
50
23
07
30
93
93
40
97
87
67
87
80
67
70
(continued)
A-ll
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
KYOIL 6
KYOIL 7
KYOIL 8
KYOIL 9
KYOIL 10
KYOIL 11
Louisiana -North
LANOIL 1
LANOIL 2
LANOIL 3
LANOIL 4
LANOIL 5
LANOIL 6
LANOIL 7
LANOIL 8
LANCIL 9
LANOIL 10
LANOIL 11
LANOIL 12
LANOIL 13
LANOIL 14
LANOIL 15
LANOIL 16
LANOIL 17
LANOIL 18
LANOIL 19
LANOIL 20
LANOIL 21
LANOIL 22
LANOIL 23
LANOIL 24
LANOIL 25
LANOIL 26
LANOIL 27
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
BOE
range
(BOE /mo)
401- 500
501- 600
601-1,000
1.001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
Number
of
wells
185
119
264
231
86
33
9725
531
455
101
40
14
16
27
17
6
3
2117
452
588
341
231
153
116
267
234
81
2
66
41
117
76
60
Number
of
fields
20
17
26
23
7
3
37
23
32
15
14
8
8
12
15
6
4
90
74
111
86
66
60
41
59
54
25
1
40
26
50
44
43
Gas rate
per well
(Mcfd)
0.00
0.00
0.00
0.00
0.00
0.00
516.63
115.93
118.50
13.77
31.33
0.87
23.33
30.10
70.90
64.30
888.80
537.87
656.03
2,103.80
1,784.33
1,837.90
2,503.53
1,327.70
4,715.50
5,698.23
4,699.90
88.30
45.07
87.20
634.50
772.63
580.60
Oil rate
per well
(Bd)
512.77
402.67
1,183.43
1,876.80
1,772.30
1,646.60
5,964.77
1,310.47
1,838.93
646.73
396.87
159.30
215.53
481.80
442.43
265.43
699.23
1,542.00
1,121.57
2,486.03
2,321.10
2,469.70
1,954.60
1,885.20
5,932.00
9,625.67
6,000.83
346.13
38.07
85.70
446.53
521.50
584.83
(continued)
A-12
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
Depth
range
(Mft)
28
29
30
31
32
33
34
35
36
37
38
39
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10 +
10 +
10+
10 +
10 +
BOB
range
(BOB /mo)
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
500
600
,000
,000
,000
Over
60
100
200
300
400
500
Number
of
wells
57
30
55
69
31
19
8
4
15
11
17
13
Number
of
fields
37
21
33
40
14
1
7
5
12
6
11
9
Gas rate
per well
(Mcfd)
1,113
1,476
1,860
4,107
7, 121
55,878
15
24
57
341
230
505
.20
.00
.83
.27
.90
.43
.20
.37
.97
.80
.17
.57
Oil rate
per well
(Bd)
656
376
1,192
2,346
2,093
514
3
7
51
58
143
132
.93
.60
.63
.67
.67
.30
.87
.33
.20
.20
.23
.07
Louisiana-South
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,003-5
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
169
90
110
44
36
37
25
42
68
21
12
187
121
223
164
149
107
94
220
191
115
20
20
27
18
14
14
11
17
23
13
11
36
35
50
47
50
42
38
67
60
41
23
1
61
ICO
129
114
130
433
1,268
970
1,562
10
74
206
412
750
714
715
2,529
3,652
3,577
.47
.47
.70
.60
.80
.00
.93
.73
.17
.87
.90
.47
.13
.97
.33
.87
.43
.17
.87
.63
.70
223
197
416
270
303
393
322
729
2,184
1,504
1,753
147
240
850
1,029
1,294
1,339
1,466
4,642
7,010
8,723
.20
.10
.33
.30
.57
.67
.70
.10
.70
.47
.50
.77
.20
.83
.73
.03
.40
.40
.33
.57
.50
(continued)
A-13
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
LASOIL 22
LASOIL 23
LASOIL 24
LASOIL 25
LASOIL 26
LASOIL 27
LASOIL 28
LASOIL 29
LASOIL 30
LASOIL 31
LASOIL 32
LASOIL 33
LASOIL 34
LASOIL 35
LASOIL 36
LASOIL 37
LASOIL 38
LASOIL 39
LASOIL 40
LASOIL 41
LASOIL 42
LASOIL 43
LASOIL 44
Michigan
MIOIL 1
MIOIL 2
MIOIL 3
MIOIL 4
MIOIL 5
MIOIL 6
MIOTL 7
MIOIL 8
MIOIL 9
MIOIL 10
Depth
range
(Mft)
2-6
.6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10 +
10 +
10 +
10+
10 +
10 +
10 +
10 +
10 +
10+
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
BOE
range
(BOE/mo)
5.001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1.000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
1C1- 200
201- 30C
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
101- 200
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
0- 60
61- 100
Number
of
wells
26
100
60
158
186
179
176
177
526
574
376
122
52
21
98
84
85
66
72
198
294
284
137
5
5
6
3
3
17
6
3
1763
302
Number
of
fields
16
57
42
96
106
93
92
96
157
154
123
55
37
18
60
51
57
47
48
94
121
132
58
1
1
2
1
1
7
2
2
21
22
Gas rate
per well
(Mcfd)
1,775.90
49.03
76.13
562.07
1,023.73
1,738.53
2,176.73
2,670.77
12,262.53
25,215.57
35,752.47
26,934.57
22.57
65.30
503.93
892 90
1,173.73
1,135.70
1,707.90
5,890.77
18,507.50
44,269.97
63,689.80
33.33
51.30
50.00
51.20
129.37
462.50
603.33
200.00
9,849.33
4,107.30
Oil rate
per well
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
Missouri
MOOIL
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
1
Depth
range
(Mft)
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10+
0-2
BOB
range
(BOB /mo)
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5.001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
2,001-5
5,001-
0-
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
6CO
,000
,000
,000
Over
,000
Over
60
Number
of
wells
411
400
203
84
122
238
377
418
99
31
31
99
99
81
41
26
128
305
229
41
3
6
807
Number
of
fields
35
33
32
20
19
38
38
34
19
4
6
15
12
18
12
10
24
24
21
13
2
2
0
Gas rate
per well
(Mcfd)
8,838.
