United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park, NC 27711
FINAL REPORT
EPA-452/R-99-003
May 1999
Air
EPA ECONOMIC IMPACT ANALYSIS
OF THE OIL AND NATURAL GAS
PRODUCTION NESHAP
AND THE
NATURAL GAS TRANSMISSION
AND STORAGE NESHAP
Final Report
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Economic Impact Analysis
of the Oil and Natural Gas
Production NESHAP
and the
Natural Gas Transmission and Storage 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
Final Report
May 1999
U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Bputevard, 12th Floor
Chicago, IL 60604-3590
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Disclaimer
This report is issued by the Air Quality Standards &
Strategies 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 NESHAPs on
the Oil and Natural Gas Production and Natural Gas
Transmission and Storage source categories (April 1997). Both
the Economic Impact Analysis and the BID are in the public
docket for the NESHAP final rulemaking. Copies of these
reports and other material supporting the rule 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
±.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 2-10
2.2.1.1 Reserves 2-10
2.2.1.2 Domestic Production . . 2-10
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
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
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)
Pace
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 Post-Regulatory
Compliance Cost .... 4-31
4.3.2.2 Revenue, Production Cost,
and Profit Impacts . . . 4-32
4.3.2.3 Screening Analysis for
Natural Gas Transmission
and Storage 4-32
4.4 Economic Welfare Impacts 4-38
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-Regulation 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 3 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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VI
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LIST OF FIGURES
Number Pace
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
ES-2
2-1
2-2
2-3
2-4
2-5
2-6
2-7
2-8
2-9
2-10
2-11
2-12
2-13
2-14
2-15
2-16
2-17
2-18
2-19
2-20
2-21
2-22
3-1
3-2
Summary of Annual Control Costs by Model Plant
Summary of Selected Economic Impact Results . .
Total U.S. Proved Reserves of Crude Oil,
1976 Through 1993
U.S. Crude Oil Reserves by State and Area,
1993
U.S. Crude Oil Production, 1982-1992
Total U.S. Crude Oil Consumption and Price
Levels, 1980-1992
Summary of U.S. Foreign Trade of Crude Oil,
1983-1992
Supply, Demand, and Price Projections for
Crude Oil, 1990-2010
U.S. Proved Reserves of Dry Natural
Gas, 1976 Through 1993
U.S. Natural Gas Reserves by State and Area,
1993
U.S. Natural Gas Production and Wellhead
-- ;ce levels, 1980-1992
U.S. Natural Gas Consumption by End-Use
Sector, 1980-1992
U.S. Natural Gas Price by End-Use Sector,
1980-1992
Historical Summary of U.S. Natural Gas
Foreign Trade, 1973-1993
Supply, Demand, and Price Projections for
Natural Gas, 1993-2010
Number of Crude Oil and Natural
Gas Wells, 1983-1992
U.S. Onshore Oil and Gas Well Capacity by
Size Range, 1989
Distribution of U.S. Gas Wells by State, 1993
U.S. Natural Gas Processing
Facilities, 1987-1993
U.S. Natural Gas Processing Plants, Capacity,
and Throughput as of January 1, 1994,
by State
Firm Size for SIC 1311 by Range
of Employees, 1992
Top 20 Oil and Natural Gas Companies, 1993 . .
Performance Measures for OGJ Group, 1993 . . .
Performance of Top 10 Gas Pipeline
Companies, 1994
Model TEG Dehydration Units
Model Condensate Tank Batteries
. XX
xxii
2-11
2-12
2-13
2-14
2-15
2-16
2-17
2-19
2-20
2-22
2-23
2-24
2-25
2-26
2-27
2-28
2-31
2-32
2-34
2-37
2-39
2-39
3-3
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 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,
rr<_cessing 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 . . . 4-30
4-7 Industry-Level Impacts 4-32
4-8 Impacts for Selected Natural Gas Transmission
and Storage Firms 4-36
4-9 Economic Welfare Impacts 4-39
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
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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
XII
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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.
Xlll
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circulated through a boiler where the water vapor is boiled
off.
Gruy "Wellgroups11—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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XVI
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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 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
xvi i
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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 transmission pipelines 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
XVlll
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subset of these five sectors. Horizontal integration also
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
affected sources. Model plants were developed to evaluate the
effects of various control options on the oil and natural gas
production industry and the transmission and storage 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.
Based on public comments on the proposed rule, EPA re-
evaluated the costs and affected units in the Natural Gas
Transmission and Storage sector. A full evaluation is
xix
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presented in the BID, but a suinmary of costs are also
presented in Table ES-1. The final rule for this industry
will control major sources only, whereas the proposal for this
rule evaluated control
xx
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TABLE ES-1. SUMMARY OF ANNUAL CONTROL COSTS BY MODEL PLANT
Model Plant Cost per model
unit
TEG dehydration units
TEG-A -
TEG-B $12,989
TEG-C $12,937
TEG-D $12,790
TEG-E $12,790
Condensate tank batteries
CTB-E -
CTB-F $19,660
CTB-G $24,973
CTB-H $25,071
Natural gas processing plants
NGPP-A $46,747
NGPP-B $61,823
NGPP-C $81,083
Natural gas transmission and
storage units
TEG-A
TEG-B
TEG-C
TEG-D $49,787
TEG-E $49,787
requirements for major and area sources. Therefore, this EIA
for the final rule only presents impacts on major sources.
ES.3 ECONOMIC IMPACT ANALYSIS
This economic impact analysis assesses the market-,
facility-, and industry-level impact of the final rule 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
XX I'.
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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
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. In addition
to the analysis presented at proposal, this EIA also
incorporates an evaluation of the impact on the transmission
and storage sector of the natural gas industry.
To estimate the economic impacts of the regulation on the
natural gas market, 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 at
proposal. The analysis for the final rule maintains this base
year to provide consistent comparisons between the final rule
and proposed rule. 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
'Oil and Natural Gas Production: An Industry Profile. U.S.
Environmental Protection Agency, OAQPS, Research Triangle Park, NC. October
1994. p. 4.
xxii
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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
Natural Gas Production
Market-level impacts
Prices(%) 0.0008%
Wellhead 0.0004%
End-user
Domestic production (%) -0.0003%
Industry-level impacts
Change in revenues ($106) $3.0
Change in costs (106) $7.4
Change in profits ($106) -$4.4
Closures
Production wells 0
Natural gas processing plants 0
Employment losses 0
Economic welfare impacts ($106)
Change in consumer surplus -$0.3
Change in producer surplus -$4.6
Domestic -$4.7
Foreign $0.1
Change in economic welfare -$4.9
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.
For transmission and storage, a screening analysis of
impacts at the firm level was conducted. If this indicated
substantial impacts a full market model as utilized for
natural gas production could have been developed. The
screening analysis showed:
1) that only 7 firms are estimated to be impacted,
2) that total compliance costs on this industry
($300,000) represent only 2/100ths of one percent (0.02%)
of industry revenues, and
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3) that compliance'costs for individuals firms are likely
to represent less than one percent of firm revenues for
the affected firms.
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 natural gas
production, transmission, and storage, the annual social cost
of the regulation is $4.9 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 the associated deadweight loss to society of
the reallocation of resources.
ES.4 REGULATORY FLEXIBILITY ANALYSIS
Environmental regulations such as this final rule 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.
xxv
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Potentially affected firms include entities that own
production wells and/or processing plants and equipment
involved in oil and natural gas production, transmission or
storage. For the production sector, we use financial
information from the Oil and Gas Journal(OGJ)and financial
ratios from Dun and Bradstreet to characterize 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 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. For the natural gas
transmission and storage sector, we use information from the
OGJs special issue of "Pipeline Economics" to determine
impacts on small businesses. With regulation, the change in
measures of profitability for production firms 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. Likewise, for the transmission and
storage sector, impacts are minimal because the majority of
firms included in our analysis have compliance cost-to-
revenues ratios below one percent. Therefore, there is no
evidence of any disproportionate impacts on small entities due
to the final rule on the oil and natural gas production
industry.
XXVI
-------
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 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 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. Special provisions in
Section 112(n)(4) for oil and gas wells and pipeline
facilities affect major source determinations for these
facilities.
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 mere stringent than the floor, considering costs,
nonair quality health and environmental impacts, and energy
requirements.
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.
• 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 regulations.
• Section 4 describes the methodology for assessing the
economic impacts of the regulation and the analysis
results.
1-2
-------
Section 5 explains the methodology for assessing the
company-level impacts of the regulation including an
initial regulatory flexibility analysis to evaluate
the small business effects of the regulation.
1-3
-------
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
-------
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
-------
"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
Marketable
natural gas
"Dry"
natural gas
City Gate
Crude
Oil
Refinery
Figure 2-1. Crude oil and natural gas production flow diagram.
2-3
-------
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
condensat '^h 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
-------
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 Dehydration Units
Once the natural gas has been separated from the crude
oil or condensate and water, residual water is removed from
2-5
-------
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
-------
Gas
Pipeline
Production
Wells
Extracted
Streams __
Separation
Produced
Water _
Storage
Tanks
Disposal or
Beneficial Use
Oil or
Condensate
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
Oper,
i
Lira!
as
r
ening nnhuHntinn
ations Dehydration
r
Sulfur
Recovery
Gas
Natural
Gas
Liquids
Pressurized
Tanks *
1
Pipeline
Fractionation —
\ <
Storage
Tanks
Pipeline
— >• Pipeline
Transfer
Operations
Figure 2-3.
Summary of processes at natural gas
processing plant.
2-8
-------
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 dehydra t i on.
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
-------
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 L-L^lr 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 Domestic 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
-------
TABLE 2-1. TOTAL U.S. PROVED RESERVES OF CRUDE OIL, 1976
THROUGH 1993
(million barrels of 42 U.S. gallons)
Year
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Total discoveries
794
827
636
862
1,161
1,031
924
1,144
995
534
691
553
716
689
554
484
785
Production
2,862
3,008
2,955
2,975
2,949
2,950
3,020
3,037
3,052
2,973
2,873
2,811
2,586
2,505
2,512
2,446
2,339
Proved reserves
33,502*
31,780
31,355
29,810
29,805
29,426
27,858
27,735
28,446
28,416
26,889
27,256
26,825
26,501
26,254
24,682
23,745
22,957
aBased 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.
alternative fuels, and existing regulations. Domestic oil
production is currently in a state of decline that began in
1970. Table 2-3 shows U.S. production in 1992 at 7.2 MMbpd,
which is the lowest level in 30 years.9 Domestic production
of crude oil has dropped by almost 2 MMbpd since 1985. This
decline has been attributed to a transfer of U.S. investment
from domestic sources to foreign production.*
"The investment in foreign ventures is spurred by low labor costs and
less stringent regulatory environments abroad, as well as the increased
likelihood of discovering larger fields in overseas activity.
2-11
-------
TABLE 2-2.
U.S. CRUDE OIL RESERVES BY STATE AND AREA, 1993
(million barrels)
State/area
Alaska
Alabama
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania
Texas
Utah
West Virginia
Wyoming
Federal offshore
Pacific (California)
Gulf of Mexico
(Louisiana)
Gulf of Mexico
(Texas)
Miscellaneous
Total, lower 48 States
Total, U.S.
Proved
reserves
12/31/92
6,022
41
58
3,893
304
36
138
17
310
34
668
102
165
193
26
757
237
58
698
16
6,441
217
27
689
2,569
734
1,643
192
29
17,723
23,745
Total
discoveries
and
adjustments
332
10
17
161
10
10
-7
0
9
-5
77
0
-12
-6
-1
14
19
4
68
-1
309
31
-1
13
492
-11
489
14
8
1,219
1,551
Production
579
10
10
290
30
6
15
2
48
3
106
12
20
16
5
64
30
8
86
1
579
20
2
78
316
50
252
14
3
1,760
2,339
Proved
reserves
12/31/93
5,775
41
65
3,764
284
40
116
15
271
26
639
90
133
171
20
707
226
54
680
14
6,171
228
24
624
2,745
673
1,880
192
34
17,182
22,957
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.
2-12
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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
-------
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-b.
SUMMARY OF U.S. FOREIGN TRADE OF CRUDE OIL,
1983-1992
Imports
Year
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
(MMbpd)
3 .
3.
3,
4.
4,
5.
5
5.
5.
6.
.10
.23
.08
.13
.60
.06
.79
.87
.78
.07
Domestic
crude oil
consump-
tion
(MMbpd)
15
15
15
16
16
17
17
16
16
17
.23
.73
.73
.28
.67
.28
.33
.99
.70
.00
Import
percent-
age of
domestic
consump-
tion
20
20
19
25
27
29
33
34
34
35
.3
.5
.6
.4
.6
.3
.4
.5
.6
.7
Exports
(MMbpd)
0
0
0
0
0
0
0
0
0
0
.16
.18
.20
.15
.15
.15
.14
.11
.12
.09
Domestic
crude oil
output
(MMbpd)
8
8
9
8
8
8
7
7
7
7
.6
.9
.0
.7
.3
.1
.6
.4
.4
.2
Export
percent-
age of
domestic
output
2
2
2
1
1
1
1
1
1
1
.0
.0
.2
.7
.8
.9
.8
.5
.6
.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)
Consumption8 (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
aConsumption 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
-------
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
213,278a
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
-------
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
-------
TABLE 2-8.
U.S. NATURAL GAS RESERVES BY STATE AND AREA, 1993
(Bcf)
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-0131(91). 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
.75
.55
.63
.38
.56
.43
.31
.31
.63
.78
.39
c c.
.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
.7?
.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
Other3
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
19
18
16
17
17
16
17
18
18
18
19
19
.88
.40
.00
.84
.95
.28
.22
.21
.03
.80
.72
.05
.75
alncludes 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
$4
$5
$6
$6
$6
$5
$5
$5
$5
$5
$5
$5
.68
.29
.17
.06
.12
.12
.83
.54
.47
.64
.80
.82
.86
Commercial
$3
$4
$4
$5
$5
$5
$5
$4
$4
$4
$4
$4
$4
.39
.00
.82
.59
.55
.50
.00
.77
.63
.74
.83
.81
.87
Industrial
$2
$3
$3
$4
$4
$3
$3
$2
$2
$2
$2
$2
$2
.56
.14
.87
.18
.22
.95
.23
.94
.95
.96
.93
.69
.81
Electric
utilities
$2
$2
$3
$3
$3
$3
$2
$2
$2
$2
$2
$2
$2
.27
.89
.48
.58
.70
.55
.43
.32
.33
.43
.39
.18
.37
Average
$2
$3
$4
$4
$4
$4
$4
$4
$4
$4
$4
.91
.51
.32
.82
.85
.72
.13
.05
.09
.22
.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
882
880
899
955
913
1,197
936
844
881
863
788
894
689
938
1,220
1,274
1,446
1,644
1,921
2,209
.7
.5
.3
.1
.4
.0
.7
.0
.6
.6
.8
.3
.4
.2
.5
.2
.6
.7
.1
.2
.9
22,
21,
19,
19,
19,
19,
20,
19,
19,
18,
16,
17,
17,
16,
17,
18,
18,
18,
19,
19,
20,
049.
223.
537.
946.
520.
627.
240.
877.
403.
001.
834.
950.
280.
221.
210.
029.
800.
716.
129.
726.
219.
4
1
6
5
6
5
8
3
9
1
9
5
9
3
8
6
8
3
4
2
Oa
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
600
108
952
025
974
471
379
177
519
822
229
197
858
432
918
095
593
585
616
251
.6
.5
.7
.4
.5
.0
.3
.7
.0
.7
.1
.6
.9
.7
.9
.5
.1
.8
.8
.9
.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
.3
.4
.4
.3
.3
.3
.3
.2
.3
.3
.3
.3
.3
.4
.3
.4
.6
.5
.7
.2
.7
aPreliminary 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
Production
(Tcf)
Consumption
(Tcf)
Wellhead price
(1993 $/Mcf)
Actual
1993
18.35
20.21
2.02
Alternative
projections
to 2010
Base case High Low
economic economic economic
growth
20.88
24.59
3.39
growth
21.91
25.85
3.74
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
Source :
Natural gas
producing wells
170,300
193,900
214,100
219,100
214,600
217,800
232,100
241,100
265,100
280,900
U.S. Department of Energy.
Crude oil
producing wells
603,300
620,800
646,600
628,700
621,200
623,600
606,900
602,400
610,200
594,200
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-
61-
60
100
101-200
201-
301-
401-
501-
601-
1001-
2001-
5001-
Total
300
400
500
600
1000
2000
5000
Over
Number
of
oil wells
3^6
67
76
47
20
21
13
29
22
9
3
617
,C32
,150
,926
,263
,631
,433
,044
,992
,134
,735
,555
,895
Percentage
of
total
49
10
12
7
3
3
2
4
3
1
_o.
100
.5
.9
.4
.6
.3
.5
.1
.9
.6
.6
.0
Number
of
gas wells
135,
24,
28,
17,
10,
6,
5,
12,
10,
6,
3.
261,
231
049
144
765
859
957
442
400
042
365
806
060
Percentage
of
total
51
9
10
6
4
2
2
4
4
2
_i
100
.8
.2
.8
.8
.2
.7
.0
.7
.0
.4
^4.