8,329.
2,121.
1,004.
2,047.
7,649.
26,107.
47,635.
8,042.
115.
217.
1,838.
2,286.
1,229.
953.
524.
5,591.
23,546.
34,071.
8,594.
666.
871.
11.
43
53
93
13
67
03
70
77
33
80
70
03
97
37
27
90
67
63
67
57
67
00
10
Oil rate
per well
(Bd)
2,433
5,354
747
385
632
1,712
4,454
13,091
8,148
13
83
563
1,339
235
141
138
745
3,598
6,265
2,886
173
356
377
.10
.17
.43
.77
.13
.43
.93
.47
.80
.83
.37
.63
.97
.00
.57
.07
.27
.10
.53
.23
.77
.00
.77
Mississippi
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
1
2
3
4
5
6
7
8
9
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
60
100
200
300
400
•500
600
,000
,000
18
14
18
46
18
37
27
50
73
8
9
10
18
11
13
12
18
22
0.
24.
2.
18.
4.
145.
57.
505.
1,933.
67
80
47
30
73
27
40
67
57
2
8
47
237
121
279
237
705
1,847
.37
.87
.00
.37
.07
.60
.07
.60
.80
sontinued)
A-15
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellqroup
MSOIL 10
MSOIL 11
MSOIL 12
MSOIL 13
MSOIL 14
MSOIL 15
MSOIL 16
MSOIL 17
MSOIL 18
MSOIL 19
MSOIL 20
MSOIL 21
MSOIL 22
MSOIL 23
MSOIL 24
MSOIL 25
MSOIL 26
MSOIL 27
MSOIL 28
MSOIL 29
MSOIL 30
MSOIL 31
MSOIL 32
MSOIL 33
MSOIL 34
MSOIL 35
MSOIL 36
MSOIL 37
MSOIL 38
MSOIL 39
MSOIL 40
MSOIL 41
MSOIL 42
MSOIL 43
Depth
range
(Mft)
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10+
10 +
10 +
10 +
10 +
10 +
10+
10+
10+
10 +
BOE
range
(BOE/mo)
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5.001- Over
Number
of
wells
38
5
66
55
146
142
111
98
62
157
131
50
47
35
128
117
120
93
72
250
181
133
6
58
18
43
49
67
76
61
175
198
194
105
Number
of
fields
12
3
19
22
47
40
32
24
22
44
34
9
30
18
58
53
46
31
28
53
42
25
3
27
13
24
26
34
42
33
65
60
56
34
Gas rate
per well
(Mcfd)
1,888.70
0.00
9.67
32.37
77.83
118.77
185.40
333.20
36.03
947 .90
873.07
731.87
1.70
18.80
40.33
107.23
222.80
323.60
306.10
1,555.03
1,844.03
3,086.10
232.97
5.87
12.13
46.93
73.70
146.30
377.77
139.87
1,139.97
2,805.10
11,177.97
12,424.30
Oil rate
per well
(Bd)
2,209.67
549.00
19.13
57.27
359.63
663 .40
792. 13
845.27
701.63
2,389.70
3,681.27
3,069.73
11.60
32.17
308.53
531.87
780.57
811.40
780.20
3,823.10
4,905.97
7,858.73
523.00
15.23
16.53
100.63
187.67
373.13
608.43
651.90
2,591.03
5,534.23
11,524.77
14,861.27
(continued)
A-16
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
we 11 group
Montana
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
Depth
range
(Mft)
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10+
BOE
range
(BOB /mo)
0-
61-
101-
201-
301-
501-
601-1
1,001-2
2,001-5
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
60
100
200
300
400
600
,000
,000
,000
60
100
200
.300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,OOC
,000
,000
Over
60
100
Number
of
wells
1070
227
142
28
8
1
5
2
1
550
281
264
174
87
72
39
89
58
25
1
19
19
70
85
104
71
70
209
222
88
7
9
3
Number
of
fields
17
14
16
9
5
1
4
3
1
53
36
61
46
28
26
20
29
21
12
1
15
16
35
44
41
39
40
54
38
23
6
10
3
Gas rate
per well
(Mcfd)
89
72
235
87
116
0
82
207
76
41
34
355
404
155
292
74
531
395
616
68
1
11
86
212
534
294
426
2,031
3,230
2,631
293
1
6
.67
.40
.43
.10
.83
.00
.73
.57
.73
.13
.93
.47
.77
.80
.87
.37
.53
.07
.93
.77
.60
.27
.47
.27
.00
.97
.33
.60
.10
.17
.17
.13
.87
Oil rate
per well
(Bd)
740
462
496
131
78
17
105
56
108
488
639
1,496
1,262
922
1,015
686
2,236
2,538
2,341
164
6
32
260
609
1.106
1,003
1,203
5,159
9,870
7,623
1,284
4
4
.17
.83
.00
.97
.70
.93
.17
.33
.00
.37
.40
.57
.20
.97
.67
.73
.70
.87
.37
.90
.23
.67
.13
.87
.80
.30
.27
.87
.70
.70
.30
.63
.37
(continued)
A-17
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
MTOIL 34
MTOIL 35
MTOIL 36
MTOIL 37
MTOIL 38
MTOIL 39
MTOIL 40
MTOIL 41
MTOIL 42
North Dakota
NDOIL 1
NDOIL 2
NDOIL 3
NDOIL 4
NDOIL 5
NDOIL 6
NDOIL 7
NDOIL 8
NDOIL 9
NDOIL 10
NDOIL 11
• NDOIL 12
NDOIL 13
NDOIL 14
NDOIL 15
NDOIL 16
NDOIL 17
NDOIL 18
NDOIL 19
NDOIL 20
NDOIL 21
NDOIL 22
NDOIL 23
NDOIL 24
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-1C
6-10
6-10
BOB
range
(BOB /mo)
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
Number
of
wells
12
14
18
30
24
76
106
50
14
2
4
9
2
2
2
3
5
6
6
84
103
289
207
95
54
53
72
46
19
6
73
51
133
Number
of
fields
12
15
18
27
22
46
66
32
10
2
4
5
1
2
2
2
6
6
6
46
43
65
55
32
24
23
24
15
3
5
37
25
51
Gas rate
per well
(Mcfd)
21.73
40.23
98.13
293.27
331.50
1,745.60
3,837.77
3,428.10
3,231.80
0.00
2.10
117.07
3.60
38.57
22.97
11.43
20.30
196.10
640.97
44.27
74.23
436.33
705.17
354.37
113.10
310.57
255.67
109.10
314.10
184.33
39.97
202.33
1,221.03
Oil rate
per well
(Bd)
46.00
95.47
173.70
376.60
399.70
1,815.37
4,466.73
4,451.70
2,217.27
0.37
10.93
62.27
22.93
18.83
16.60
60.67
66.33
520.43
995.60
78.13
241.23
1,299.13
1,566.60
1,056.33
759.73
916.17
1,692.87
1,992.97
1,657.00
1,108.50
23.00
59.63
409.23
(continued)
A-18
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
welloroup
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
Nebraska
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
1
2
3
4
5
6
7
8
9
10
31
12
13
14
Depth
range
(Mft)
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10-r
10 +
10+
10 +
10 +
10 +
10 +
10 +
10 +
10 +
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
BOE
range
(BOE /mo)
201-
301-
401-
501-
601-1
1.0C1-2
300
400
500
600
,000
,000
2,001-5,000
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
501-
601-1
2,001-5
0-
61-
101-
201-
301-
401-
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
600
,000
,000
60
100
200
300
400
500
Number
of
wells
194
177
136
115
322
321
163
46
30
12
34
33
38
42
36
115
193
156
69
25
49
84
13
10
3
57
1
104
180
380
286
121
25
Number
of
fields
73
75
70
65
98
81
50
18
24
13
28
26
32
36
32
67
83
58
29
12
14
28
7
4
4
1
2
67
77
135
74
36
16
Gas rate
per well
(Mcfd)
2,323
2,444
2,133
2,069
8,519
14,738
15,897
20,293
30
27
163
234
518
695
923
4,398
13,360
21,523
46,475
0
6
165
13
0
0
0
39
24
76
381
193
361
84
.43
.53
.83
.53
.37
.37
.07
.10
.53
.70
.93
.57
.90
.93
.30
.97
.37
.03
.90
.50
.30
.90
.93
.00
.00
.00
.67
.77
.43
.53
.17
.10
.60
Oil rate
per well
(Bd)
1,253
1,643
1,743
1,839
7,351
13,123
14,098
9,926
7
17
113
193
349
500
499
2,523
7.596
12,330
11,876
32
134
364
104
116
39
1,843
145
131
486
1.903
2,310
1,281
357
.23
.23
.80
.37
.93
.53
.87
.43
.00
.20
.83
.37
.50
.90
.33
.60
.97
.33
.00
.13
.93
.97
.47
.57
.63
.13
.13
.30
.47
.60
.43
.07
.93
(continued)
A-19
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
NEOIL 15
NEOIL 16
NEOIL 17
NEOIL 18
NEOIL 19
NEOIL 20
NEOIL 21
NEOIL 22
NEOIL 23
NEOIL 24
NEOIL 25
NEOIL 26
NEOIL 27
NEOIL 28
NEOIL 29
New Mexico
NMOIL 1
NMOIL 2
NMOIL 3
NMOIL 4
NMOIL 5
NMOIL 6
NMOIL 7
NMOIL 8
NMOIL 9
NMOIL 10
NMOIL 11
NMOIL 12
NMOIL 13
NMOIL 14
NMOIL 15
NMOIL 16
NMOIL 17
NMOIL 18
Depth
range
(Mft)
2-6
2-6
2-6
2-6
6-10
6-10
S-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
BOE
range
(BOE/mo)
501- 600
601-1.000
1,001-2,000
2,001-5,000
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
SOl-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
Number
of
wells
54
23
77
5
35
45
97
38
15
9
9
10
7
8
1
881
240
276
102
52
35
14
24
13
11
2
2424
1550
2409
1256
729
456
302
Number
of
fields
12
16
12
4
26
29
67
31
14
9
9
11
7
4
1
93
52
52
34
24
24
13
22
13
12
2
186
173
179
145
117
101
68
Gas rate
per well
(Mcfd)
68.87
48.60
65.23
0.00
10.77
23.10
45.17
88.50
60.00
6.87
5.27
49.77
51.20
189.77
72.80
778.37
605.93
1,065.80
305.63
274.10
739.93
565.67
965.97
702.10
693.97
1,138.83
4,115.77
8,030.80
27,423.43
26,772.07
22,602.07
18,856.53
15,637.30
Oil rate
per well
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
Nevada
NVOIL
NVOIL
NVOIL
NVOIL
NVOIL
NVOIL
NVOIL
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
1
2
3
4
5
6
7
Depth
range
(Mft)
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-1C
10+
10 +
10 +
10 +
10 +
10 +
10+
1C +
10+
10+
10 +
2-6
2-6
2-6
2-6
2-6
2-5
2-6
BOB
range
(BOB /mo)
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
101-
201-
301-
401-
501-
601-1
1,001-2
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
200
300
400
500
600
,000
,000
Number
of
wells
655
417
213
51
479
321
845
631
487
342
222
510
382
231
73
76
46
109
117
89
53
59
138
118
60
30
2
4
6
3
1
6
5
Number
of
fields
98
67
34
3
113
87
120
111
98
88
72
95
83
59
17
49
31
61
51
49
30
41
64
50
33
11
3
3
4
1
1
3
4
Gas rate
per well
(Mcfd)
42,
39,
20,
5.