.0
Source: Gruy Engineering
Economic Impacts
for the American
Corporation. Estimates of RCRA Reauthorization
on the Petroleum Extraction Industry. Prepared
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 OCS
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
4.96
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 Gruy 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 BOE that equals 10 Mcf. The
production rate ranges in BOE 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. 21(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
Natural gas (MMcfd)
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
Capacity
785
7,775
878
1,044
1,596
890
5,122
141
18,334
4,731
884
19
2,889
122
20
4,656
14
17,259
624
398
3.783
71, 971
.0
.0
.0
.0
.5
.0
.0
.0
.4
.9
.2
.5
.0
.9
.0
.8
.0
.5
.9
.9
.7
.2
1993 throughput
700
6,502
520
658
1,128
622
3,778
117
11,869
858
209
6
2,122
83
8
2,857
8
12,002
416
337
2.973
47,783
.7
.0
.5
.5
.6
.0
.4
.9
.4
.6
.5
.8
.2
.2
.8
.5
.3
.5
.2
.9
,6
.1
Source: "Worldwide Gas Processing Report.
11(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 firm 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 and
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
-------
TABLE 2-20. TOP 20 OIL AND NATURAL GAS COMPANIES, 1993
Rank Company
1
2
3
4
5
6
7
8
E 9
<] 10
11
12
13
14
15
16
17
18
19
20
Exxon Corp.
Mobil Corp.
Chevron Corp .
Amoco Corp.
Shell Oil Co.
Texaco Inc .
ARCO (Atlantic Richfield
Corp . )
Occidental Petroleum Corp.
BP (USA)
Conoco Inc .
Enron Corp.
Phillips Petroleum Co.
USX-Marathon Group
Coastal Corp.
Unocal Corp.
Amerada Hess Corp.
Columbia Gas System
Ashland Oil Inc.
Consolidated Natural Gas Co.
Pennzoil Co.
Total
assets
($103)
84,145,000
40,585,000
34,736,000
28,486,000
26,851,000
26,626,000
23,894,000
17,123,000
14,864,000
11,938,000
11,504,315
10,868,000
10,806,000
10,277,100
9,254,000
8,641,546
6,957,900
5,551,817
5,409,586
4,886, 203
Total
revenue
($103)
111,211,000
63,975,000
37,082,000
28,617,000
21,092,000
34,071,000
19,183,000
8,544,000
15,714,000
15,771,000
8,003,939
12,545,000
11,962,000
10,136,100
8,344,000
5,872,741
3,398,500
10,283,325
3,194,616
2,782,397
Worldwide
Net liquids
income production
($103) (Mil bbl)
5,280,
2,084,
1,26^.
1,820,
781,
1,068,
269,
283,
1,461,
812,
332,
243,
-29,
115,
213,
-268,
152,
142,
205,
141,
000
000
000
000
000
000
000
000
000
000
522
000
000
800
000
203
200
234
916
856
568
285
295
236
170
228
250
79
--
135
3
89
57
4
84
79
3
8
3
24
.0
.0
.0
.0
.0
.0
.0
.0
.0
.5
.0
.0
.9
.0
.0
.6
.3
.9
.0
Worldwide
natural gas
production
(Bcf)
1,583
1,665
902
1,487
553
748
449
238
--
481
262
509
317
122
623
323
71
36
124
223
.0
.0
.0
.0
.0
.0
.0
.0
.0
.2
.0
.0
.0
.0
.0
.5
.2
.0
.0
U.S.
liquids
production
(Mil bbl)
202.0
111.0
144.0
100.0
147.0
155.0
221.0
21.0
228.9
40.0
2.5
47.0
41.0
4.9
48.0
26.0
3.6
0.4
3.9
24.0
U.S.
natural gas
production
(Mil bbl)
697.0
558.0
751.0
867.0
539.0
652.0
332.0
219.0
33.6
305.0
240.0
345.0
193.0
122.0
365.0
183.0
71.5
36.2
124.0
220.0
Note: All values are in 1993 U.S. dollars.
Source: "Total Earnings Rose, Revenues Fell in
September 5, 1994.
1993 for OGJ300 Companies." Oil and Gas Journal. 22(36):49-75.
-------
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 1994.49 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
Perf ormance 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 eras 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
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.
t
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
-------
References:
1. U.S. Environmental Protection Agency. 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. Office of Air Quality Planning and
Standards. Research Triangle Park, NC. July 1996.
2. Ref. 1, p. 2-6.
3. Ref. 1, p. 2-6.
4. Wright Killen & Co. Natural Gas Dehydration: Status and
Trends. January 1994. Prepared for Gas Research Institute,
Chicago, IL.
5. Ref. 1, p. 2-13 through 2-15.
6. U.S. Department of Energy. Energy Information
Administration. U.S. Crude Oil, Natural Gas, and Natural
Gas Liquids Reserves: 1993 Annual Report. October 1994.
7. Ref . 6 .
8. Ref. 6.
9. U.S. Department of Energy. Petroleum Supply Annual 1992.
DOE/EIA-0340(92)-1. Vol. 1. May 1993.
10. Ref. 9.
11. U.S. Department of Energy. Natural Gas Annual 1991.
DOE/EIA-0131(91). Washington, DC. October 1992.
12. U.S. Department of Energy. Annual Energy Review 1991.
DOE/EIA-0384(91). June 1992.
13. Independent Petroleum Association of America. Fact Sheet.
"IPAA Supply and Demand Committee Short Run Forecast for
1993."
14. Independent Petroleum Association of America. Fact Sheet.
"IPAA Supply and Demand Committee Long Run Forecast for
1993-2000." May 6, 1993.
15. Ref. 6.
16. Ref. 14.
2-50
-------
17. Ref. 6.
18. Ref. 6.
19. Ref. 9.
20. Ref. 11.
21. Ref. 9.
22. Ref. 11.
23. Doane, Michael J., and Spulber, Daniel F. "Open Access and
the Evolution of the U.S. Spot Market for Natural Gas."
Journal of Law and Economics. 12:477-517. October 1994.
24. Energy Statistics Sourcebook, 8th ed. PennWell Publishing
Co. September 1993.
25. Ref. 24.
26. U.S. Department of Energy. Energy Information
Administration. Natural Gas Monthly U.S. Natural Gas
Imports and Exports--1993. August 1994.
27. U.S. Department of Energy. Natural Gas 1994: Issues and
Trends. DOE/EIA-0560(94). Energy Information
Administration. Washington, DC. July 1994.
28. Haun, Rick R. U.S. Gas Processing Prospects to Improve
After Mid-90s. Oil and Gas Journal. 11(23).
29. Ref. 6.
30. Ref. 14.
31. U.S. Department of Energy. Natural Gas 1992: Issues and
Trends. DOE/EIA-0560(92). Washington, DC. March 1993.
32. Gruy Engineering Corporation. Estimates of RCRA
Reauthorization Economic Impacts on the Petroleum Extraction
Industry. Prepared for the American Petroleum Institute.
July 20, 1991.
33. "Producing Gas Well Numbers Still Climbing," World Oil.
215_(2) :77, February 1994.
34. Ref. 32.
35. Ref. 4, Table B-l.
2-51
-------
36. Memorandum from Akin, Tom, EC/R Incorporated to Smith,
Martha E.; EPA/CPB. July 30, 1993. Revised preliminary
estimate of the number and size ranges of tank batteries on
a national basis.
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 Journal.
£2(24) :49-110. June 13, 1994.
40. Ref. 39.
41. U.S. Department of Commerce. Census of Mineral Industries-
Industry Series. Bureau of the Census, 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. 92 (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. 12(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.
2-52
-------
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 s20 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
Capacity (MMcfd)
A B
<5 5 to
20
C
20 to
50
D
>50 to
500
E Total
>500
Throughput (MMcfd) 0.3 10
Estimated
population
Stand-alone 24,000 200
® Condensate 12,000 500
tank battery
@ Natural gas 66
processing plant
@ Offshore 260
production
platform
® Natural gas 200 125
transmission and
underground
storage
TOTAL 36,200 1,151
35
25
100
110
40
35
100
20
70
54
500
10
10
24,245
12,670
230
300
370
300
154
10 37,815
Source: National Emission Standards for Hazardous Air Pollutants for
Source Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information Document. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
April 1997.
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, and
• CTB H: >50 MMcfd.
3-3
-------
TABLE 3-2. MODEL CONDENSATE TANK BATTERIES
Capacity (MMcfd)
Throughput (MMcfd)
Estimated population
Model plant
E F G H Total
s5 5 to 20 20 to 50 >50
1 10 35 100
12,000 500 100 70 12,670
Source: National Emission Standards for Hazardous Air Pollutants for
Source Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information Document. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
April 1997.
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 £100 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
Capacity (MMcfd)
Throughput (Mmcfd)
Estimated population
Model plant
A B
*20 20 to 100
10 70
260 300
C
>100
200
140
Total
700
Source: U.S. Environmental Protection Agency. National Emission Standards
for Hazardous Air Pollutants for Source Categories: Oil and
Natural Gas Production and Natural Gas Transmission and Storage—
Background Information Document. Office of Air Quality Planning
and Standards. Research Triangle Park, NC. April 1997.
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
t
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 State waters State waters
Capacity (BOPD) 1,000 5,000
Throughput (BOPD) 200 2,000
Estimated population 260 40 300
Source: National Emission Standards for Hazardous Air Pollutants for
Source Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information Document. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
April 1997.
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
are 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
Natural gas
processing
plant
Offshore
production
platforms
Open-top
storage tank
Fixed roof
storage tank
Equipment
leaks
Cover and vent to 95%
control device or
redirect
Fixed roof
storage tank
Equipment leaks LDARa
Vent to 95% control
device or redirect
Vapor collection and
redirect
LDAR
Equipment leaks LDAR
99
95
70
95
70
70
a 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: National Emission Standards for Hazardous Air Pollutants for
Source Categories: Oil and Natural Gas Production and Natural Gas
Transmission and Storage —Background Information Document. U.S.
Environmental Protection Agency. Research Triangle Park, NC.
April 1997.
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
3-7
-------
of the operations at black oil tank batteries and are
completely controlled at offshore production platforms.
The engineering analysis contained in the BID document
projects the number of major 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
Affected units
Stand-alone
® Condensate TB
® NGPP
® transmission and
storage facility
Total
A
36,200
0.0%
0
0
0
0
0
B
1,151
22.7%
138
109
14
0
261
C
300
50.3%
25
100
26
0
151
D
154
18.2%
20
5
3
4
32
E
10
50.0%
0
0
0
3
3
Total
37,615
445
183
214
43
5
445
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
Item
Total population
Percent affected
Affected units
E
12,000
0%
0
F
500
21.8%
109
tank battery
G
100
10.0%
10
H
70
7.1%
5
Total
12,670
1.0%
124
TABLE 3-8. TOTAL AND AFFECTED POPULATION OF NATURAL GAS
PROCESSING PLANTS BY MODEL TYPE
Model NGPP
Item
Total population
Percent affected
Affected units
A
260
2.7%
7
B
300
1.3%
4
C
140
0.7%
1
Total
700
1.7%
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
-------
TABLE 3-9.
REGULATORY CONTROL COSTS PER UNIT FOR THE OIL AND NATURAL GAS PRODUCTION
INDUSTRY BY MODEL PLANT
Control option/model plant"
Condenser control systemsc
TEG-B
TEG-B'
TEG-C
TEG-C'
TEG-D
TEG-E
Storage tank controls/recycle
CTB-F
CTB-G
CTB-H
NGPP-A
NGPP-B
NGPP-C
Number of
Affected
Units
157
104
67
84
28
5
50
4
2
3
2
0
Total
capital
cost
$13,620
$11,400
$13,620
$11,400
$11,400
$11,400
$3,590
$3,590
$3,590
$3,590
$3,590
$3,590
Annualized
capital
cost
$1,495
$1,252
$1,495
$1,252
$1,252
$1,252
$394
$394
$394
$394
$394
$394
Operating and
maintenance
cost"
$11,626
$11,538
$11,626
$11,538
$11,538
$11,538
$2,511
$2,511
$2,511
$2,511
$2,511
$2,511
Total
annual
cost
$13,121
$12,790
$13,121
$12,790
$12,790
$12,790
$2,905
$2,905
$2,905
$2,905
$2,905
$2,905
Product
recovery
credit
$2,825
$2,825
$9,789
$9,789
$23,783
$3,580
$71
$93
$115
$115
$115
$115
Storage tank controls/fuel substitute
CTB-F
CTB-G
CTB-H
NGPP-A
NGPP-B
NGPP-C
50
4
2
3
2
1
$3,590
$3,590
$3,590
$3,590
$3,590
$3,590
$394
$394
$394
$394
$394
$394
$2,511
$2,511
$2,511
$2,511
$2,511
$2,511
$2,905
$2,905
$2,905
$2,905
$2,905
$2,905
$46
$60
$75
$75
$75
$75
(continued)
-------
TABLE 3-9.
REGULATORY CONTROL COSTS PER UNIT FOR THE OIL AND NATURAL GAS PRODUCTION
INDUSTRY BY MODEL PLANT (CONTINUED)
Number of
Affected
Control option/model plant" Units
Storage tank controls/flare
TB-F
TB-G
TB-H
NGPP-A
NGPP-B
NGPP-C
w Leak detection and repair
^ NGPP-A
1-1 NGPP-B
NGPP-C
9
2
1
1
0
0
7
4
1
Total
capital
cost
$37,080
$37,080
$45,260
$37,080
$37,080
$45,260
$1,378
$1,378
$1,378
Annualized
capital
cost
$4,071
$4,071
$4,970
$4,071
$4,071
$4, 970
$6,564
$6,564
$6,564
Operating and
maintenance
costb
$44,490
$44,490
$44,817
$44,490
$44,490
$44,817
$10,543
$19,479
$40,331
Total
annual
cost
$48,561
$48,561
$49,787
$48,561
$48,561
$49,787
$11,921
$20,857
$41,709
Product
recovery
credit
$0
$0
$0
$0
$0
$0
$135
$340
$815
' Abbreviations are TEG for triethylene glycol dehydration units, CTB for condensate tank batteries, and NGPP for
natural gas processing plants. The letter following the hyphen designates the model plant.
b Included in this cost category are operating and maintenance costs, other annual costs (i.e., administrative, taxes,
insurance, etc.), and monitoring, inspection, recordkeeping, and reporting costs.
c Model condensate tank battery E is not listed since it does not incur control costs. Also the presence of a flash
tank at glycol dehydration units affects the compliance costs. Thus, model TEG-B represents a glycol dehydration
unit without a flash tank, white model TEG-B' has a flash tank.
-------
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. Recovered liquid, condensate,
and crude oil were assig'ned 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
Tabl_ r-10 summarizes the annual control costs for major
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
-------
TABLE 3-10. SUMMARY OF ANNUAL CONTROL COSTS BY MODEL PLANT
Model Plant
Cost per model unit
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
NGPP-B
NGPP-C
Natural gas transmission and storage
TEG-A
TEC D
TEG-C
TEG-D
TEG-E
$12,989
$12,937
$12,790
$12,790
$19,660
$24,973
$25,071
$46,747
$61,823
$81,083
$49,787*
$49,787
Three of the four affected TEGs of this size are assumed to have control
costs of $49,787, while the fourth TEG is assumed to have control costs of
$4,315.
3-13
-------
References:
1. Ref. 1, Chapter 4.
2. Ref. 1, p. 2-4.
3. Ref. 39.
4. U.S. Department of the Interior/Minerals Management
Service. Federal Offshore Statistics: 1993 (OCS Report
MMS 94-0060). Herndon, VA. 1994.
5. Ref. 1, Table 3-1.
6. Ref. 1.
7. Ref. 1.
3-14
-------
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 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.1 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.2'3 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 effects on the world
4-1
-------
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.4 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.5
Based on this research, the U.S. market for natural gas was
modeled as a national, perfectly competitive market for a
homogeneous commodity.
Sections 4.1 through 4.3.2.2 assesses the market-,and
industry-level impact of the regulation on the natural gas
4-2
-------
production industry. These sections provide 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. Section 4.3.2.2 presents a screening analysis of
impacts on the natural gas transmission and storage industry.
Section 4.4 provides conclusions for the impacts on society
from these regulations.
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,
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
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.
4-3
-------
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 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 produccj.on 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
Qmin 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 t*16 minimum economically feasible production rate,
which is determined by the minimum of the ATAC curve, which
coincides with the price Pmin. 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
-------
$/Q
P1
mm
ATAC
Qmi
mm
Q
Q/t
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 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
This characterization of the economics regarding the operating decision agrees with that described in
Reference 6.
4-5
-------
involve shifting upward the ATAC and MC curves as shown in
Figure 4-2 by the per-unit compliance cost (operating and
4-6
-------
$/Q
p;
min
rmin
Qmin Q'min
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'^J is
determined by a new (higher) Pmin.
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 S1 (see
Figure 4-3). The supply shifts for natural gas cause the
4-7
-------
$/Q
PI
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
4-8
-------
• 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.6
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
4-9
-------
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 at
proposal. The analysis for the final rule maintains this same
base year for consistency.
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 NaturalGas 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
4-10
-------
units of measure between Gruy and supporting data sources, all
units of natural gas production were converted to thousands of
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.7
Oil and gas production fields were randomly allocated to the
natural gas processing plants within a State given the plant-
level natural gas processing throughput for 1993 as provided
4-11
-------
in the OGJ survey. However, in many cases, natural gas that
is extracted in one State is processed in another 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
4-12
-------
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.
4-13
-------
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.8
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 the 720 as reported in the industry profile (section 2)because plants in OGJ
processing survey that indicated no throughput for 1993 were excluded from the analysis.
4-14
-------
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).9
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, & 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) .10
TEG units at natural gas 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.
4-15
-------
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
OGJ 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 for
this analysis 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
4-16
-------
TABLE 4-2. SUMMARY OF ALLOCATION OF PRODUCTION WELLS, PROCESSING PLANTS, AND MODEL
UNITS FOR 1993 BY STATE
Wells providing natural gas to plants within
that State
State
Alaska
Alabama
Arkansas
California
Colorado
Florida
i Kansas
•j Kentucky
Louisiana
Michigan
Mississippi
Montana
North Dakota
New Mexico
Oklahoma
Pennsylvania
Ohio
West Virginia
Texas-Gulf Coast
Texas-North
Texas-West
Oil
wells
1,541
0
12,726
40,482
8,306
2,779
33,967
0
71,049
2,099
1,811
0
2,101
5,606
59,564
0
0
0
56,558
50,502
61,913
Gas
wells
157
2,274
2,974
1,018
7,157
1,395
26,850
7,842
131,256
2,196
278
83
80
17,596
12,472
258
609
24,154
17,647
14,521
7,750
Total
1,698
2,274
15,700
41,500
15,463
4,174
60,817
7,842
202,305
4,295
2,089
83
2,181
23,202
72,036
258
609
24,154
74,205
65,023
69,663
Natural gas
processed
(Mmcfd)
6,499.2
701.9
520.3
659.4
1,129.6
621.3
3,776.5
118.0
11,865.5
859.0
209.6
7.1
83.2
2,122.2
2,863.4
8.2
8.8
337.8
7,037.9
1,679.7
3,284.0
A
286
339
206
577
781
369
2,747
0
5,973
69
92
1
9
1,205
1,834
0
0
0
5,119
882
1,778
Stand-alone TEG
B
1
2
3
2
4
2
13
0
62
1
1
0
0
10
21
0
0
0
47
7
6
C
1
1
1
0
0
1
3
0
4
0
0
0
0
1
2
0
0
0
4
1
3
D
1
1
2
0
4
0
4
0
5
0
1
0
0
0
0
0
0
0
2
0
0
Total
289
343
212
579
789
372
2,767
0
6,044
70
94
1
9
1,216
1,857
0
0
0
5,172
890
1,787
-------
TABLE 4-2. SUMMARY OF ALLOCATION OF PRODUCTION WELLS, PROCESSING PLANTS, AND MODEL
UNITS FOR 1993 BY STATE (CONTINUED)
Condensate tank batteries
State E F
Alaska
Alabama
Arkansas
California
Colorado
Florida
Kansas
Kentucky
i Louisiana
oo Michigan
Mississippi
Montana
North Dakota
New Mexico
Oklahoma
Pennsylvania
Ohio
West Virginia
Texas-Gulf Coast
Texas-North
Texas-West
Utah
Wyoming
G H Total
27
79
60
281
326
84
555
0
2,765
86
54
1
27
571
1,175
0
0
0
2,220
665
1,418
137
918
Natural gas processing plants
ABC Total8
2
4
3
6
6
4
32
0
162
4
3
0
1
40
53
0
0
0
99
32
15
8
26
3
1
3
3
0
2
15
0
32
1
0
0
1
7
1
0
0
0
11
4
10
1
5
4
2
2
0
4
2
6
0
25
0
1
0
0
0
4
0
0
0
15
0
1
2
2
36
86
68
290
336
92
608
0
2,984
91
58
1
29
618
1,233
0
0
0
2,345
701
1,444
148
951
0
2
1
15
27
0
6
0
14
7
3
6
5
6
34
1
0
3
22 .
42
34
7
15
0
4
1
11
14
1
4
3
22
9
2
0
1
20
48
0
1
2
69
27
44
5
16
3
3
1
2
4
1
11
0
32
11
1
0
0
7
10
0
0
2
21
7
10
2
9
3
9
3
28
45
2
21
3
68
27
6
6
6
33
92
1
1
7
112
76
88
14
40
-------
natural gas producing field resulting from the generalized
Leontief technology is:
q. = v + —
J J 2
1
1/2
(4.1)
u 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
B2
that corresponds with a shutdown price equal to -i— 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:
r 11-1/2
(4.2)
The market-level supply elasticity for natural gas is assumed
to be 0.2624, which reflects the production-weighted average
4-19
-------
S/q,
71 -q,
Figure 4-4. Theoretical supply function of natural gas
producing well.
supply elasticity estimated across EPA regions as shown in
Table 4-3.n 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 P, 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
4-20
-------
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.12 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:
4-21
-------
(4.3)
where
qx = foreign supply of natural gas (Mcf ) ,
A1 = positive constant, and
S1 = 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. ,
(4.4)
where q1 is foreign supply of natural gas and ]£ QJ" is the
j
domestic supply of natural gas, which is the sum of natural
gas production across all U.S. producing fields (j).
4-22
-------
4.2.3 Demand for Natural Gas
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 (qf) , that is,
" = Bd "' (4-5)
where
pi = the end-user price for sector I,
r\l = the demand elasticity for end-use sector I,
B^ = 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.13 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.14 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
4-23
-------
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
a 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.15 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.
4-24
-------
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.
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 @RAND function in
Lotus 1-2-3.
• 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.
• 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.
4-25
-------
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 (c.,) 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^ - GJ . Thus, the supply function for producing
fields, assuming the generalized Leontief production
technology becomes:
'1/2
(4.7)
n = v. + —
J J 2
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.j -Cj) falls
B2
below the shutdown price of -*— , then the producing field's
production response for the supply equation given the
4-26
-------
regulatory control costs will be less than or equal to zero
(i.e., q., < 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.16 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 OGJ processing survey.17 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
4-27
-------
TABLE 4-5. BASELINE EQUILIBRIUM VALUES FOR
ECONOMIC MODEL: 1993
Item
Producers
Domestic
Foreign
Total
Consumers
Residential
Commercial
Industrial
Electric utility
Other
Average/ total
Price3
($/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.
4-28
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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 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-
4-29
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user prices, resulting in a new market demand for
natural gas.
5) 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 changes in wellhead and end-use prices for each
regulatory scenario are all nearly zero (less than 0.0005
percent change). 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.18 The increase in foreign imports of natural gas is
also inconsequential (totaling less than 0.0004 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
4-30
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TABLE 4-6. SUMMARY OF NATURAL GAS MARKET ADJUSTMENTS FOR MAJOR SOURCES
I
OJ
Major sources
Item
Producers
Domestic
Foreign
Total
Consumers
Residential
Commercial
Industrial
Electric
utility
Other
Total
Price
($/Mcf)
$2.01
$2.01
$6.15
$5.16
$3.07
$2.61
N/A
$4.16
Percent
change
(%)
0.00044%
0.00044%
0.00014%
0.00017%
0.00029%
0.00034%
N/A
0.00021%
Quantity
(MMcf)
17,440,551
2,350,123
19,790,674
4,955,997
2,905,999
7,935,986
2,681,991
1,310,701
19,790,674
Percent
change
(%)
-0.00020%
0.00035%
-0.00014%
-0.00005%
-0.00005%
-0.00018%
-0.00034%
0.00000%
-0.00014%
(continued)
-------
the change in industry output. Workers' dislocation costs
associated with industry-wide job losses are also computed.
Table 4-7 summarizes these industry-level impacts by
regulatory scenario.
TABLE 4-7. INDUSTRY-LEVEL IMPACTS
Oil and Natural Gas Production Category
Change in revenues ($106) $3.1
Market adjustments $0.2
Product recovery $2.9
Change in costs ($106) $7.4
Post-regulatory
control costs $7.5
Costs of production
adjustment -$0.1
Change in profits ($106) -$4.3
Closures
Production wells 0
Natural gas processing
plants 0
Employment loss 0
Natural Gas Transmission and Storage Category
Compliance Costs ($106) $0.3
4.3.2.1 Post-Reaulatory Compliance Cost. The post-
regulatory compliance cost at each facility can be calculated
as the product of the total annual compliance cost per unit
(Cj) and the new output rate (q*'). At the industry-level,
the post-regulatory compliance cost for major sources is
roughly $7.5 million for production facilities 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 output rates may change at affected producing
wells.
4-32
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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 sources, the total increase in revenue is
$3 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 ($2.9 million). The total
increase in production cost is $7.4 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 ($7.5 million) and the decrease in costs
due to the lower output rate ($0.1 million). These costs
amount to just C.004 percent of the total revenues in 1993 of
the 300 largest publicly traded oil and natural gas producing
companies in the U.S.19'20 The changes in total revenue and
total cost are used to measure the profitability impact of the
regulations which indicates a loss of $4.3 million at the
industry level due to regulation.
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
industry. No closure or employment effects are estimated to
occur.
4.3.2.3 Screening Analysis for Natural Gas Transmission
and Storage
The cost estimates for the 7 major sources in the natural gas
transmission and storage category were not included in the
market model reported above. Between proposal and promulgation
of this rule, data was collected through surveys and site
visits for 81 facilities, however, only one facility in EPA's
4-33
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database, KN Interstate Gas Transmission Company, is known to
be affected by the standard. We db not have information on
the other six facilities estimated to be affected by the rule.
Below is a screening analysis of Impacts on the natural gas
transmission and storage industry, the calculated impact for
KN Interstate Gas Transmission Company, and an approach to
characterize potential impacts for other affected facilities.
First, to screen the potential impacts on the market for
natural gas transmission and storage, we calculate the ratio
of total compliance costs with industry revenues. This
calculation can give some insight into potential price
increases and the level of potential impacts on the
transmission and storage market. Information on pipeline
economics from the OGJ21 indicates total 1997 revenues of $16.1
billion for all pipeline firms listed. A total regulatory
cost of $jGu,000 would represent CT..02% of market revenues.
This level of impact is unlikely to be enough of a shock to
production costs throughout the market to cause the supply
curve to shift upward, so market price would not be expected
to increase as a result of the regulation. This impact is
also overstated to the extent that the table of firms from the
OGJ does not list all of the firms in the industry. The table
includes all "major" and "non-major* firms (as defined by the
FERC), which are required to report pipeline company
statistics. The overstatement of impacts will be minimal if
the firms reported in the OGJ table constitute a large
majority of the industry.
To screen for impacts of the rule on individual firms, we
calculate the ratio of firm compliance cost to firm revenues*.
If the ratio is greater that one percent for a substantial
number of firms this screening would indicate a need for
It should be noted that while the estunated regulatory impact of $300,000 is based on seven facilities, this
analysis is based on firm-level impacts. A firm may own one facffily or seven! facilities - a portion of which might
be affected by the final rule.
4-34
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further evaluation, especially for small businesses in
accordance with requirements of the Regulatory Flexibility Act
and the Small Business Regulatory Enforcement and Fairness
Act. Using the information provided by the OGJ, we selected
data for 42 pipeline companies that transferred greater than
100 Mmscf of natural gas per year corresponding to the
throughput of EPA's model TEG-D units and larger. It is
assumed that companies listed in this table with less than 100
Mmscf would not be affected by the rule because they may not
be a major source (as defined by the Clean Air Act), or they
may be major but excluded from this regulation due to the 85
Mmscf cut-off for control requirements. From the information
given in the table, we obtained the total volume of gas sold
and transferred, and operating revenues to calculate the cost-
to-revenues ratios for each company. The firms were then
divided into two categories: (1) those with throughput of 100
but less than 500 Mmscf (i.e., model TEG-D size category), and
(2) those with throughput greater than or equal to 500 Mmscf
(i.e. model TEG-E facilities). Table 4-8 below displays the
firm information for the two TEG size categories. We then
calculate the cost-to-revenue ratios assuming one TEG
transfers all of the throughput indicated for the firm (i.e. a
TEG-D can transfer as little as 100 Mmscf , or as much as 499
Mmscf). The cost associated with controlling a single TEG is
$49,787, which is used in the numerator of the ratio.
As Table 4-8 demonstrates, this rule will have a minimal
impact on affected firms. All but one of the 42 companies in
the analysis had a cost-to-revenue ratio well below 1%,
including KN Interstate Gas with a ratio of 0.06%. The range
of ratios for the listed firms is from 0.003% to 1.32%. The
average firm ratio is 0.09%, which indicates that the impacts
are typically well below l/10th of one percent.
It is also possible for a firm to transfer it's volume
through multiple TEGs of various sizes. As is previously
4-35
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mentioned, TEGs with throughputs below 85 Mmscf do not have
control requirements resulting from this rule. Therefore,
firms that utilize multiple TEG units will have a portion of
those controlled by the rule. Again, we do not have
information on the number of affected TEG units operated at
the listed firms. Alternatively, we calculate the number of
TEGs it would take to equate to 1% of a firm's revenues.
Table 4-8 shows that on average, it would require 57 TEGs to
be controlled for compliance costs to reach 1% of firm
revenues.
In summary, the screening of compliance costs on market
and firm revenues shows minimal impacts on the natural gas
transmission and storage industry. Nearly all of the firms
have impacts below 1%, and it would require the control of 57
TEGs on average for greater impacts to be realized. With this
information, it is not likely that small businesses will be
significantly impacted and the further evaluation of the
industry is not warranted.
4-36
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TABLE 4-8. IMPACTS ON SELECTED
NATURAL GAS TRANSMISSION AND STORAGE FIRMS
(See Excel file: Transl)
4-37
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4.4 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 4-9 shows the estimated economic
welfare change. These estimates represent the social cost of
the regulation. For major sources, the social cost of the
regulation is $4.9 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 units may close and not incur the regulatory costs.
Thus, the difference between the engineering estimate of
social cost and that derived through economic welfare analysis
is the deadweight loss to society of the reallocation of
resources.
4-39
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TABLE 4-9. ECONOMIC WELFARE IMPACTS ($106)
Change in consumer surplus -$0.32
Change in producer surplus -$4.33
Domestic -$4.36
Foreign $0.04
Change in surplus for . -$0.30
transmission and storage
Change in economic welfare -$4.94
4-40
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References:
1. 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.
2. Farzin, Yeganeh Hossein. Competition in the Market for
an Exhaustible Resource. Jai Press, 1986.
3. Crimer, Jacques. Models of the Oil Market. Harwood
Academic Publishers, 1991.
4. Ref. 23, p. 477-517.
5. Ref. 23.
6. Bradley, M.E., and Wood, A.R.O. "Forecasting Oilfield
Economic Performance," JPT. November 1994.
p. 965-971.
7. Ref. 39, p. 63-109.
8. 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.
9. Ref. 1, Table 4-1.
10. Ref. 1, Table 4-1.
11. 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.
12. 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.
13. Al-Sahlawi, Mohammed A. "The Demand for Natural Gas: A
Survey of Price and Income Elasticities," Energy
Journal 10(1) January 1989.
14. Ref. 69.
15. Ref. 69.
4-41
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16. U.S. Department of Energy. Natural Gas Monthly.
Energy Information Administration, Washington, DC.
Tables 18, 19, 20, and 21. October 1994.
17. Ref. 39, p. 63.
18. Ref. 72, Table 4.
19. Ref. 46.
20. Dun's Analytical Services. Industry Norms and Key
Business Ratios. Dun and Bradstreet, Inc. 1994.
21. "Weather, Construction Inflation Could Sqeeze North
American Pipelines." Oil and Gas Journal Special.
August 31, 1998.
4-42
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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
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 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 revised EPA
5-1
-------
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,1
this firm-level analysis addresses the RFA requirements by
measuring the impacts on small entities in the oil and natural
gas production source category. In addition, the screening
analysis presented in section 4.3.2.3 provides an indication
that small transmission and storage firms are also not likely
to experience significant impacts.
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
-------
(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
4923
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
-------
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 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
-------
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
-------
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
-------
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 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.l 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 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.2'3 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-Recrulation 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 (%)
1382-Oil a^rl nas Exploration Services
Quick ratio (times)
Current ratio (times)
Current liab. to net worth (%)
Fixed assets to net worth (%)
2911-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
guartile
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)
TABLE 5-2. DUN AND BRADSTREET'S BENCHMARK FINANCIAL RATIOS
BY SIC CODE FOR THE OIL AND NATURAL GAS PRODUCTION INDUSTRY
(CONTINUED)
5-9
-------
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
cjuartile
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 1994.4
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
-------
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
($106
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
(annual!zed 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
-------
E
>»
u
c
3
er
£
u.
/ U 70 -
60% -
50% -
40% -
30% -
20% -
10% -
0% -
ll
r~
' '^aji.
-Weig
hted Avg. = 0.090%
i"l"' 1''" J.I | ^f
••••••«• •""•€ V^Sv^i - ? i ^
, .,., ., . ..
.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
/ V 70 -
60% -
2 50% -
« 40% -
§ 30% -
£ 20% -
10% -
n% .
\
I Maximum = 0.187%
/
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 (%)
(b) Large Companies
/ U 70 -
60% -
g, 50% -
o 40% -
c
a 30% -
£ 20% -
10% -
0% -
,r-
"^-Weighted Avg. = 0.013%
\ *''' ' \
, ;;j"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 (%)
(c) Total, All Companies
Figure 5-2. Distribution of total annual compliance cost to sales ratio for sample companies.
5-12
-------
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
-------
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
Current assets
Fixed assets
Other noncurrent
assets
Total assets
Current
liabilities
Noncurrent
liabilities
Total liabilities
Net worth
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.
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
-------
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.5 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:
5-16
-------
• liquidity or solvency
• asset management
• debt management
• profitability
• market value
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
5-17
-------
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
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
5-18
-------
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
negligible and show no overall disproportionate impact across
small and large firms.