1.
3.
14,
21,
21,
18,
13,
47,
46,
38,
20,
1,
2,
2,
1,
1,
6,
6,
8,
8,
880
434
413
310
945
058
319
075
493
712
888
243
788
694
120
151
264
048
157
121
079
895
001
715
737
444
0
0
0
0
0
0
0
.60
.20
.93
.07
.70
.47
.67
.57
.30
.67
.27
.90
.27
.57
.20
.23
.43
.77
.83
.67
.30
.20
.57
.53
.60
.53
.00
.00
.00
.00
.00
.00
.00
Oil rate
per well
(Bd)
11
14
17
11
2
2
3
2
2
7
12
16
13
2
4
4
6
,097.90
,102.07
,644.83
,350.73
221.73
479.63
,556.23
,863.57
,276.43
,998.77
,526.53
,780.37
,054.23
,448.33
,884.27
39.47
79.50
364.03
666.10
756.00
626.93
798.20
,738.20
,376.93
,465.53
,760.47
4.57
33.87
60.63
26.07
19.43
155.27
235.40
(continued)
A-21
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
we 11 group
NVOIL 8
NVOIL 9
New York
NYOIL 1
NYOIL 2
NYOIL 3
NYOIL 4
NYOIL 5
Ohio
OHOIL 1
OHOIL 2
OHOIL 3
OHOIL 4
OHOIL 5
OHOIL 6
Oklahoma
OKOIL 1
OKOIL 2
OKOIL 3
OKOIL 4
OKOIL 5
OKOIL 6
OKOIL 7
OKOIL 8
OKOIL 9
OKOIL 10
OKOIL 11
OKOIL 12
OKOIL 13
OKOIL 14
OKOIL 15
OKOIL 16
OKOIL 17
OKOIL 18
Depth
range
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgrouo
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKO.TL
OKOIL
OKOIL
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 '
41
42
43
Depth
range
(Mft)
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-1C
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10<
10 +
10 +
10 +
10 +
10 +
10+
10+
. 10+
10 +
BOE
range
(BOE/mo)
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
Number
of
wells
411
151
34
1744
1978
5442
3076
1756
1045
704
1330
934
294
50
47
87
355
247
196
145
113
232
271
79
44
Number
of
fields
110
45
13
147
153
352
267
181
138
109
149
91
57
16
25
31
90
75
54
39
34
56
44
24
12
Gas rate
per well
(Mcfd)
13
19
4
7
18
84
83
61
45
39
90
84
58
21
3
4
5
5
6
18
21
19
35
,864
,590
,423
,406
,072
,083
,240
,732
,540
,961
,218
,621
,906
,552
215
616
,088
,626
,262
,375
,301
,881
,834
,129
,422
.33
.67
.87
.00
.63
.67
.47
.17
.30
.50
.90
.93
.73
.97
.63
.90
.33
.53
.33
.67
.57
.97
.70
.67
.70
Oil rate
per well
(Bd)
10,290
7,389
3,720
551
1,541
8,815
7,986
6,832
5,628
4,238
12,456
17,596
9,896
5,527
9
62
524
759
932
823
697
2,791
5,614
2,313
4,368
.30
.10
.73
.53
.33
.57
.80
.63
.17
.90
.63
.13
.50
.10
.87
.17
.63
.97
.07
.00
.07
.87
.13
.10
.17
Pennsylvania
PAOIL
PAOIL
PAOIL
PAOIL
1
2
3
4
0-2
0-2
0-2
0-2
0-
61-
101-
501-
60
100
200
600
26702
337
139
40
N/A
N/A
N/A
N/A
0
0
0
0
.00
.00
.00
.00
5,066
897
813
727
.90
.87
.37
.43
South Dakota
SDOIL
SDOIL
SDOIL
1
2
3
0-2
0-2
0-2
101-
201-
1,001-2
200
300
,000
2
2
2
1
1
•j
0
0
C
.00
.00
.00
8
14
44
.73
.90
.50
(continued)
A-23
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
SDOIL 4
SDOIL 5
SDOIL 6
SDOIL 7
SDOIL 8
SDOIL 9
SDOIL 10
SDOIL 11
SDOIL 12
SDOIL 13
SDOIL 14
SDOIL 15
SDOIL 16
SDOIL 17
SDOIL 18
SDOIL 19
SDOIL 20
SDOIL 21
SDOIL 22
Tennessee
TNOIL 1
TNOIL 2
TNOIL 3
TNOIL 4
TNOIL 5
TNOIL 6
TNOIL 7
TNOIL 8
Texas -Gulf
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
Depth
range
(Mft)
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
Coast
1 0-2
2 0-2
3 0-2
4 0-2
5 0-2
BOB
range
(BOB /mo)
2,001-5,
101-
201-
401-
501-
601-1,
1,001-2,
2,001-5,
000
200
300
500
600
000
000
000
5,001- Over
0-
61-
101-
201-
301-
401-
501-
601-1,
1,001-2,
2,001-5,
0-
61-
101-
201-
301-
501-
60
100
200
300
400
500
600
000
000
000
60
100
200
300
400
600
1,001-2,000
2,001-5,
0-
61-
101-
201-
301-
000
60
100
200
300
400
Number
of
wells
1
3
2
2
6
3
1
4
1
1
1
2
16
14
4
12
37
42
3
489
57
22
18
D3
9
4
1
14856
839
1328
474
165
Number
of
fields
1
4
3
3
6
4
1
3
1
1
1
3
7
8
3
4
8
5
1
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
227
101
63
53
27
Gas rate
per well
(Mcfd)
0.00
16.27
3.40
22.20
24.80
20.70
17.83
871.77
226.63
0.27
0.00
0.50
10.03
20.43
0.00
12.67
50.43
1.60
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
810.87
657.50
2,008.73
789.90
644.27
Oil rate
per well
(Bd)
116.57
14.30
16.03
28.93
104.87
89.80
35.10
322.33
175.07
0.23
2.50
7.87
124.50
158.63
59.30
217.23
989.17
1,893.77
167.00
431.90
178.37
107.13
135.87
144.30
176.77
160.13
143.23
6,062.03
2,147.73
6,604.17
3,690.67
1,910.50
(continued)
A-24
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
Depth
range
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellqroup (Mft)
TXGCOIL 40
TXGCOIL 41
TXGCOIL 42
TXGCOIL 43
Texas -North
TXNOIL 1
TXNOIL 2
TXNOIL 3
TXNOIL 4
TXNOIL 5
TXNOIL 6
TXNOIL 7
TXNOIL 8
TXNOIL 9
TXNOIL 10
TXNOIL 11
TXNOIL 12
TXNOIL 13
TXNOIL 14
TXNOIL 15
TXNOIL 16
TXNOIL 17
TXNOIL 18
TXNOIL 19
TXNOIL 20
TXNOIL 21
TXNOIL 22
TXNOIL 23
TXNOIL 24
TXNOIL 25
TXNOIL 26
TXNOIL 27
TXNOIL 28
TXNOIL 29
10 +
10 +
10 +
10 +
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
BOE
range
(BOE /mo)
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
Number
of
wells
115
99
44
5
24154
2170
1406
474
93
39
15
10
2
11809
5331
5523
2233
901
593
436
1057
313
125
6
661
520
955
583
280
250
152
248
168
Number
of
fields
34
35
18
5
324
129
119
57
31
15
8
7
3
913
559
313
207
149
266
147
24
5
211
195
265
187
114
78
56
87
60
Gas rate
per well
(Mcfd)
11,308.83
17,638.00
14,699.93
4,752.83
8,155.87
3,361.73
3,867.60
3,124.40
125.13
330.57
134.07
117.27
3.87
29,635.17
35,910.47
71,697.70
41,825.13
28,284.77
17,502.63
15,842.00
19,382.53
15,852.10
10,560.43
856.03
1,349.63
3,892.13
16,088.27
14,460.37
9,370.90
8,494.97
7,490.80
16,191.23
8,557.73
Oil rate
per well
(Bd)
1,889.13
2,495.93
2,330.40
333.73
14,697.57
5,213 .67
6,088.77
3,125.57
996.13
516.03
252.17
233.10
72.27
9,019.07
10,659.43
19,463.37
14,511.50
7,728.80
7,173.20
6,238.23
24,238.00
11,729.73
9,402.20
1,463-87
527.43
981.37
2,969.90
3,401.93
2,259.77
2,868.47
2,010.53
4,645.23
6,135.67
(continued)
A-26
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
30
31
32
33
34
35
36
37
38
39
40
41
42
Depth
range
(Mft)
6-10
6-10
10 +
10+
10+
10+
10+
10+
10+
10+
10+
10 +
10 +
BOE
range
(BOE /mo)
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
,000
Over
60
100
200
300
400
500
600
,000
,000
.000
Over
Number
of
wells
72
12
10
8
23
13
11
10
4
26
9
11
5
Number
of
fields
34
9
8
8
14
11
11
5
4
9
8
6
3
Gas rate
per well
(Mcfd)
8,
2,
3,
2,
5,
3,
883
064
13
60
468
439
604
903
530
824
029
321
799
.70
.57
.27
.07
.20
.27
.30
.00
.90
.97
.30
.30
.30
Oil rate
per well
(Bd)
6,
2,
281.37
584.10
4.53
15.40
55.37
63.30
64.73
60.23
22.07
261.87
142.53
308.77
436.40
Texas -West
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
1
2
3
4
5
6
1
8
9
10
11
12
13
14
15
16
17
18
19
20
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
0-
61-
101-
201-
301-
401--
501-
601-1
1,001-2
2,001-5
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
60
100
200
300
400
500
600
,000
,000
,000
60
100
200
300
400
500
600
,000
,000
,000
3101
760
862
172
114
48
16
40
5
1270
9224
5740
9670
5497
4518
4577
2114
4219
3829
676
158
71
57
28
8
7
5
8
2
0
709
462
575
363
251
180
130
180
120
39
1,
155,
24,
32,
73,
43,
34,
33,
35,
58,
304,
125,
419
343
131
121
30
23
177
159
83
889
699
416
291
473
413
966
221
625
490
2fiO
.17
.87
.33
.50
.10
.57
.63
.97
.43
.60
.93
.13
.37
.13
.57
.47
.13
.27
.43
.03
2,
1,
3,
1,
1,
75,
8,
14,
44,
41,
49,
62,
35,
104,
163,
64.