The screening analysis of the transmission and storage
firms in section 4.3.2.2 shows that the cost-to-revenues
ratios of the selected firms is 0.09% on average, which
indicates that impacts are typically well below I/10th of one
percent for these firms.
Therefore, this information presented in this section of
the EIA along with the screening analysis of the transmission
and storage firms in section 4.3.2.2 clearly indicates that
there will not be a significant impact on a substantial number
of small entities in the natural gas production, and
transmission and storage industries.
5-19
-------
References:
1. Ref. 49.
2. Ref. 46.
3. Ref. 76.
4. Ref. 39.
5. Brigham, Eugene F., and Louis C. Gapenski. Financial
Management: Theory and Practice. 6th Ed. Orlando,
FL, The Dryden Press. 1991.
6. Ref. 82.
5-20
-------
APPENDIX A
GRUY ENGINEERING CORPORATION'S
OIL WELLGROUPS BY STATE
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE
Depth
State/ range
wellgroup (Mft)
Alaska
AKOIL 1
AKOIL 2
AKOIL 3
AKOIL 4
AKOIL 5
AKOIL 6
AKOIL 7
AKOIL 8
AKOIL 9
AKOIL 10
AKOIL 11
AKOIL 12
AKOIL 13
AKOIL 14
AKOIL 15
AKOIL 16
AKOIL 17
AKOIL 18
AKOIL 19
AKOIL 20
AKOIL 21
AKOIL 22
AKOIL 23
AKOIL 24
AKOIL 25
AKOIL 26
AKOIL 27
AKOIL 28
AKOIL 29
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)
12.43
31.33
91.17
42.80
54.17
610.07
2,233.33
176,855.57
100.50
32,719.13
2.20
1.93
3.33
16.30
14.10
34.97
60.73
160.77
546.37
2,778.30
1,732,915.13
26.10
50.03
22.93
2.03
161.20
472.47
5,214.00
2,990,463.67
Oil rate
per well
(Bd)
1.33
0.17
0.70
14.27
17.53
187.30
2,142.23
37,691.77
50.27
6,184.60
0.27
3.57
4.97
15.40
8.90
10.97
29.93
94.03
463.40
2,250.57
808,289.93
0.33
0.67
10.13
18.10
57.43
348.40
2,726.60
1,039,351.67
(continued)
A-l
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
Alabama
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
ALOIL
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
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
C-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 +
BOE
range
(BOE/mo)
0-
61-
101-
201-
301-
501-
601-
1, 001-
2,001-
5,001-
0-
Gl-
101-
201-
301-
401-
501-
601-
1, 001-
2,001-
0-
201-
401-
601-
1,001-
2,001-
5,001-
0-
101-
201-
301-
401-
60
100
200
300
400
600
1, 000
2,000
5,000
Over
60
100
200
300
400
500
600
1, 000
2, 000
5, 000
60
300
500
1,000
2,000
5,000
Over
60
200
300
400
500
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
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
Gas rate
per well
(Mcfd)
0
5
6
324
0
188
138
107
2,093
1,808
3
61
148
103
124
4
214
19
156
162
0
0
0
1
5
37
13
0
0
0
31
6
.00
.13
.13
.13
.00
.63
.47
.40
.50
.80
.07
.97
.47
.07
.03
.90
.97
.50
.30
.50
.00
.00
.40
.07
.53
.53
.03
.10
.00
.17
.53
.30
Oil rate
per well
(Bd)
1.
7.
43.
3,587.
505.
762.
665.
362.
1,755.
2,062.
6.
22.
185.
254.
191.
148.
129.
138.
57.
57.
1.
9.
16.
49.
231.
680.
202.
2.
5.
10.
66.
30.
90
73
53
97
47
30
37
10
03
70
20
30
97
83
57
47
83
43
00
20
43
00
27
10
03
23
33
03
53
17
90
17
A-2
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
ALOIL
33
10 +
BOE
range
(BOE/mo)
501-
600
Number
of
wells
2
Number
of
fields
3
Gas rate
per well
(Mcfd)
8
.33
Oil rate
per well
(Bd)
28
.90
(continued)
ALOIL
ALOIL
ALOIL
ALOIL
Arkansas
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
34
35
36
37
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
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
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5, 001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
0-
61-
101-
201-
301-
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
60
100
200
300
400
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
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
113
382
1,557
4,389
28
7
26
138
32
38
227
3,222
0
178
912
1
9
46
119
11
70
3
410
106
159
55
61
213
284
581
.43
.23
.57
.67
.77
.93
.17
.67
.70
.27
.73
.50
.00
.27
.30
.97
.87
.00
.83
.33
.40
.70
.07
.53
.07
.43
.17
.93
.63
.80
130
381
2,214
6,605
1,176
1,722
2,474
1,186
2,793
421
790
871
4,341
339
1,529
672
798
1,883
1,150
782
435
272
1,049
1,022
577
16
17
295
460
403
.43
.27
.33
.90
.03
.60
.17
.97
.13
.93
.53
.00
.50
.43
.90
.57
.87
.33
.90
.20
.47
.23
.20
.90
.90
.10
.60
.27
.67
.17
A-3
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
AROIL
AROIL
AROIL
27
28
29
6-10
6-10
6-10
BOE
range
(BOE/mo)
401-
501-
601-1
500
600
,000
Number
of
wells
20
12
50
Number
of
fields
12
7
20
Gas rate
per well
(Mcfd)
179
343
1,652
.23
.30
.83
Oil rate
per well
(Bd)
264
167
1,033
.17
.93
.10
(continued)
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
AROIL
Arizona
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
AZOIL
30
31
32
33
34
35
36
37
38
39
40
41
1
2
3
4
5
6
7
8
9
10
11
12
13
California -Coastal
CACNOIL 1
CACNOIL 2
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
and
0-2
0-2
1,001-2
2,001-5
5,001-
0-
61-
201-
401-
501-
601-1
1,001-2
2,001-5
5,001-
101-
301-
401-
601-1
2,001-5
0-
101-
201-
301-
401-
501-
601-1
2,001-5
Northern
0-
61-
, 000
,000
Over
60
100
300
500
600
,000
,000
,000
Over
200
400
500
,000
, 000
60
200
300
400
500
600
,000
,000
60
100
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
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
2,247
3,947
1,600
3
8
7
94
5
245
1,394
1,465
2,320
4
7
44
56
4
0
5
94
34
0
69
55
0
131
395
.10
.77
.67
.37
.30
.50
.53
.63
.33
.40
.73
.40
.17
.83
.47
.30
.40
.00
.77
.73
.83
.00
.10
.03
.00
.83
.40
904
561
70
i,
0
1
12
7
16
85
178
54
135
4
9
9
42
121
0
4
31
18
16
12
40
71
229
324
.40
.43
.67
.33
.57
.27
.17
.57
.77
.70
.17
.63
.20
.47
.97
.47
.90
.83
.27
.37
.50
.20
.60
.63
.33
.57
.37
A-4
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
we 11 group
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
Depth
range
(Mft)
3
4
5
6
7
0-2
0-2
0-2
0-2
0-2
BOE
range
(BOE/mo)
101-
201-
301-
401-
501-
200
300
400
500
600
Number
of
wells
292
160
119
68
47
Number
of
fields
58
36
39
29
23
Gas rate
per well
(Mcfd)
1,228
1,031
1,348
567
522
Oil rate
per well
(Bd)
.53
.03
.27
.50
.53
1,
1,
1,
066
022
085
836
744
.93
.10
.70
.27
.30
(continued)
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
8
9
10
11
12
13
-v a
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
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+
601-
1,001-
2,001-
5,001-
0-
61-
1C1-
201-
301-
401-
501-
601-
1, 001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
1, 000
2, 000
5,000
Over
60
100
200
300
400
500
600
1,000
2, 000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
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
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
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
961
3,073
4,871
7,494
2,657
2
.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
2,
3,
2,
2,
2,
2,
2,
1,
6,
5,
5,
2,
4,
5,
1,
436
650
699
792
156
418
135
382
245
612
808
883
908
474
594
29
44
406
509
624
718
699
277
637
325
990
2
.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
A-5
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
CACNOIL
Depth
range
(Mft)
35
36
37
38
39
40
41
10 +
10 +
10 +
10+
10 +
10 +
10 +
BOE
range
(BOE/mo)
61-
101-
201-
301-
401-
501-
601-
100
200
300
400
500
600
1,000
Number
of
wells
8
17
23
38
31
24
60
Number
of
fields
4
5
8
7
8
8
11
Gas rate
per well
(Mcfd)
16
64
111
373
643
574
1,507
Oil rate
per well
(Bd)
.20
.67
.93
.03
.10
.00
.80
1,
13
71
156
363
357
310
263
.77
.73
.40
.70
.33
.73
.60
(continued)
CACNOIL
CACNOIL
CACNOIL
42
43
44
California- Los
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
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
1,001-
2,001-
5,001-
Basin
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
2, 000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
63
36
3
382
291
591
396
232
177
111
273
174
48
1
189
176
493
415
282
230
176
396
239
59
10
7
1
29
24
37
40
32
30
24
37
30
20
1
30
30
39
38
37
34
29
44
32
19
1,683
3,053
350
191
505
1,261
1,408
1, 037
1,001
673
2,385
2,376
1,258
15
124
195
1,136
1,342
1,398
1,290
954
3,133
3,014
2,009
.30
.70
.20
.60
.17
.77
.10
.03
.27
.20
.63
.10
.47
.00
.23
.30
.43
.37
.13
.00
.37
.57
.03
.57
2,
3,
2,
2,
2,
2,
1,
6,
7,
4,
2,
3,
2,
3,
3,
9,
9,
4,
602
251
565
319
631
516
896
493
395
881
438
559
424
192
128
377
154
Oil
921
135
027.
435
753.
674,
.90
.53
.37
.37
.47
.60
.70
.33
.53
.97
.13
.20
.30
.43
.73
.67
.20
.63
.70
.20
.90
.87
.57
.80
A-6
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
Depth
range
(Mft)
22
23
24
25
26
27
28
29
30
2-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
BOB
range
(BOE/mo)
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
Over
60
100
200
300
400
500
600
1,000
Number
of
wells
1
60
35
112
83
75
67
32
86
Number
of
fields
1
19
21
22
29
28
24
24
29
Gas rate
per well
(Mcfd)
40
19
102
470
754
1,036
1,073
564
1,894
.20
.93
.77
.30
.53
.40
.30
.90
.23
Oil rate
per well
(Bd)
168
36
67
451
540
706
812
490
1,951
.53
.80
.87
.67
.47
.13
.03
.37
.50
(continued)
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
CALAOIL
31
32
33
34
35
36
37
38
39
40
41
42
43
44
California -San
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
1
2
3
4
5
6
7
8
6-10
6-10
6-ir
10+
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10+
10 +
Jose Basin
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5, C01-
0-
61-
101-
201-
301-
401-
501-
601-
2, 000
5,000
Over
60
100
200
300
400
500
600
1,000
2, 000
5,000
Over
60
100
200
300
400
500
600
1,000
75
46
10
3
1
6
4
9
5
5
7
7
8
1
3812
2369
4493
3091
2474
2050
1541
3920
21
11
5
1
1
6
4
6
5
4
5
6
4
1
77
56
54
45
32
34
24
31
2,006
2,038
449
11
2
4
9
138
111
59
202
226
417
255
S20
743
1,963
1,703
1,770
1,639
1,715
4,760
.37
.97
.97
.50
.40
.67
.43
.80
.77
.23
.73
.40
.00
.63
.23
.10
.40
.93
.13
.00
.33
.87
3,183
4,551
1,982
1
2
30
22
74
62
67
138
339
749
225
2,968
5,237
19,634
23,541
26,934
28,980
26,846
96,300
.70
.50
.90
.00
.40
.67
.40
.40
.10
.57
.60
.47
.67
.73
.03
.23
.90
.70
.10
.40
.50
.23
A-7
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
Depth
range
(Mft)
9
10
11
12
13
14
15
16
17
18
19
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)
1,001-2,000
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
5,000
Over
60
100
200
300
400
500
600
1,000
Number
of
wells
2971
1137
266
1280
865
1400
830
447
303
254
660
Number
of
fields
24
20
9
57
52
55
53
40
31
26
27
Gas rate
per well
(Mcfd)
9,799
21,738
110,704
985
1,736
7,310
8,410
6,593
6,641
6,752
29,171
.00
.57
.47
.90
.33
.10
.87
.17
.60
.80
.67
Oil rate
per well
(Bd)
127,933
102,768
61,404
999
1,862
5,482
5,453
4,038
3,468
3,595
12,579
.63
.57
.97
.33
.63
.23
.63
.97
.57
.77
.37
(continued)
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
CASJOIL
::
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
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 +
1, C01-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
2,000
5,000
Over
60
100
200
300
400
500
600
1, 000
2,000
5,000
Over
60
100
200
300
400
500
600
520
295
38
74
49
144
97
69
53
40
112
132
143
147
21
10
16
29
16
10
17
24
14
7
37
20
39
39
27
26
21
18
20
17
6
15
10
9
15
11
9
11
35,959
28,730
18,777
29
183
796
1,487
1,363
1,669
1,499
9,722
24,153
71,093
195,646
8
21
88
317
111
367
398
.97
.93
.40
.10
.33
.57
.23
.60
.13
.47
.03
.97
.53
.73
.97
.43
.87
.80
.03
.57
.53
16,932
18,800
6,337
47
82
476
529
548
557
469
1,802
3,472
8,207
46,313
5
16
58
160
124
84
261
.00
.80
.57
.93
.57
.60
.43
.13
.60
.27
.73
.83
.40
.93
.90
.10
.83
.43
.33
.97
.17
A-8
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
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
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
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
6-10
6-10
6-10
6-10
6-10
6-10
BOB
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
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
Number
of
wells
38
34
44
36
129
22
81
27
28
16
7
7
4
3
429
840
857
230
148
88
56
121
129
127
39
270
407
975
418
146
101
Number
of
fields
18
15
12
5
16
13
23
14
4
7
1
4
3
3
73
88
162
92
67
47
35
52
30
17
6
93
89
129
85
51
39
Gas rate
per well
(Mcfd)
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
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
Oil rate
per well
(Bd)
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
148.73
(continued)
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
A-9
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
COOIL
COOIL
COOIL
COOIL
COOIL
Florida
FLOIL
FLOIL
FLOIL
FLOIL
FLOIL
FLOIL
FLOIL
FLOIL
FLOIL
28
29
30
31
32
1
2
3
4
5
6
7
8
9
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)
501-
601-1
1,001-2
2,001-5
5,001-
601-1
1,001-2
2,001-5
5,001-
61-
101-
201-
301-
501-
600
,000
,000
,000
Over
,000
,000
,000
Over
100
200
300
400
600
Number
of
wells
44
98
76
430
10
1
1
1
1
1
1
3
4
2
Number
of
fields
25
45
23
13
5
1
2
1
1
1
1
1
4
3
Gas rate
per well
(Mcfd)
2,357
6,765
7,984
16,352
1,247
3
65
9
834
32
42
22
65
34
.63
.77
.73
.83
.17
.07
.40
.80
.57
.17
.17
.20
.47
.43
Oil rate
per well
(Bd)
388
1,559
2,289
33,830
2,107
25
58
103
704
3
6
22
16
32
.53
.50
.20
.30
.37
.43
.17
.03
.90
.33
.67
.20
.67
.80
(continued)
FLOIL
FLOIL
FLOIL
FLOIL
Illinois
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
ILOIL
Indiana
10
11
12
13
1
2
3
4
5
6
1
8
9
10
11
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
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
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
7
19
39
44
5424
5421
14865
3006
1146
630
426
708
462
210
51
4
10
13
8
132
250
433
217
127
88
59
91
57
25
12
107
550
1,984
20,896
0
0
0
0
0
0
0
0
0
0
0
.20
.03
.73
.33
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
89
693
3,422
15,087
937
2,275
12,122
6,760
3,960
2,966
2,504
5,807
6,916
6,499
5,835
.23
.73
.67
.57
.07
.20
.03
.17
.70
.17
.30
.33
.80
.63
.70
A-10
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
INOIL
INOIL
INOIL
INOIL
INOIL
INOIL
INOIL
INOIL
INOIL
INOIL
INOIL
Kansas
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
1
2
3
4
5
6
7
8
9
10
11
1
2
3
4
5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
BOE
range
(BOE/mo)
0-
61-
101-
201-
301-
401-
501-
601-
1, 001-
2,001-
5,001-
0-
61-
101-
201-
301-
60
100
200
300
400
500
600
1, 000
2,000
5,000
Over
60
100
200
300
400
Number
of
wells
1205
1894
3062
677
274
155
73
119
66
17
7
11041
2824
2204
833
219
Number Gas rate
of per well
fields (Mcfd)
70
135
188
88
45
31
16
26
14
6
3
385
385
691
249
103
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
Oil rate
per well
(Bd)
2
1
6
5
8
5
1
202.17
683.73
,394.47
,402.87
851.43
658.17
387.33
901.87
874.80
486.60
350.93
,667.47
,559.90
,269.37
,269.77
,873.87
(continued)
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
0
0
0
0
0
0
2
2
2
2
2
2
2
2
2
-2
-2
-2
-2
-2
-2
-6
-6
-6
-6
-6
-6
-6
-6
-6
401-
501-
601-
1, 001-
2,001-
5, 001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
500
600
1,000
2, 000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
125
74
93
69
11
4
7001
6754
8015
2524
955
508
292
556
320
67
40
56
44
10
3
565
989
B93
373
206
147
234
153
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
1
1
1
2
1
7
13
29
15
8
5
4
10
10
,430.70
,025.37
,761.77
,517.87
637.70
,053.67
,051.93
,896.93
,623.00
,720.63
,413.90
,930.70
,034.57
,691.93
,400.10
A-ll
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
KSOIL
Kentucky
KYOIL
KYOIL
KYOIL
KYOIL
KYOIL
21
22
23
24
25
26
27
28
29
30
31
32
33
1
2
3
4
5
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
BOE
range
(BOE/mo)
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
61-
0-
61-
101-
201-
301-
5,000
Over
60
100
200
300
400
500
600
1, 000
2,000
5,000
100
60
100
200
300
400
Number
of
wells
107
21
15
10
137
66
25
15
6
21
16
10
5
4495
8494
5828
1181
502
Number
of
fields
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
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
Oil rate
per well
(Bd)
7,183.67
4,623.77
2.43
4 .
97
285.50
327.
197.
175.
74.
397.
545.
704.
10.
328.
1,605.
3,071.
1,592.
1,047.
23
07
30
93
93
40
97
87
67
87
80
67
70
(continued)
KYOIL
KYOIL
KYOIL
KYOIL
KYOIL
KYOIL
6
7
8
9
10
11
0-2
0-2
0-2
0-2
0-2
0-2
401-
501-
601-
1,001-
2,001-
5,001-
500
600
1, 000
2,000
5,000
Over
185
119
264
231
86
33
20
17
26
23
7
3
0
0
0
0
0
0
.00
.00
.00
.00
.00
.00
512.
402.
1,183.
1,876.
1,772.
1,646.
77
67
43
80
30
60
Louisiana -North
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
1
2
3
4
5
6
0-2
0-2
0-2
0-2
0-2
0-2
0-
61-
101-
201-
301-
401-
60
100
200
300
400
f
500
9725
531
455
101
40
14
37
23
32
15
14
8
516
115
118
13
31
0
.63
.93
.50
.77
.33
.87
5,964.
1,310.
1,838.
646.
396.
159.
77
47
93
73
87
30
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
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
LANOIL
Depth
range
(Mft)
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
34
35
36
37
38
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 +
10 +
10 +
10 +
BOE
range
(BOE/mo)
501-
601-1
1,001-2
2,001-5
600
,000
,000
,000
5,001- Over
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-
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
Number
of
wells
16
27
17
6
3
2117
452
588
341
231
153
116
267
234
81
2
66
41
117
76
60
57
30
55
69
31
19
8
4
15
11
17
Number
of
fields
8
12
15
6
4
90
74
111
86
66
60
41
59
54
25
1
40
26
50
44
43
37
21
33
40
14
1
7
5
12
6
11
Gas rate
per well
(Mcfd)
23.
30.
70.
64.
888.
537.
'656.
2,103.
1,784.
1,837.
2,503.
1,327
4,715
5,698
4,699
88
45
87
634
772
580
1,113
1,476
1,860
4,107
7,121
55,878
15
24
57
341
230
33
10
90
30
80
87
.03
.80
.33
.90
.53
.70
.50
.23
.90
.30
.07
.20
.50
.63
.60
.20
.00
.83
.27
.90
.43
.20
.37
.97
.80
.17
Oil rate
per well
(Bd)
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)
656.93
376.60
1,192.63
2,346.67
2,093.67
514.30
3.*7
7.33
51.20
58.20
143.23
A-13
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
LANOIL
Depth
range
(Mft)
39
10-f
BOE
range
(BOE/mo)
401-
500
Number
of
wells
13
Number
of
fields
9
Gas rate
per well
(Mcfd)
505
.57
Oil rate
per well
(Bd)
132
.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
-
12
13
14
15
16
17
18
19
20
21
0
0
0
0
0
0
0
0
0
0
0
2
2
2
2
2
2
2
2
2
2
-2
-2
-2
-2
-2
-2
•2
-2
-2
-2
-2
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5, C01-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2, 001-
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
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
100
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)
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
22
23
24
25
26
27
28
29
30
2
-6
6-10
6-10
6-10
6-10
6-10
6-10
6-10
6-10
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
Over
60
100
200
300
400
500
600
1,000
26
100
60
158
186
179
176
177
526
16
57
42
96
106
93
92
96
157
1,775
49
76
562
1,023
1,738
2,176
2,670
12,262
.90
.03
.13
.07
.73
.53
.73
.77
.53
3,741
69
96
546
1,140
1,585
2,056
2,628
10,709
.90
.30
.33
.40
.93
.57
.20
.87
.57
A-14
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
LASOIL
Michigan
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
Depth
range
(Mft)
31
32
33
34
35
36
37
38
39
40
41
42
43
44
1
2
3
4
5
6
7
8
9
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)
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
101-
301-
401-
501-
601-
1,001-
2,001-
0-
61-
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5, 000
Over
60
200
400
500
600
1,000
2,000
5,000
60
100
Number
of
wells
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
154
123
55
37
18
60
51
57
47
48
94
121
132
58
1
1
2
1
1
7
3
2
21
22
Gas rate
per well
(Mcfd)
25,215
35/752
26,934
22
65
503
892
1,173
1,135
1,707
5,890
18,507
44,269
63,689
33
51
50
51
129
462
603
200
9,849
4,107
.57
.47
.57
.57
.30
.93
.90
.73
.70
.90
.77
.50
.97
.80
.33
.30
.00
.20
.37
.50
.33
.00
.33
.30
Oil rate
per well
(Bd)
22,136
29,837
23,851
21
32
335
546
711
673
1,101
4,294
11,376
22,691
39,835
22
52
28
13
8
106
30
123
337
520
.90
.23
.47'
.20
.27
.57
.63
.20
.80
.23
.00
.27
.10
.23
.77
.07
.93
.13
.70
.93
.63
.43
.93
.93
(continued)
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
11
12
13
14
15
16
17
2-6
2-6
2-6
2-6
2-6
2-6
2-6
101-
201-
301-
401-
501-
601-
1,001-
200
300
400
500
600
1,000
2,000
411
400
203
84
122
238
377
35
33
32
20
19
38
38
8,838
8,329
2,121
1,004
2,047
7,649
26,107
.43
.53
.93
.13
.67
.03
.70
2,433
5,354
747
385
632
1.712
4.454
.10
.17
.43
.77
.13
.43
.93
A-15
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
MIOIL
Missouri
MOOIL
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
1
2
2
6-
6-
6-
6-
6-
6-
6-
6-
6-
6-
6-
-6
-6
•10
•10
•10
•10
•10
•10
•10
•10
•10
•10
•10
10 +
10 +
0
-2
BOE
range
(BOE/mo)
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
2,001-
5, 001-
0-
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
5,000
Over
60
Number
of
wells
418
99
31
31
99
99
81
41
26
128
305
229
41
3
6
807
Number
of
fields
34
19
4
e
15
12
18
12
10
24
24
21
13
2
2
0
Gas rate
per well
(Mcfd)
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
.77
.33
.80
.70
.03
.97
.37
.27
.90
.67
.63
.67
.57
.67
.00
.10
Oil rate
per well
(Bd)
13,091
8,148
13
83
563
1,339
235
141
138
745
3,598
6,265
2,886
173
356
377
.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
1
8
9
0
0
0
0
0
0
0
0
0
-2
-2
-2
-2
-2
-2
-2
-2
-2
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
60
100
200
300
400
500
600
1,000
2,000
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
217
121
279
237
705
1,847
.37
.87
.00
.37
.07
.60
.07
.60
.80
(continued)
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
10
11
12
13
14
0
0
2
2
2
-2
-2
-6
-6
-6
2,001-
5,001-
0-
61-
101-
5,000
Over
60
100
200
38
5
66
55
146
12
3
19
22
47
1,888
0
9
32
77
.70
.00
.67
.37
.83
2,209
549
19
57
359
.67
.00
.13
.27
.63
A-16
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
MSOIL
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
42
43
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)
201-
301-
401-
501-
601-
1,001-
2,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
300
400
500
600
1,000
2,000
5,000
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2, 000
5,000
Over
Number
of
wells
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
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)
118
185
333
36
947
873
731
1
18
40
107
222
323
306
1,555
1,844
3,086
232
5
12
46
73
146
377
139
1,139
2,805
11,177
12,424
.77
.40
.20
.03
.90
.07
.87
.70
.80
.33
.23
.80
.60
.10
.03
.03
.10
.97
.87
.13
.93
.70
.30
.77
.87
.97
.10
.97
.30
Oil rate
per well
(Bd)
663.
792.
845.
701.
2,389.
3,681.
3,069.
11.
32.
308.
531.
780.
811.
780.
3,823.
4,905.
7,858.
523.
15.
16.
100.
187.
373.
608.
651.
2,591.
5,534.
11,524.
14,861.
40
13
27
63
70
27
73
60
17
53
87
57
40
20
10
97
73
00
23
53
63
67
13
43
90
03
23
77
27
(continued)
Montana
MTOIL
MTOIL
1
2
0-2
0-2
0-
61-
60
100
1070
227
17
14
89
72
.67
.40
740.
462.
17
83
A-17
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
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
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
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
(BOE/mo)
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-
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
,000
,000
,000
Over
60
100
Number
of
wells
142
28
8
1
5
2
1
550
281
364
174
87
72
39
89
58
25
1
19
19
70
85
104
71
70
209
222
88
7
9
3
Number
of
fields
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)
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
.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)
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
.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)
MTOIL
34
10+
101-
200
12
12
21
.73
46
.00
A-18
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
MTOIL
35
36
37
38
39
40
41
42
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-
300
400
500
600
,000
,000
, 000
Over
Number
of
wells
14
18
30
24
76
106
50
14
Number
of
fields
15
18
27
22
46
66
32
10
Gas rate
per well
(Mcfd)
40
98
293
331
1,745
3,837
3,428
3,231
.23
.13
.27
.50
.60
.77
.10
.80
Oil rate
per well
(Bd)
95
173
376
399
1,815
4,466
4,451
2,217
.47
.70
.60
.70
.37
.73
.70
.27
North Dakota
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
NDOIL
1
2
3
4
5
6
7
B
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
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
0-
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-
60
200
300
400
500
600
,000
,000
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
2
4
9
2
2
2
3
5
6
6
84
103
289
207
95
54
53
72
46
19
6
73
51
133
2
4
5
1
2
2
2
6
6
6
46
43
65
55
32
24
23
24
15
9
5
37
25
51
0
2
117
3
38
22
11
20
196
640
44
74
436
705
354
113
310
255
109
314
184
39
202
1,221
.00
.10
.07
.60
.57
.97
.43
.30
.10
.97
.27
.23
.33
.17
.37
.10
.57
.67
.10
.10
.33
.97
.33
.03
0
10
62
22
18
16
60
66
520
995
78
241
1,299
1,566
1,056
759
916
1,692
1,992
1,657
1,108
23
59
409
.37
.93
.27
.93
.83
.60
.67
.33
.43
.60
.13
.23
.13
.60
.33
.73
.17
.87
.97
.00
.50
.00
.63
.23
A-19
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
NDOIL 25
NDOIL 26
NDOIL 27
NDOIL 28
NDOIL 29
NDOIL 30
NDOIL 31
NDOIL 32
NDOIL 33
NDOIL 34
NDOIL 35
NDOIL 3:
NDOIL 37
NDOIL 38
NDOIL 39
NDOIL 40
NDOIL 41
NDOIL 42
NDOIL 43
Nebraska
NEOIL 1
NEOIL 2
NEOIL 3
NEOIL 4
NEOIL 5
NEOIL 6
NEOIL 7
NEOIL 8
NEOIL 9
NEOIL 10
NEOIL 11
NEOIL 12
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
2-6
2-6
BOE
range
(BOE/mo)
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
?01- 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
501- 600
601-1,000
2,001-5,000
0- 60
61- 100
101- 200
201- 300
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
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
Gas rate
per well
(Mcfd)
2,323.43
2,444.53
2,133.83
2,069.53
8,519.37
14,738.37
15,897.07
20,293.10
30.53
27.70
163.93
234.57
518.90
695.93
923.30
4,398.97
13,360.37
21,523.03
46,475.90
0.50
6.30
165.90
13.93
0.00
0.00
0.00
39.67
24.77
76.43
381.53
193.17
Oil rate
per well
(Bd)
(continued)
1,253.23
1,643.23
1,743.80
1,839.37
7,351.93
13,123.53
14,098.87
9,926.43
7.00
17.20
113.83
193.37
349.50
500.90
499.33
2,523.60
7,596.97
12,330.33
11, 876.00
32.13
134.93
364.97
104.47
116.57
39.63
1,843.13
145.13
131.30
486.47
1,903.60
2,310.43
A-20
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
NEOIL
NEOIL
13
14
2
2
-6
-6
BOE
range
(BOE/mo)
301-
401-
400
500
Number
of
wells
121
25
Number
of
fields
36
16
Gas rate
per well
(Mcfd)
361
84
.10
.60
Oil rate
per well
(Bd)
1,281
357
.07
.93
(continued)
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
NEOIL
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
2
2
2
2
6-
6-
6-
6-
6-
6-
6-
6-
6-
6-
6-
-6
-6
-6
-6
•10
•10
•10
•10
•10
•10
•10
•10
•10
•10
•10
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-
600
,000
,000
,000
60
100
200
300
400
500
600
,000
, 000
, 000
Over
54
23
77
5
35
45
97
38
15
9
9
10
7
8
1
12
16
12
4
26
29
67
31
14
9
9
11
7
4
1
68
48
65
0
10
23
45
88
60
6
5
49
51
189
72
.87
.60
.23
.00
.77
.10
.17
.50
.00
.87
.27
.77
.20
.77
.80
1,020
572
3,384
318
50
117
454
303
162
118
159
243
273
736
221
.33
.77
.70
.83
.43
.37
.63
.37
.27
.20
.90
.00
.40
.47
.67
New Mexico
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
NMOIL
1
2
3
4
5
6
7
8
9
10
11
12
13
14
0
0
0
0
0
0
0
0
0
0
0
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
2-6
2
2
-6
-6
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
101-
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
200
881
240
276
102
52
35
14
24
13
11
2
2424
1550
2409
93
52
52
34
24
24
13
22
13
12
2
186
173
179
778
605
1,065
305
274
739
565
965
702
693
1,138
4,115
8,030
27,423
.37
.93
.80
.63
.10
.93
.67
.97
.10
.97
.83
.77
.80
.43
594
513
1,144
734
518
395
146
301
209
655
192
1,877
3,055
8,415
.57
.63
.77
.53
.43
.40
.40
.53
.93
.70
.80
.23
.83
.50
A-21
-------
APPENDIX A:
GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
NMOIL 15
NMOIL 16
NMOIL 17
NMOIL 18
NMOIL 19
NMOIL 20
NMOIL 21
NMOIL 22
NMOIL 23
NMOIL 24
NMOIL 25
NMOIL 26
NMOIL 27
NMOIL 28
NMOIL 29
NMOIL 30
NMOIL 31
NMOIL 32
NMOIL 33
NMOIL 34
NMOIL 35
NMOIL 36
NMOIL 37
NMOIL 38
NMOIL 39
NMOIL 40
NMOIL 41
NMOIL 42
NMOIL 43
NMOIL 44
Nevada
NVOIL 1
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 +
2-6
BOE
range
(BOE/mo)
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
101- 200
Number
of
wells
1256
729
456
302
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
Number
of
fields
145
117
101
68
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
Gas rate
per well
(Mcfd)
26,772.07
22,602.07
18,856.53
15,637.30
42,880.60
39,434.20
20,413.93
5,310.07
1,945.70
3,058.47
14,319.67
21,075.57
21,493.30
18,712.67
13,888.27
47,243.90
46,788.27
38,694.57
20, 120.20
151.23
264.43
1,048.77
2,157.83
2,121.67
1,079.30
1,895.20
6,001.57
6,715.53
8,737.60
8,444.53
0.00
Oil rate
per well
(Bd)
7,168.60
5,874.97
4,615.13
3,662.23
(continued)
11,097.90
14,102.07
17,644 .83
11,350.73
221.73
479.63
2,556.23
2,863.57
3,276.43
2,998.77
2,526.53
7,780.37
12,054.23
16,448.33
13,884.27
39.47
79.50
364.03
666.10
756.00
626.93
798.20
2,738.20
4,376.93
4,465.53
6,760.47
4.57
A-22
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
NVOIL
NVOIL
NVOIL
NVOIL
NVOIL
NVOIL
2
3
4
5
6
7
2
2
2
2
2
-6
-6
-6
-6
-6
2-6
BOE
range
(BOE/mo)
201-
301-
401-
501-
601-1
1,001-2
300
400
500
600
,000
,000
Number
of
wells
4
6
3
1
6
5
Number
of
fields
3
4
1
1
3
4
Gas rate
per well
(Mcfd)
0
0
0
0
0
0
.00
.00
.00
.00
.00
.00
Oil rate
per well
(Bd)
33
60
26
19
155
235
.87
.63
.07
.43
.27
.40
(continued)
NVOIL
NVOIL
New York
NYOIL
NYOIL
NYOIL
NYOIL
NYOIL
Ohio
OHOIL
OHOIL
OHOIL
OHOIL
OHOIL
OHOIL
Oklahoma
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
OKOIL
8
9
1
2
3
4
5
1
2
3
4
5
6
1
2
3
4
5
6
7
8
9
10
2
2
0
0
0
0
0
0
2
2
2
2
2
0
0
0
0
0
0
0
-6
-6
-2
-2
-2
-2
-2
-2
-6
-6
-6
-6
-6
-2
-2
-2
-2
-2
-2
-2
0-2
0
-2
0-2
2,001-5
5,001-
0-
61-
101-
201-
601-1
0-
61-
101-
201-
501-
1,001-2
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
,000
Over
60
100
200
300
,000
60
100
200
300
600
,000
60
100
200
300
400
500
600
,000
,000
,000
11
9
3805
70
49
20
6
27356
1424
841
374
154
45
28981
5990
6742
2612
928
356
215
401
171
65
4
5
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
514
453
694
271
157
104
63
80
43
17
0
0
0
0
0
0
0
0
0
0
0
0
0
6,130
7,604
15,807
27,232
10,788
6,913
5,101
14,083
8,669
8,480
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.10
.33
.97
.40
.30
.07
.77
.57
.53
.77
1,135
7,267
863
146
179
162
145
11,722
3,511
3,929
3,395
3,076
2,751
14,132
8,905
18,709
10,845
5,708
2,696
1,984
5,176
3,734
3,967
.23
.77
.97
.13
.00
.17
.03
.67
.13
.10
.77
.20
.20
.57
.77
.37
.10
.53
.67
.67
.33
.70
.63
A-23
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
OKOIL 11
OKOIL 12
OKOIL 13
OKOIL 14
OKOIL 15
OKOIL 16
OKOIL 17
OKOIL 18
OKOIL 19
OKOIL 20
OKOIL 21
OKOIL 22
OKOIL 23
OKOIL 24
OKOIL 25
OKOIL 26
OKOIL 27
OKOIL 28
OKOIL 29
OKOIL 30
OKOIL 31
OKOIL 32
OKOIL 33
OKOIL 34
OKOIL 35
OKOIL 36
OKOIL 37
OKOIL 38
OKOIL 39
OKOIL 40
OKOIL 41
OKOIL 42
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+
BOE
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
Number
of
wells
7618
5631
7341
2763
2058
2179
401
1135
411
151
34
1744
1978
5442
3076
1756
1045
704
1330
934
294
50
47
87
355
247
196
145
113
282
271
79
Number
of
fields
480
529
884
461
265
173
109
151
110
45
13
147
153
352
267
181
138
109
149
91
57
16
25
31
90
75
54
39
34
56
44
24
Gas rate
per well
(Mcfd)
7,213.00
10,941.07
27,160.73
21,579.57
13,968.10
9,767.73
6,176.83
25,833.57
13,864.33
19,590.67
4,423.87
7,406.00
18,072.63
84,083.67
83,240.47
61,732.17
45,540.30
39,961.50
90,218.90
84,621.93
58,906.73
21,552.97
215.63
616.90
3,088.33
4,626.53
5,262.33
5,375.67
6,301.57
18,881.97
21,834.70
19,129.67
Oil rate
per well
(Bd)
4,620.70
8,228.37
19,611.37
12,102.60
13,669.33
20,633.57
3,962.33
15,867.40
(continued)
10,290.30
7,389.10
3,720.73
551.53
1,541.33
8,815.57
7,986.80
6,832.63
5,628.17
4,238.90
12,456.63
17,596.13
9,896.50
5,527.10
9.87
62.17
524.63
759.97
932.07
823.00
697.07
2,791.87
5,614.13
2,313.10
A-24
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
OKOIL
Depth
range
(Mft)
43
10 +
BOE
range
(BOE/mo)
5,001-
Over
Number
Of
wells
44
Number
of
fields
12
Gas rate
per well
(Mcfd)
35,422.