687.60
820.10
461.20
354.40
270.93
632.70
277.27
869.87
198.63
763.03
859.80
223.07
562.07
345.07
462.13
441.07
724.10
599.53
734.80
493.47
(continued)
A-27
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
TXWOIL 21
TXWOIL 22
TXWOIL 23
TXWOIL 24
TXWOIL 25
TXWOIL 26
TXWOIL 27
TXWOIL 28
TXWOIL 29
TXWOIL 30
TXWOIL 31
TXWOIL 32
TXWOIL 33
TXWOIL 34
TXWOIL 35
TXWOIL 36
TXWOIL 37
TXWOIL 38
TXWOIL 39
TXWOIL 40
TXWOIL 41
TXWOIL 42
TXWOIL 43
Utah
UTOIL 1
UTOIL 2
UTOIL 3
UTOIL 4
UTOIL 5
UTOIL 6
UTOIL 7
UTOIL 8
UTOIL 9
UTOIL 10
Depth
range
(Mft)
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10 +
10 +
10+
10 +
10 +
10 +
10 +
10 +
10 +
10 +
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
BOB
range
(BOE/roo)
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1.000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
Number
of
wells
37
2295
2327
5183
2971
1704
1281
1150
3356
2540
254
240
222
147
324
320
180
156
131
362
342
144
32
76
6
8
3
2
1
1
4
3
2
Number
of
fields
10
391
262
413
325
237
176
153
239
173
80
19
121
53
120
111
81
71
64
112
104
68
14
6
1
4
3
1
2
1
5
3
•3
Gas rate
per well
(Mcfd)
950.93
44,810.03
69,747.03
144,652.73
73,143.27
55,556.17
44,735.23
33,130.67
103,708.00
457,137.57
23,383.30
33,489.57
5,372.10
7,753.40
20,292.60
18,342.00
13,626.33
10,720.30
4,706.33
20,884.23
52,246.17
8,611.00
760.50
8.57
4.47
7.93
21.63
0.00
3C.63
51.53
152.93
31.83
856.60
Oil rate
per well
(Bd)
7,396.70
2,599.13
5,760.10
23,487.93
22,330.23
18,207.17
17,521.67
19,941.33
86,184.10
106,421.63
20,483.23
39,435.57
169.10
346.50
1,449.77
2,464.13
1,996.57
2,099.13
2,127.53
8,595.03
14,177.37
12,583.97
7,439.07
33.53
13.80
25.27
25.90
23.73
12.67
13.33
83. CO
139.90
122.70
(continued)
A-28
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
UTOIL 11
UTOIL 12
UTOIL 13
UTOIL 14
UTOIL 15
UTOIL 16
UTOIL 17
UTOIL 18
UTOIL 19
UTOIL 20
UTOIL 21
UTOIL 22
UTOIL 23
UTOIL 24
UTOIL 25
UTOIL 26
UTOIL 27
UTOIL 28
UTOIL 29
UTOIL 30
UTOIL 31
UTOIL 32
UTOIL 33
UTOIL 34
UTOIL 35
UTOIL 36
UTOIL 37
UTOIL 38
UTOIL 39
UTOIL 40
UTOIL 41
UTOIL 42
UTOTL 43
Depth
range
(Mft)
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10+
10+
10+
10+
10+
10 +
10 +
10 +
10+
10 +
10 +
BOB
range
(BOE/mo)
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5.000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
Number
of
wells
45
49
130
140
127
88
94
228
213
76
15
7
5
20
33
21
20
13
45
38
22
16
31
14
21
25
17
22
18
73
153
95
17
Number
of
fields
23
22
27
34
26
22
20
31
22
12
8
7
6
13
19
12
11
10
17
18
12
7
4
3
4
6
6
5
5
6
7
6
6
Gas rate
per well
(Mcfd)
38.93
200.50
860. 10
1,836.57
1,956.00
1,629.30
2,320.70
6,241.50
7,149.07
4,250.83
3,792.40
0.83
19.47
130.77
594.30
466.60
477.30
387.30
1,936.40
3,565.70
4,507.50
50,086.47
24.50
29.23
112.43
176.07
183.67
384.73
284.90
2,551.87
12,665.57
16,031.90
18,867.27
Oil rate
per well
(Bd)
18.90
88.87
483.90
884.27
1,217.83
1,086.27
1,369.40
5,098.07
8,791.70
6,305.30
2,614.57
3.47
7.30
80.20
199.27
151.20
211.10
193.13
934.83
1,251.67
1,680.30
2,283.70
11.40
21.93
63.33
155.47
146.27
226.67
254.27
1,522.87
5,726.77
6,857.97
3,842.27
(continued)
A-29
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
we 11 group
Virginia
VAOIL 1
West Virginia
WVOIL 1
WVOIL 2
WVOIL 3
WVOIL 4
WVOIL 5
Wyoming
WYOIL 1
WYOIL 2
WYOIL 3
WYOIL 4
WYOIL 5
WYOIL 6
WYOIL 7
WYOIL 8
WYOIL 9
WYOIL 10
WYOIL 11
WYOIL 12
WYOIL 13
WYOIL 14
WYOIL 15
WYOIL 16
WYOIL 17
WYOIL 18
WYOIL 19
WYOIL 20
WYOIL 21
WYOIL 22
WYOIL 23
WYOIL 24
WYOIL 25
Depth
range
(Mft)
0-2
0-3
0-3
0-3
0-3
0-3
0-2
0-2
0-2
C-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
2-6
6-10
6-10
6-10
BOE
range
(BOE /mo)
0- 60
0- 60
61- 100
101- 200
201- 300
601-1,000
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
201- 300
301- 400
401- 500
501- 600