,70
Oil rate
per well
(Bd)
4,368.
17
Pennsylvania
PAOIL
PAOIL
PAOIL
PAOIL
1
2
3
4
0
0
0
0
-2
-2
-2
-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
0
0
-2
-2
-2
101-
201-
1, 001-
200
300
2,000
2
2
2
1
1
2
0.
0.
0.
.00
.00
.00
8.
14.
44.
73
90
50
(continued)
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
SDOIL
Tennessee
TNOIL
TNOIL
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
1
2
0
2
2
2
-2
-f
-6
-6
2-6
2
2
2
2
6-
6-
6-
6-
6-
6-
6-
6-
6-
-6
-6
-6
-6
•10
-10
•10
•10
-10
•10
•10
-10
•10
6-10
0
0
-2
-2
2,001-
101-
201-
401-
501-
601-
1,001-
2,001-
5, 001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
0-
61-
5,000
200
300
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
60
100
1
3
2
2
6
3
1
4
1
1
1
2
16
14
4
12
37
42
3
489
57
1
4
3
3
6
4
1
3
1
1
1
3
7
8
3
4
8
5
1
N/A
N/A
0
16
3
22
24
20
17
871
226
0
0
0
10
20
0
12,
50,
1.
0,
0,
0,
.00
.27
.40
.20
.80
.70
.83
.77
.63
.27
.00
.50
.03
.43
.00
.67
.43
.60
.00
.00
.00
116.
14.
16.
28.
104.
89.
35.
322.
175.
0.
2.
7.
124.
158.
59.
217.
989.
1,893.
167.
431.
178.
57
30
03
93
87
80
10
33
07
23
50
87
50
63
30
23
17
77
00
90
37
A-25
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
we 11 group
TNOIL 3
TNOIL 4
TNOIL 5
TNOIL 6
TNOIL 7
TNOIL 8
Texas-Gulf
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
Depth
range
(Mft)
Coast
1
2
3
4
5
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)
101-
201-
301-
501-
1,001-2
2,001-5
0-
61-
101-
201-
301-
200
300
400
600
,000
,000
60
100
200
300
400
Number
of
wells
22
18
13
9
4
1
14856
839
1328
474
165
Number
of
fields
N/A
N/A
N/A
N/A
N/A
N/A
227
101
83
53
27
Gas rate
per well
(Mcfd)
0.
0.
0.
0.
0.
0.
810.
657.
2,008.
789.
644.
Oil rate
per well
(Bd)
00
00
00
00
00
00
87
50
73
90
27
6,
2,
6,
3,
1,
107
135
144
176
160
143
062
147
604
690
910
.13
.87
.30
.77
.13
.23
.03
.73
.17
.67
.50
(continued)
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
TXGCOIL
6
1
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
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
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
5,001-
0-
61-
101-
201-
500
600
,000
,000
,000
60
100
200
300
400
500
600
,000
, 000
,000
Over
60
100
200
300
163
837
609
17
1
9344
2451
4857
2319
1487
1326
1330
2470
1991
379
11
920
612
1535
1162
7
11
18
11
1
571
358
569
416
300
205
142
261
182
64
7
336
235
434
341
1,233.
4,776.
4,698.
404.
373.
6,719.
6,473.
15,404.
16,282.
14,038.
16,091.
15,457.
40,689.
233,150.
134,278.
742.
1,149.
2,712.
14,052.
20,082.
37
50
57
37
03
93
43
20
30
17
33
40
43
53
20
10
20
43
73
63
2,
15,
13,
7,
6,
22,
18,
16,
18,
23,
57,
78,
27,
2,
1,
6,
7,
285
001
453
635
77
805
073
642
119
581
698
455
393
840
913
130
711
307
124
667
.90
.83
.53
.57
.30
.00
.80
.10
.00
.17
.47
.53
.60
.43
.43
.30
.90
.17
.43
.80
A-26
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
TXGCOIL 26
TXGCOIL 27
TXGCOIL 28
TXGCOIL 29
TXGCOIL 30
TXGCOIL 31
TXGCOIL 32
TXGCOIL 33
TXGCOIL 34
TXGCOIL 35
TXGCOIL 36
TXGCOIL 37
TXGCOIL 38
TXGCOIL 39
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
6-10
6-10
6-10
6-10
6-10
6-10
6-}0
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
2-6
2-6
2-6
2-6
BOE
range
(BOE/mo)
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
0- 60
61- 100
101- 200
201- 300
Number
of
wells
946
843
617
1249
1080
492
115
137
84
149
95
86
43
35
115
99
44
5
24154
2170
1406
474
93
39
IS
10
2
11809
5331
5523
2233
Number
of
fields
308
249
191
322
264
145
28
35
29
51
34
34
23
14
34
35
18
5
324
129
119
57
31
IS
8
7
3
913
559
Gas rate
per well
(Mcfd)
22,867.23
28,478.20
26,189.63
78,855.30
116,647.70
139,729.73
39,580.93
378.97
686.53
2,438.03
2,703.63
3,562.97
2,244.47
2, 716.13
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
Oil rate
per well
(Bd)
9,031.33
10,079.70
9,045.90
25,064.70
37,938.33
34,415.50
30,841.67
76.37
148.03
463.57
482.67
620.87
413.23
349.27
(continued)
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
A-27
-------
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
TXNOIL
TXNOIL
TXNOIL
Depth
range
(Mft)
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
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)
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
400
500
600
,000
, 000
,000
Over
60
100
200
300
400
500
600
,000
, 000
Number
of
wells
901
593
436
1057
313
125
6
661
520
955
583
280
250
152
248
168
Number
of
fields
313
207
149
266
147
24
5
211
195
265
187
114
78
56
87
60
Gas rate
per well
(Mcfd)
28,284
17,502
15,842
19,382
15,852
10,560
856
1,349
3,892
16,088
14,460
9,370
8,494
7,490
16,191
8,557
Oil rate
per well
(Bd)
.77
.63
.00
.53
.10
.43
.03
.63
.13
.27
.37
.90
.97
.80
.23
.73
7,
7,
6,
24,
11,
9,
1,
2,
3,
2,
2,
2,
4,
6,
728
173
238
238
729
402
463
527
981
969
401
259
868
010
645
135
.80
.20
.23
.00
.73
.20
.87
.43
.37
.90
.93
.77
.47
.53
.23
.67
(continued)
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
TXNOIL
Texas-West
TXWOIL
TXWOIL
30
31
32
33
34
35
36
37
38
39
40
41
42
1
2
6-10
6-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10+
10 +
0-2
0-2
2, 001-5
5,001-
0-
61-
101-
201-
301-
401-
501-
601-1
1,001-2
2,001-5
5,001-
0-
61-
,000
Over
60
100
200
300
400
500
600
,000
,000
,000
Over
60
100
72
12
10
8
23
13
11
10
4
26
9
11
5
3101
760
34
9
8
8
14
11
11
5
4
9
8
6
3
158
71
8,883
2,064
13
60
468
439
604
903
530
3,824
2,029
5,321
3,799
1,419
343
.70
.57
.27
.07
.20
.27
.30
.00
.90
.97
.30
.30
.30
.17
.87
6,
2,
2,
1,
281
584
4
15
55
63
64
60
22
261
142
308
436
687
820
.37
.10
.53
.40
.37
.30
.73
.23
.07
.87
.53
.77
.40
.60
.10
A-28
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
TXWOIL 3
TXWOIL 4
TXWOIL 5
TXWOIL 6
TXWOIL 7
TXWOIL 8
TXWOIL 9
TXWOIL 10
TXWOIL 11
TXWOIL 12
TXWOIL 13
TXWOIL 14
TXWOIL 15
TXWOIL 16
TXWOIL 17
TXWOIL 18
TXWOIL 19
TXWOIL 20
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
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-f
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
(BOE /mo)
101-
201-
301-
401-
501-
601-
1,001-
2,001-
0-
61-
101-
201-
301-
401-
501-
601-
1, 001-
2,001-
5, 001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
200
300
400
500
600
1,000
2, 000
5, 000
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
Number
of
wells
862
172
114
48
16
40
5
1270
9224
5740
9670
5497
4518
4577
2114
4219
3829
676
37
2295
2327
5183
2971
1704
1281
1150
3356
2540
254
240
222
147
Number
of
fields
57
28
8
7
5
8
2
0
709
462
575
363
251
180
130
180
120
39
10
391
262
413
325
237
176
153
239
173
80
19
121
53
Gas rate
per well
(Mcfd)
131.33
121.50
30.10
23.57
177.63
159.97
88.43
155,889.60
24,699.93
32,416.13
73,291.37
43,473.13
34,413.57
33,966.47
35,221.13
58,625.27
304,490.43
125,260.03
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
Oil rate
per well
(Bd)
3,461.20
1,354.40
1,270.93
632.70
277.27
869.87
198.63
75,763.03
8,859.80
14,223.07
44,562.07
41,345.07
49,462.13
62,441.07
35,724.10
104,599.53
163,734.80
64,493.47
(continued)
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
A-29
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
we 11 group
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
TXWOIL
Utah
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
Depth
range
(Mft)
35
36
37
38
39
40
41
42
43
1
2
3
4
5
6
7
8
9
10
10 +
10
10
10
+
+
+
10 +
10
10
+
+
10 +
1C
0-
0-
0-
0-
0-
0-
0-
0-
0-
0-
+
2
2
2
2
2
2
2
2
2
2
BOE
range
(BOE/mo)
101-
201-
301-
401-
501-
601-
1, 001-
2,001-
5,001-
0-
61-
131-
201-
301-
401-
501-
601-
1, 001-
2,001-
200
300
400
500
600
1,000
2, 000
5, 000
Over
60
100
200
300
400
500
600
1, 000
2, 000
5, 000
Number
of
wells
324
320
180
156
131
362
342
144
32
76
6
8
3
2
1
1
4
3
2
Number
of
fields
120
ill
81
71
64
112
104
68
14
6
1
4
3
1
2
1
5
3
3
Gas rate
per well
(Mcfd)
20,292
18,342
13,626
10,720
4,706
20,884
52,246
8,611
760
8
4
7
21
0
36
51
152
31
856
.60
.00
.33
.30
.33
.23
.17
.00
.50
.57
.47
.93
.63
.00
.63
.53
.93
.83
.60
Oil rate
per well
(Bd)
1,449
2,464
1,996
2,099
2,127
8,595
14,177
12,583
7,439
33
13
25
25
23
12
13
83
139
122
.77
.13
.57
.13
.53
.03
.37
.97
.07
.53
.80
.27
.90
.73
.67
.33
.00
.90
.70
(continued)
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
11
12
13
14
15
16
17
18
19
20
21
22
2-
2-
2-
2-
2-
2-
2-
2-
2-
2-
2-
6
6
6
6
6
6
6
6
6
6
6
6-10
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
45
49
130
140
127
88
94
228
213
76
15
7
23
22
27
34
26
22
20
31 '
22
12
8
7
38
200
860
1,836
1,956
1,629
2,320
6,241
7,149
4,250
3,792
0
.93
.50
.10
.57
.00
.30
.70
.50
.07
.83
.40
.83
18
88
483
884
1,217
1,086
1,369
5,098
8,791
6,305
2,614
3
.90
.87
.90
.27
.83
.27
.40
.07
.70
.30
.57
.47
A-30
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
UTOIL
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
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)
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
100
200
300
400
500
600
1,000
2,000
5, 000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
Number
of
wells
5
20
33
21
20
13
45
38
22
16
31
14
21
25
17
22
18
73
153
95
17
Number
of
fields
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)
19
130
594
466
477
387
1,936
3,565
4,507
50,086
24
29
112
176
183
384
284
2,551
12,665
16,031
18,867
.47
.77
.30
.60
.30
.30
.40
.70
.50
.47
.50
.23
.43
.07
.67
.73
.90
.87
.57
.90
.27
Oil rate
per well
(Bd)
7
80
199
151
211
193
934
1,251
1,680
2,283
11
21
63
155
146
226
254
1,522
5,726
6,857
3,842
.30
.20
.27
.20
.10
.13
.83
.67
.30
.70
.40
.93
.33
.47
.27
.67
.27
.87
.77
.97
.27
(continued)
A-31
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
State/
wellgroup
Virginia
VAOIL
Depth
range
(Mft)
1
0-2
BOE
range
(BOE /mo)
0-
60
Number
of
wells
50
Number
of
fields
N/A
Gas rate
per well
(Mcfd)
0
.00
Oil rate
per well
(Bd)
58
.33
West Virginia
WVOIL
WVOIL
WVOIL
WVOIL
WVOIL
Wyoming
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
WYOIL
1
2
3
4
5
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
2
2
2
2
2
2
2
2
2
2
-3
-3
-3
-3
-3
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-2
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
-6
6-10
6-10
0-
61-
101-
201-
601-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
60
100
200
300
1, 000
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
60
100
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
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
0
0
0
0
0
22
53
559
414
376
290
651
1,302
2,266
2,092
4,559
183
546
2,781
2,149
1,518
1,132
1,623
4,498
7,025
9,170
4,628
296
822
.00
.00
.00
.00
.00
.63
.20
.63
.17
.90
.60
.97
.50
.40
.27
.67
.53
.40
.33
.97
.33
.67
.37
.17
.33
.40
.70
.03
.40
3,597
608
745
675
603
973
951
2,515
2,501
2,512
1,993
1,488
4,203
3,379
2,075
1,201
385
1,025
3,772
3,880
3,697
3,576
3,746
14,127
26,723
29,795
9,108
120
398
.67
.47
.33
.20
.87
.87
.70
.70
.33
.87
.60
.63
.27
.23
.90
.67
.07
.17
.33
.47
.97
.10
.03
.73
.37
.47
.30
.90
.10
A-32
-------
APPENDIX A: GRUY ENGINEERING CORPORATION'S OIL WELLGROUPS
BY STATE (Continued)
Depth
State/ range
wellgroup (Mft)
WYOIL
25
6-10
BOE
range
(BOE/mo)
101-
200
Number
of
wells
622
Number
of
fields
158
Gas rate
per well
(Mcfd)
6,
137
.53
Oil rate
per well
(Bd)
2,263.