601-1,000
1,001-2,000
2,001-5,000
5,001- Over
0- 60
61- 100
101- 200
Number
of
wells
50
15356
284
197
81
24
1340
393
556
326
230
140
90
185
92
27
5
475
466
905
537
350
266
230
591
621
330
46
192
201
622
Number
of
fields
N/A
N/A
N/A
N/A
N/A
N/A
79
46
62
45
38
34
27
33
31
20
5
94
92
126
121
86
75
79
81
71
37
15
93
90
158
Gas rate
per well
(Mcfd)
0.00
0.00
0.00
0.00
0.00
0.00
22.63
53.20
559.63
414.17
376.90
290.60
651.97
1,302.50
2,266.40
2,092.27
4,559.67
183.53
546.40
2,781.33
2,149.97
1,518.33
1,132.67
1,623.37
4,498.17
7,025.33
9,170.40
4,628.70
296.03
822.40
6,137.53
Oil rate
per well
(Bel)
58.33
3,597.67
608.47
745.33
675.20
603.87
973.87
951.70
2,515.70
2,501.33
2,512.87
1,993.60
1,488.63
4,203.27
3,379.23
2,075.90
1,201.67
385.07
1,025.17
3,772.33
3,880.47
3,697.97
3,576.10
3,746.03
14,127.73
26,723.37
29,795.47
9,108.30
120.90
398.10
2,263.97
(continued)
A-30
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Depth
range
(Mft)
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10+
10+
10+
10+
BOE
range
(BOE /mo)
201-
301-
401-
501-
601-1
1.001-2
2,001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
Number
of
wells
587
457
247
175
416
348
300
174
20
27
55
73
59
38
44
117
121
95
103
Number
of
fields
158
133
118
93
166
147
125
54
19
22
35
32
36
20
32
53
58
49
26
Gas rate
per well
(Mcfd)
9,
9,
6,
4,
10,
10,
23,
146,
1,
1,
5,
13,
21,
223,
181
092
283
791
529
470
030
148
25
136
532
997
009
462
500
375
329
076
460
.17
.83
.80
.50
.70
.40
.37
.00
.57
.23
.17
.00
.13
.60
.23
.20
.90
.03
.00
Oil rate
per well
(Bd)
3
4
2
2
9
14
27
38
2
4
6
34
,611.30
,035.30
,891.83
,550.97
,063.23
,483.13
,171.90
,210.57
11.00
35.03
179.33
475.10
536. SO
486.70
611.80
,355.20
,241.20
..666.07
,896.93
A-31
-------
APPENDIX B
GRUY ENGINEERING CORPORATION'S
GAS WELLGROUPS BY STATE
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APPENDIX C
DERIVATION AND INTERPRETATION OF
SUPPLY FUNCTION PARAMETER
-------
APPENDIX C
DERIVATION AND INTERPRETATION OF SUPPLY
FUNCTION PARAMETER 3
The generalized Leontief functional form that is used to
project supply relations for each producing field is set out
in Equation (4-1), repeated below for clarity:
11/2
3
2
1 (4-1)
r '
A closer look at the supply specification in Eq. (4-1)
requires an interpretation of the 3 parameter. Although this
parameter does not have an intuitively appealing
interpretation, it is related to the producing field's supply
elasticity for natural gas--a well-known model parameter. An
individual field's supply elasticity for natural gas, £.,, can
be expressed as :
8q /q 3q / dr
*j = i— ; — = - : — (c
dr/r q.j/r
or
q.
(C-lb)
where dq^/dr is the derivative of quantity supplied by the
field with respect to wellhead price (r) .
To establish the relationship between ^ and 3 we start
by taking the derivative of the facility supply function
C-l
-------
(Equation [4.1]) with respect to price, and multiply the
expression by r/q.j resulting in the following expression for
the supply elasticity:
8r
1/2
(C-2)
Since economic theory dictates that the supply elasticity
is positive (i.e., ^ > 0) and q^ and r are positive, Equation
(C-2) above indicates that the parameter (3 is negative, i.e.,
3 < 0. Finally, the solution for p from Equation (C-2)
reveals the following expression:
-1/2
(C-3)
where
£, = market supply elasticity, and
q = production-weighted average annual level of natural
gas production per well.
This approach derives a single p value based on market-level
data.
C-2
-------
APPENDIX D
NATURAL GAS MARKET MODEL SUMMARY
-------
APPENDIX D
NATURAL GAS MARKET MODEL SUMMARY
This appendix provides a complete list of the exogenous
and endogenous variables, as well as the model equations.
D.I EXOGENOUS VARIABLES
n^ Demand elasticity for natural gas by end-user
(i).