97
(continued)
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
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 +
201-
301-
401-
501-
601-
1,001-
2,001-
5,001-
0-
61-
101-
201-
301-
401-
501-
601-
1, 001-
2,001-
5,001-
300
400
500
600
1, 000
2,000
5,000
Over
60
100
200
300
400
500
600
1,000
2,000
5,000
Over
587
457
247
175
416
348
300
174
20
27
55
73
59
38
44
117
121
95
103
158
133
118
93
166
147
125
54
19
22
35
32
36
20
32
53
58
49
26
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
3,611.
4,035.
2,891.
2,550.
9,063.
14,483 .
27,171.
38,210.
11.
35
179
475
536
486
611
2,355
4,241
6,666
34,896
30
30
83
.97
,23
.13
.90
.57
.00
.03
.33
.10
.90
.70
.80
.20
.20
.07
.93
A-33
-------
APPENDIX B
GRUY ENGINEERING CORPORATION'S
GAS WELLGROUPS BY STATE
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE
Gruy
State/wellgroup
Alaska
AKGAS1
AKGAS2
AKGAS3
AKGAS4
AKGAS5
AKGAS6
AKGAS7
AKGAS8
AKGAS9
AKGAS10
AKGAS11
AKGAS12
AKGAS13
AKGAS14
AKGAS15
Alabama
ALGAS 1
ALGAS 2
ALGAS 3
ALGAS 4
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
10+
10+
10+
0-4
0-4
0-4
0-4
Range
(Mcfd)
34
100
167
200
334
667
1,667
134
200
334
667
1,667
334
667
1,667
0.0
20
34
67
67
133
200
333
667
1,667
167
333
667
1,667
0
667
1,667
20
33
67
100
Gas rate
per well
(Mcfd)
40
121
182
224
335
902
4,719
68
299
229
1,031
5,981
494
1,568
6,108
5
18
34
74
.07
.90
.55
.61
.07
.83
.79
.23
.97
.31
.92
.88
.77
.63
.00
.16
.12
.87
.30
dumber
of
wells
1
2
2
5
3
1
4
2
1
3
7
72
2
1
13
203
148
275
191
Number
of
fields
1
3
3
4
1
1
3
3
1
3
4
8
3
1
5
31
30
37
40
Revised 1993
Number
of
wells
1
3
3
7
4
1
5
3
1
4
9
95
3
1
17
452
329
611
425
Number
of
fields
1
5
5
6
1
1
4
5
1
4
5
11
5
1
7
69
67
82
89
1993
Total gas
production
(Mcdf)
40
365
547
1,572
1,340
902
23,598
204
299
917
9,287
568,278
1,484
1,468
103,836
2,333
5,962
21,304
31,578
.07
.70
.65
.29
.27
.83
.96
.70
.97
.24
.27
.30
.30
.63
.04
.70
.46
.13
.46
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
ALGAS
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10+
10+
10+
Range
(Mcfd)
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
34
134
200
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
67
167
333
Gas rate
per well
(Mcfd)
94
141
174
256
444
740
2,231
0
13
42
71
99
136
170
233
456
847
1,799
45
17
74
.52
.98
.39
.60
.45
.36
.05
.93
.23
.09
.10
.15
.09
.26
.31
.88
.83
.49
.43
.90
.53
Number
of
wells
95
95
42
115
79
20
60
4
5
9
14
12
11
6
25
27
19
5
1
1
4
Number
of
fields
37
31
23
32
27
15
9
5
6
7
9
11
9
5
13
13
12
5
1
2
5
Revised 1993
Number
of
wells
211
211
93
259
174
37
126
26
11
20
31
27
24
13
56
60
42
11
2
2
9
Number
of
fields
82
69
51
71
60
33
20
11
13
16
20
25
20
11
29
29
27
11
2
4
11
1993
Total gas
production
(Mcdf)
19,943.42
29,957.19
16,218.68
66,458.72
77,333.60
27,393.26
281,112.23
24.27
145.57
841.70
2,204.10
2,677.13
3,266.11
2,213.39
13,065.10
27,412.52
35,608.71
19,794.35
90.87
35.80
670.73
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
W
I
oo
ALGAS
ALGAS
ALGAS
Arkansas
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
ARGAS
26
27
28
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Depth
Range
(Mft)
10+
10+
10 +
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
Range
(Mcfd)
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
Gas rate
per well
(Mcfd)
176.07
644.75
3,677.65
6.95
22.19
42.24
69.96
94.19
131.45
143.00
226.13
390.89
745.22
1,359.01
7.95
21.71
41.86
73.96
105.05
132.60
Number
of
wells
1
15
44
276
100
209
146
76
57
30
87
79
36
3
157
111
251
164
150
91
Number
of
fields
1
8
10
61
48
56
47
33
30
18
35
29
17
4
35
35
43
38
39
31
Revised 1993
Number
of
wells
2
33
98
311
113
237
165
86
65
34
98
89
41
3
178
126
284
186
170
103
Number
of
fields
2
18
22
69
54
64
53
37
34
20
39
33
19
4
40
40
49
43
44
35
1993
Total gas
production
(Mcdf)
' 352.13
21,276.64
360,410.00
2,161.64
2,507.66
10,011.72
11,542.80
8,100.71
8,544.08
4,862.00
22,160.54
34,788.97
30,554.07
4,077.03
1,415.57
2,734.92
11,887.19
13,756.40
17,858.58
13,657.50
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
ARGAS 18
ARGAS 19
ARGAS 20
ARGAS 21
ARGAS 22
ARGAS 23
Arizona
w AZGAS 1
JL AZGAS 2
AZGAS 3
AZGAS 4
AZGAS 5
California-Northern
CACNGAS 1
CACNGAS 2
CACNGAS 3
CACNGAS 4
CACNGAS 5
CACNGAS 6
CACNGAS 7
CACNGAS 8
Depth
Range
(Mft)
4-10
4-10
4-10
4-10
4-10
10+
0-4
4-10
4-10
4-10
4-10
& Coastal
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
Range
(Mcfd)
167
200
334
667
1,667
200
34
0.0
67
667
1,667
0.0
20
34
67
100
134
167
200
200
333
667
1,667
0.00
333
67
20
100
1,667
0.00
20
33
67
100
133
167
200
333
Gas rate
per well
(Mcfd)
156
231
422
756
2,018
293
30
20
30
1,025
2,641
5
21
43
75
90
144
160
230
.60
.68
.80
.84
.26
.80
.83
.00
.00
.23
.68
.41
.77
.91
.29
.36
.56
.62
.68
Number
of
wells
83
189
167
95
17
1
1
1
1
1
2
28
18
41
26
27
14
6
17
Number
of
fields
31
36
32
26
12
1
1
1
1
2
1
15
13
21
13
15
11
6
10
Revised 1993
Number
of
wells
94
214
189
108
19
1
1
2
1
1
2
16
14
31
20
20
11
5
13
Number
of
fields
35
41
36
30
13
1
1
1
1
2
1
11
10
16
10
11
9
5
8
1993
Total gas
production
(Mcdf )
14,720.
49,580.
79,909.
81,738.
38,347.
293.
30.
40.
30.
1,025.
5,283.
86.
304.
1,361.
1,505.
1,807.
1,590.
803.
2,998.
29
37
61
57
03
80
83
00
00
23
37
59
79
28
72
14
13
08
87
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
CACNGAS
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Depth
Range
(Mft)
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10+
10+
10+
10+
10+
10+
10+
Range
(Mcfd)
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
Gas rate
per well
(Mcfd)
339
617
2,313
5
21
43
72
101
138
168
240
436
870
2,380
10
16
25
93
89
106
152
.98
.42
.29
.52
.40
.83
.94
.83
.36
.00
.27
.98
.10
.39
.10
.11
.08
.67
.73
.83
.22
Number
of
wells
23
5
3
107
53
115
108
89
72
61
166
172
61
20
1
3
3
1
6
2
2
Number
of
fields
13
6
4
33
26
36
36
28
27
24
43
37
27
14
1
3
4
1
5
1
1
Revised 1993
Number
of
wells
17
6
2
73
38
87
82
70
55
46
126
130
46
17
1
2
2
' 1
5
2
2
Number
of
fields
10
5
3
25
20
27
27
21
21
18
33
28
20
11
1
2
3
1
4
1
1
1993
Total gas
production
(Mcdf )
5,779.61
3,704.52
4,626.58
402.61
813.32
3,813.30
5,981.04
7,128.10
7,609.99
7,728.13
30,274.51
56,808.01
40,024.73
40,466.69
10.10
32.22
50.16
93.67
448.67
213.67
304.43
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
Depth
Range
State/wellgroup (Mft)
CACNGAS 30
CACNGAS 31
CACNGAS 32
CACNGAS 33
10+
10+
10+
10+ 1
Range
(Mcfd)
200
334
667
,667
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
249.37
457.30
965.03
3,921.66
N imber
of
-.veils
8
5
8
6
Number
of
fields
3
1
1
3
Revised 1993
Number
of
wells
6
4
6
5
Number
of
fields
2
1
1
3
1993
Total gas
production
(Mcdf )
1,496.23
1,829.20
5,790.20
19,608.28
California- Los Angeles Basin
CALAGAS 1
CALAGAS 2
CALAGAS 3
California-San
CASJGAS 1
CASJGAS 2
CASJGAS 3
CASJGAS 4
CASJGAS 5
CASJGAS 6
CASJGAS 7
CASJGAS 8
CASJGAS 9
CASJGAS 10
CASJGAS 11
CASJGAS 12
0-4
0-4
0-4
Jose Basin
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4 1
4-10
4-10
0.0
34
67
0.0
20
34
67
134
167
200
334
667
,667
0.0
20
20
67
100
20
33
67
100
167
200
333
667
1,667
0.00
20
33
10.23
47.57
92.40
6.99
22.57
49.74
85.02
137.03
181.07
250.08
457.42
842.90
2,751.10
4.46
25.58
1
1
1
33
12
14
6
1
1
4
7
11
1
8
2
1
1
1
9
6
5
5
1
1
1
1
1
1
6
1
1
1
1
25
9
11
5
1
1
3
5
• 8
1
6
2
1
1
1
7
5
4
4
1
1
1
1
1
1
5
1
10.23
47.57
92.40
174.72
203.15
547.15
425.08
137.03
181.07
750.25
2,287.12
6,743.18
2,751.10
26.75
51.17
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
CASJGAS
Colorado
COGAS 1
COGAS 2
COGAS 3
COGAS 4
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Depth
Range
(Mft)
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10+
10+
10+
10+
10+
10+
10+
0-4
0-4
0-4
0-4
Range
(Mcfd)
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
0.0
20
34
67
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
20
33
67
100
Gas rate
per well
(Mcfd)
42
86
119
135
172
170
425
1,037
1,008
19
10
13
23
27
73
39
8
25
46
78
.17
.92
.60
.67
.10
.60
.40
.45
.98
.13
.80
.19
.05
.58
.40
.83
.52
.49
.25
.33
"lumber
of
1
2
2
1
1
3
1
5
2
1
1
6
2
2
1
4
345
210
410
257
Number
of
fields
1
3
3
1
2
4
2
5
2
1
1
1
1
1
1
1
64
56
65
45
Revised 1993
Number
of
wells
1
2
2
1
1
2
1
4
2
1
1
5
2
2
1
3
384
217
424
266
Number
of
fields
1
3
3
1
2
3
2
4
2
1
1
1
1
1
1
1
66
58
67
47
1993
Total gas
production
(Mcdf )
42.17
173.83
239.20
135.67
172.10
341.20
425.40
4,149.81
2,017.97
19.13
10.80
65.94
46.10
55.17
73.40
119.50
3,270.46
5,530.95
19,609.83
20,836.32
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wel
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
.Igroup
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
'4-10
4-10
4-10
4-10
10+
10+
10+
10+
100
134
167
200
334
667
0.
20
34
67
100
134
167
200
334
667
1,667
0
20
34
100
Range
(Mcfd)
133
167
200
333
667
1,667
.0 20
33
6.7
100
133
167
200
333
667
1,667
0.00
.0 20
33
67
133
Gas rate
per well
(Mcfd)
104.46
143.59
148.79
230.25
351.41
514.47
8.88
22.01
37.65
63.93
92.17
110.05
125.16
179.37
360.27
622.57
1,489.77
8.18
17.40
38.07
130.97
Number
of
wells
118
186
34
161
70
11
444
411
1,271
771
437
243
198
349
161
54
4
4
2
2
1
Number
of
fields
34
24
15
21
18
6
89
76
109
69
43
32
36
49
41
17
5
4
3 *
3
1
Revised 1993
Number
of
wells
122
192
30
166
72
14
459
425
1292
797
452
251
205
361
166
56
4
• 4
2
2
1
Number
of
fields
35
25
15
22
19
6
92
79
113
71
44
33
37
51
42
18
5
4
3
3
1
1993
Total gas
production
(Mcdf )
12,744
27,568
4,463
38,221
25,301
7,202
4,074
9,354
48,638
50,953
41,662
27,621
25,656
64,753
59,804
34,863
5,959
32
34
76
130
.42
.69
.62
.04
.86
.62
.28
.24
.40
.35
.78
.95
.79
.57
.44
.73
.07
.70
.80
.13
.97
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State /wellgroup
COGAS
COGAS
COGAS
COGAS
COGAS
COGAS
Illinois
ILGAS
ILGAS
ILGAS
ILGAS
ILGAS
ILGAS
Indiana
INGAS
INGAS
INGAS
Kansas
KSGAS
KSGAS
KSGAS
26
27
28
29
30
31
1
2
3
4
5
6
1
2
3
1
2
3
Depth
Range
(Mft)
10+
10+
10+
10+
10+
10+
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-4
0-4
0-4
Range
(Mcfd)
134
167
200
334
667
1,667
0.0
20
0
100
200
667
0.0
20
34
0.0
20
34
167
200
333
667
1,667
0.00
20
33
67
133
333
1,667
20
33
80
20
33
67
Gas rate
per well
(Mcfd)
164
187
92
448
684
2,910
5
27
53
110
208
374
0
22
48
7
23
42
.23
.07
.77
.20
.12
.87
.39
.76
.29
.86
.35
.13
.89
.20
.03
.72
.03
.86
Number
of
wells
1
1
1
1
2
2
263
16
10
4
2
1
1,291
3
1
1,424
718
1,480
Number
of
fields
1
1
1
1
3
1
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
290
180
189
Revised 1993
Number
of
wells
1
1
1
1
2
2
341
21
13
5
3
1
1323
3
1
1549
784
1617
1993
Number Total gas
of production
fields (Mcdf)
1 164.
1 187.
1 92.
1 448.
3 1,368.
1 5,821.
1,836.
582.
692.
554.
625.
374.
1,172.
66.
48.
317 11,956.
197 18,056.
206 69,311.