£J Import supply elasticity of foreign natural gas.
3,Y- Supply function parameters for natural gas by
U.S. producing field (j).
A1 Import supply function parameter for natural gas
(Multiplicative constant).
B f Demand function parameters for natural gas by
end-user (i) (Multiplicative constants).
c. Regulatory control costs (per Mcf of output) for
producing field (j).
D.2 ENDOGENOUS VARIABLES
r Wellhead price of natural gas ($/Mcf).
PA End-user price of natural gas where i represents
residential, commercial, industrial, and utility
consumers.
<3jS ' q1 ' Qs Domestic (field-level) and foreign supply of
natural gas (qjS • q1) and market supply of natural
gas (Qs) .
D-l
-------
Qi • QD Domestic end-user demand (q^) and market demand
for natural gas (QD) .
D.3 MODEL EQUATIONS
Market Supply of Natural Gas:
where
q1 = A1 [r]
and
or
E q/ = E
1/2
without regulation
r -
1/2
with regulation
Market Demand of Natural Gas:
where
D-2
-------
APPENDIX E
APPROACH TO ESTIMATING
ECONOMIC WELFARE IMPACTS
-------
APPENDIX E
APPROACH TO ESTIMATING ECONOMIC WELFARE IMPACTS
The economic welfare implications of the market price and
output changes of natural gas with the regulations can be
examined using two slightly different tactics, each giving a
somewhat different insight but the same implications:
(1) changes in the net benefits of consumers and producers
based on the price changes, and (2) changes in the total
benefits and costs of natural gas based on the quantity
changes. For this analysis, we focus on the first measure--
the changes in the net benefits of consumers and producers.
Figure E-l depicts the change in economic welfare by first
measuring the change in consumer surplus and then the change
in producer surplus. In essence the demand and supply curves
previously used as predictive devices are now being used as a
valuation tool.
This method of estimating the change in economic welfare
with the regulations decomposes society into consumers and
producers. In a market environment, consumers and producers
of the good or service derive welfare from a market
transaction. The difference between the maximum price
consumers are willing to pay for a good and the price they
actually pay is referred to as consumer surplus. Consumer
surplus is measured as the area under the demand curve and
above the price of the product. Similarly, the difference
between the minimum price producers are willing to accept for
a good and the price they actually receive is referred to as
producer surplus. Producer surplus is measured as the area
above the supply curve to the price of the product. These
areas may be thought of as consumers' net benefits of
E-l
-------
$/Q
Q2 Q, Q/t
(a) Change in Consumer Surplus with Regulation
$/Q
Q2 Qt Q/t
(b) Change in Producer Surplus with Regulation
$/Q
Q2 Q,
Q/t
(c) Net Change in Economic Welfare with Regulation
Figure E-l. Economic welfare changes with regulation:
consumer and producer surplus.
E-2
-------
consumption and producers' net benefits of production
respectively.
In Figure E-l, baseline equilibrium occurs at the
intersection of the natural gas demand curve, D, and supply
curve, S. Price is Px with quantity Qx. The increase cost of
production with the regulations will cause the market supply
curve to shift upward to S'. The new equilibrium price of
paper is P^ With a higher price for natural gas there is
less consumer welfare, all else being unchanged. In
Figure E-l(a), area A represents the dollar value of the
annual net loss in consumers' benefits with the increased
price of natural gas. The rectangular portion represents the
loss in consumer surplus on the quantity still consumed, Q2,
while the triangular area represents the foregone surplus
resulting from the reduced amount of natural gas consumed,
Qi-Q2-
In addition to the changes in consumer welfare, there are
also changes in producers welfare with the regulations. With
the increase in natural gas price producers receive higher
revenues on the quantity still purchased, Q2. In
Figure E-l(b), area B represents the increase in revenues due
to this increase in price. The difference in the area under
the supply curve up to the original market price, area C,
measures the loss in producers' surplus, which includes the
loss associated with the quantity no longer produced. The net
change in producers' welfare is represented by area B-C.
The change in economic welfare attributable to the
compliance costs of the regulations is the sum of consumer and
producer surplus changes, that is, - (A) + (B-C).
Figure E-l(c) shows the net (negative) change in economic
welfare associated with the regulations as area D. However,
this analysis does not include the benefits that occur outside
the natural gas market—the value of the reduced levels of air
E-3
-------
pollution with the regulations. Inclusion of this benefit may
reduce the net cost of the regulations or even make them
positive, that is, total benefits, private market benefits as
estimated above plus the benefits in the quality of the
environment, may exceed total costs.
E-4
-------
APPENDIX F
DATA SUMMARY OF
COMPANIES INCLUDED IN
FIRM-LEVEL ANALYSIS: 1993
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TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
\. REPORT NO.
EPA-453/R-96-016
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
5. REPORT DATE
November 1996
Economic Impact Analysis of the Proposed Oil and Natural Gas
NESHAPs
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Lisa Conner; EPA, OAQPS
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Air Quality Planning and Strategies Division (MD-15)
Research Triangle Park, NC 27711
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
Director
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report presents a technical analysis of the economic impacts associated with the proposed NESHAP
for Oil and Natural Gas Production. The analysis evaluates adjustments in the markets for crude oil and
natural gas (through price and production changes), social cost, and the resulting affects on employment,
international trade, and small businesses.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI PJeM/Group
Economic Impact Analysis (EIA)
Regulatory Flexibility Analysis (RFA)
Air Pollution control
economic analysis
small business analysis
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Page)
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12th Floor
Chicago, IL 60604-3590
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