23
07
77
20
23
73
60
88
77
29
05
13
05
60
03
02
97
32
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellqroup
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
W KSGAS
1
£ KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
KSGAS
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
Range
(Mcfd)
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
71
97
119
148
214
392
786
2,016
9
24
43
73
105
134
169
217
394
807
1,808
.56
.09
.36
.06
.87
.16
.22
.29
.27
.32
.85
.45
.39
.83
.37
.99
.59
.93
.96
Number
of
wells
1,071
901
790
663
1,595
1,082
165
4
791
493
707
323
223
109
71
180
124
70
15
Number
of
fields
110
66
48
39
50
30
14
5
241
184
240
137
112
67
56
92
67
35
12
Revised 1993
Number
of
wells
1170
984
863
724
1749
1182
180
4
864
539
772
353
245
119
78
197
135
76
16
Number
of
fields
120
72
52
43
55
33
15
5
263
201
262
150
123
73
62
101
73
38
13
1993
Total gas
production
(Mcdf)
83,
95,
103,
107,
375,
463,
141,
8,
8,
13,
33,
25,
25,
16,
13,
42,
53,
61,
28,
725.06
534.71
004.26
196.88
806.08
528.76
519.31
065.17
007.42
109.33
853.89
926.12
821.17
044.95
210.60
943.63
270.20
402.72
943.32
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
Kentucky
KYGAS 1
KYGAS 2
KYGAS 3
KYGAS 4
KYGAS 5
KYGAS 6
tfl KYGAS 7
1
^ Louisiana-North
LANGAS 1
LANGAS 2
LANGAS 3
LANGAS 4
LANGAS 5
LANGAS 6
LANGAS 7
LANGAS 8
LANGAS 9
LANGAS 10
LANGAS 11
LANGAS 12
Depth
Range
(Mft)
0-2
0-2
0-2
0-2
0-2
0-2
0-2
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
Range
(Mcfd)
0.0
34
67
100
200
334
667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
67
100
133
333
667
1,667
20
33
67
100
133
167
200
333
667
1,667
0.00
20
Gas rate
per well
(Mcfd)
7
41
80
119
217
551
1,356
5
23
36
55
84
101
118
208
346
528
1,222
7
.09
.82
.61
.20
.15
.40
.05
.88
.26
.80
.91
.01
.67
.77
.80
.10
.84
.75
.48
Number
of
wells
9,884
884
159
139
121
45
17
8,290
408
257
114
65
36
36
56
24
21
2
222
Number
of
fields
N/A
N/A
N/A
N/A
N/A
N/A
N/A
50
34
56
44
32
24
23
27
15
16
3
66
Revised 1993
Number
of
wells
11294
1024
150
159
139
51
19
7576
373
235
104
59
33
33
51
22
19
2
203
Number
of
fields
46
31
51
40
29
22
21
25
14
14
3
60
1993
Total gas
production
(Mcdf )
80,089
42,820
12,091
18,952
30,184
28,121
25,764
44,537
8,675
8,649
5,814
4,956
3,354
3,919
10,648
7,614
10,047
2,445
1,518
.36
.42
.23
.46
.52
.25
.97
.38
.78
.13
.69
.51
.97
.27
.56
.29
.98
.50
.69
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State /wellgroup
tx)
I
M
to
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
LANGAS
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
Depth
Range
(Mft)
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
10+
10+
10+
10+
10+
10+
10+
10+
10+
Range
(Mcfd)
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
20.86
38.99
68.10
98.36
124.53
153.83
212.52
403.91
779.52
2,860.46
6.45
14.52
28.44
49.59
92.79
107.70
114.10
184.16
330.93
846.97
2,135.84
Number
of
wells
127
250
207
136
116
100
274
275
188
89
29
10
26
26
13
24
11
63
51
59
40
Number
of
fields
53
70
60
56
49
46
67
64
52
24
17
9
18
19
11
16
10
24
27
21
15
Revised 1993
Number
of
wells
116
228
189
124
106
91
250
251
172
81
27
9
24
24
12
22
10
58
47
54
37
Number
of
fields
48
64
55
51
45
42
61
58
48
22
16
8
17
18
10
15
9
22
25
19
14
1993
Total gas
production
(Mcdf)
2,419.22
8,888.78
12,871.23
12,196.62
13,200.62
13,998.17
53,129.01
101,380.79
134,077.29
231,697.47
174.17
130.65
682.68
1,190.12
1,113.54
2,369.49
1,141.00
10,681.39
15,553.77
45,736.44
79,026.11
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
Depth
Range
(Mft)
Range
(Mcfd)
Gas rate
per well
(Mcfd)
'lumber
of
wells
Number
of
fields
Revised 1993
Number
of
wells
Number
of
fields
1993
Total gas
production
(Mcdf)
Louisiana-South
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
W LASGAS
1
H1 LASGAS
CO
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
LASGAS
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
4
16
33
66
81
96
120
185
344
743
1,246
2
14
30
40
62
90
112
169
303
.94
.82
.49
.55
.85
.09
.69
.65
.10
.76
.82
.96
.59
.62
.61
.59
.21
.42
.85
.26
11
7
13
9
11
5
10
14
24
30
13
40
23
42
62
39
36
28
100
157
12
7
8
9
10
6
10
13
19
16
13
34
23
35
47
34
32
24
76
114
10
6
12
8
10
5
9
13
22
27
12
37
21
38
57
36
33
26
91
143
11
6
7
8
9
6
9
12
17
14
12
31
21
32
43
31
29
22
69
104
49.39
100.91
401.94
532.39
818.55
480.47
1,086.21
2,413.45
7,570.26
20,081.40
14,961.88
109.40
306.33
1,163.73
2,314.66
2,253.08
2,977.06
2,922.93
15,456.35
43,365.71
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
LASGAS 21
LASGAS 22
LASGAS 23
LASGAS 24
LASGAS 25
LASGAS 26
LASGAS 27
0) LASGAS 28
1
H» LASGAS 29
LASGAS 30
LASGAS 31
LASGAS 32
LASGAS 33
Michigan
MIGAS 1
MIGAS 2
MIGAS 3
MIGAS 4
MIGAS 5
MIGAS 6
MIGAS 7
Depth
Range
(Mft)
4-10
4-10
10+
10+
10+
10+
10 +
10 +
10+
10+
10+
10 +
10+
0-4
0-4
0-4
0-4
0-4
0-4
0-4
Range
(Mcfd)
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
Gas rate
per well
(Mcfd)
692.
1,918.
2.
12.
21.
50.
71.
96.
112.
164.
342.
781.
3,612.
4.
11.
24.
47.
67.
85.
102.
16
26
55
22
88
37
77
13
88
12
46
98
62
77
73
47
46
71
20
70
Number
of
wells
167
67
75
21
71
58
52
59
44
177
325
486
538
89
69
89
77
62
42
47
Number
of
fields
112
48
60
20
63
54
47
54
40
123
186
205
195
21
21
24
18
20
15
13
Revised 1993
Number
of
wells
153
61
69
19
65
53
48
54
40
162
297
444
508
287
222
287
248
200
135
151
Number
of
fields
103
44
55
18
58
49
43
49
36
113
170
187
178
68
68
77
58
65
48
42
1993
Total gas
production
(Mcdf)
105,
117,
1,
2,
3,
5,
4,
26,
101,
347,
1,835,
1,
2,
7,
11,
13,
11,
15.
899.88
014.15
175.78
232.25
422.13
669.52
444.83
191.20
515.18
586.70
709.58
197.71
212.51
367.71
605.12
024.08
769.37
541.83
501.79
507.06
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
U MIGAS
1
H-1 MIGAS
Ul
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
MIGAS
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10+
10+
10+
10+
10+
10+
Range
(Mcfd)
200
334
667
1,667
0.0
34
67
200
334
667
1,667
34
67
167
334
667
1,667
333
667
1,667
0.00
20
67
100
333
667
1,667
0.00
67
100
200
667
1,667
0.00
Gas rate
per well
(Mcfd)
144
279
586
1,773
21
69
68
10
250
244
1,196
53
77
116
77
618
2,190
.50
.71
.05
.05
.49
.85
.88
.89
.68
.70
.94
.73
.92
.78
.92
.42
.33
Number
of
wells
109
91
146
94
5
2
2
7
12
10
12
2
2
2
2
5
7
Number
of
fields
25
29
36
24
3
2
2
4
4
5
4
2
2
2
2
3
4
Revised 1993
Number
of
wells
351
293
470
306
16
6
6
23
39
32
39
6
6
6
6
16
23
Number
of
fields
81
93
116
77
10
6
6
13
13
16
13
6
6
6
6
10
13
1993
Total gas
production
(Mcdf)
50,720.79
81,955.86
275,441.35
542,554.82
343.89
419.10
413.30
250.48
9,776.33
7,830.29
46,680.73
322.40
467.50
700.70
467.50
9,894.72
50,377.67
Mississippi
MSGAS
MSGAS
MSGAS
1
2
3
0-4
0-4
0-4
0.0
20
34
20
33
67
5
19
35
.64
.13
.05
19
15
10
10
12
8
16
11
7
7
9
6
90.22
210.44
245.37
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
tx) MSGAS
1
H-1 MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10+
10+
Range
(Mcfd)
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
Gas rate
per well
(Mcfd)
68
88
108
151
187
317
629
2,446
6
18
40
58
85
100
136
189
337
631
977
3
6
.19
.60
.64
.49
.72
.41
.15
.34
.11
.59
.37
.71
.98
.36
.24
.30
.94
.51
.54
.18
.76
Number
of
wells
22
23
16
6
32
30
23
6
25
11
32
23
22
18
10
18
23
11
7
21
9
Number
of
fields
11
13
13
6
15
15
12
4
11
6
14
10
9
12
8
8
8
9
2
11
9
Revised 1993
Number
of
wells
16
17
12
4
24
22
17
4
19
8
24
17
16
13
7
13
17
8
5
16
10
Number
of
fields
8
10
10
4
11
11
9
3
8
4
11
7
7
9
6
6
6
7
1
8
7
1993
Total gas
production
(Mcdf)
1,091.10
1,506.22
1,303.68
605.96
4,505.23
6,983.07
10,695.49
9,785.38
116.18
148.73
968.98
998.12
1,375.61
1,304.74
953.68
2,460.95
5,745.06
5,052.05
4,887.69
50.90
67.63
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
MSGAS
Cd MSGAS
1
|-i MSGAS
-J
Montana
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
25
26
27
28
29
30
31
32
33
1
2
3
4
5
6
7
8
9
10
11
Depth
Range
(Mft)
10+
10+
10+
10+
10+
10+
10+
10+
10+
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
Range
(Mcfd)
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
21
40
81
97
127
180
341
788
3,862
9
22
40
73
107
133
164
214
400
727
874
.81
.88
.20
.27
.61
.58
.98
.39
.31
.11
.90
.04
.20
.99
.07
.55
.61
.44
.03
.56
Number
of
wells
10
9
11
13
9
39
51
77
89
1,184
585
520
169
82
49
40
48
36
13
4
Number
of
fields
10
7
7
11
7
22
30
32
36
95
72
77
43
29
23
16
17
14
4
3
Revised 1993
Number
of
wells
7
7
8
10
7
29
38
57
66
1243
614
546
177
86
51
42
50
38
14
4
Number
of
fields
7
5
5
8
5
16
22
24
27
100
76
81
45
30
24
17
18
15
4
3
1993
Total gas
production
(Mcdf )
152.69
286.14
649.58
972.74
893.28
5,236.78
12,995.06
44,938.45
254,912.17
11,328.52
14,059.17
21,864.19
12,956.05
9,286.95
6,786.43
6,911.14
10,730.59
15,216.75
10,178.43
3,498.23
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
W
I
M
CO
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
MTGAS
12
13
14
15
16
17
18
19
20
21
22
Depth
Range
(Mft)
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
Range
(Mcfd)
0.0
20
34
67
100
134
167
200
334
0.0
34
20
33
67
100
133
167
200
333
667
20
67
Gas rate
per well
(Mcfd}
4.53
23.98
45.78
68.29
106.33
135.10
163.45
143.48
579.03
10.83
37.93
dumber
of
wells
4
2
9
3
5
3
2
2
1
1
1
Number
of
fields
4
3
3
3
3
3
1
3
1
1
1
Revised 1993
Number
of
wells
4
2
9
3
7
3
2
2
1
1
1
Number
of
fields
4
3
3
3
3
3
1
3
1
1
1
1993
Total gas
production
(Mcdf)
18.13
47.97
412.00
204.87
744.33
405.30
326.90
286.97
579.03
10.83
37.93
North Dakota
NDGAS
NDGAS
NDGAS
NDGAS
NDGAS
NDGAS
NDGAS
NDGAS
NDGAS
1
2
3
4
5
6
7
8
9
0-4
0-4
0-4
0-4
10+
10+
10+
10+
10+
0.0
20
34
67
0.0
200
334
667
1,667
20
33
67
100
20
333
667
1,667
0.00
7.95
25.59
42.90
69.43
3.16
48.33
146.81
478.33
2,250.43
54
5
2
1
3
1
3
1
3
3
1
1
1
4
1
4
2
4
77
7
3
1
4
3
4
1
4
4
1
2
1
5
1
5
2
5
611.77
179.11
128.70
69.43
12.62
145.00
587.24
478.33
9,001.73
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
Nebraska
NEGAS
NEGAS
NEGAS
1
2
3
Depth
Range
(Mft)
4-10
4-10
4-10
Range
(Mcfd)
20
34
67
33
67
100
Gas rate
per well
(Mcfd)
13
40
37
.99
.93
.93
lumber
of
wells
6
4
2
Number
of
fields
4
3
3
Revised 1993
Number
of
wells
30
20
10
Number
of
fields
20
15
15
1993
Total gas
production
(Mcdf )
419.83
818.67
379.33
New Mexico
NMGAS
NMGAS
UJ NMGAS
1
J-J NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
7
22
38
65
95
121
150
214
358
740
2,844
6
20
39
65
89
.82
.10
.97
.54
.90
.20
.13
.76
.24
.49
.17
.76
.21
.24
.70
.94
2,306
1,126
1,486
635
355
241
138
289
155
59
38
1,151
796
1,908
1,531
1,206
64
43
43
38
37
29
25
30
22
14
4
93
60
82
61
55
3694
1804
2380
1017
569
386
221
463
248
95
61
1844
1275
3056
2449
1932
103
69
69
61
59
46
40
48
35
23
6
149
96
131
98
88
28,885.87
39,867.17
92,744.99
66,656.42
54,566.51
46,781.54
33,178.35
99,435.26
88,842.61
70,346.91
173,494.49
12,471.91
25,766.53
119,918.32
160,888.64
173,764.07
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
tO NMGAS
1
*J NMGAS
O
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
NMGAS
New York
NYGAS
NYGAS
NYGAS
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
1
2
3
Depth
Range
(Mft)
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
0-3
0-3
0-3
Range
(Mcfd)
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
167
200
333
667
1, 667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
Gas rate
per well
(Mcfd)
113
135
182
318
750
2,735
5
20
41
68
96
116
152
220
395
863
2,245
6
30
46
.46
.86
.92
.43
.05
.30
.21
.37
.01
.94
.16
.06
.41
.45
.22
.73
.17
.00
.40
.60
Number
of
wells
842
561
953
395
99
52
122
56
109
98
67
60
51
129
172
132
58
4,850
168
139
Number
of
fields
37
41
59
43
33
11
71
42
54
60
46
44
35
67
81
63
30
N/A
N/A
N/A
Revised 1993
Number
of
wells
1349
899
1526
633
159
83
195
90
175
157
107
96
82
207
276
211
93
5391
187
155
Number
of
fields
59
66
94
69
53
18
113
68
87
96
73
70
56
108
130
101
48
1993
Total gas
production
(Mcdf )
153,051
122,134
279, 137
201,565
119,257
227,030
1,015
1,833
7,176
10,823
10,289
11,141
12,497
45,633
109,080
182,246
208,800
32,334
5,684
7,222
.05
.41
.16
.31
.76
.01
.17
.70
.07
.60
.03
.49
.44
.12
.60
.19
.45
.25
.73
.41
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
W
1
to
i — i
NYGAS
NYGAS
NYGAS
NYGAS
Ohio
OHGAS
OHGAS
OHGAS
OHGAS
OHGAS
OHGAS
OHGAS
Oklahoma
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
4
5
6
7
1
2
3
4
5
6
7
1
2
3
4
5
6
7
8
Depth
Range
(Mft)
0-3
0-3
0-3
0-3
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
Range
(Mcfd)
67
100
200
667
0.0
20
34
67
100
200
667
0.0
20
34
67
100
134
167
200
100
133
333
1,667
20
33
67
100
133
333
1,667
20
33
67
100
133
167
200
333
Gas rate
per well
(Mcfd)
72
127
282
853
4
23
48
74
130
288
880
5
16
30
52
78
100
126
172
.41
.67
.72
.38
.78
.62
.01
.27
.67
.46
.18
.39
.35
.36
.65
.12
.10
.05
.67
Number
of
wells
95
66
27
8
28,300
3,789
887
609
424
174
51
2,959
1,169
1,537
895
523
371
249
520
Number
of
fields
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
466
301
329
220
129
87
56
106
Revised 1993
Number Number
of of
wells fields
106
73
30
9
28587
3827
896
615
428
176
52
3114 492
1236 318
1624 348
946 233
553 136
392 92
263 59
550 112
1993
Total gas
production
(Mcdf )
7,675.29
9,320.18
8,481.67
7,680.41
136,735.83
90,383.96
43,018.74
45,675.18
55,928.56
50,768.82
45,769.41
16,772.70
20,207.56
49,305.89
49,806.14
43,200.93
39,239.24
33,151.38
94,968.89
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State /wellgroup
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
tfl OKGAS
1
W OKGAS
NJ
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
OKGAS
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Depth
Range
(Mft)
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
10 +
10 +
10 +
10 +
10+
Range
(Mcfd)
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
Gas rate
per well
(Mcfd)
306.
597.
1,373 .
6.
16.
30.
52.
73.
96,
120,
165,
297
610
1,832
4
13
27
47
68
91
112
66
25
57
33
,17
,46
.75
.20
.28
.39
.91
.53
.86
.28
.75
.87
.03
.30
.39
.81
17
Number
of
wells
356
100
11
1,394
1,113
2,363
1,818
1,293
870
698
1,629
1,295
829
210
245
247
536
428
323
279
247
Number
of
fields
78
23
7
285
250
337
284
233
180
162
240
211
141
47
88
84
135
117
90
91
83
Revised 1993
Number
of
wells
376
106
12
1473
1176
2497
1921
1367
920
738
1725
1369
876
222
259
261
566
452
341
295
261
Number
of
fields
82
24
8
301
264
356
300
246
190
171
254
223
149
50
93
89
143
124
95
96
88
1993
Total gas
production
(Mcdf )
115,305.26
63,308.57
16,482.87
9,320.09
19,011.26
76,051.91
101,333.91
100,064.44
88,578.20
88,850.30
286,193.81
407,322.50
535,113.28
406,767.22
1,231.15
3,619.45
15,300.55
21,378.93
23,321.44
27,084.81
29,275.96
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State /wellgroup
OKGAS
OKGAS
OKGAS
OKGAS
Oregon
ORGAS
ORGAS
ro
1 ORGAS
NJ
^ ORGAS
ORGAS
ORGAS
ORGAS
ORGAS
30
31
32
33
1
2
3
4
5
6
7
8
Depth
Range
(Mft)
10 +
10 +
10 +
10 +
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
Range
(Mcfd)
200
334
667
1,667
20
34
100
134
200
334
667
67
333
667
1,667
0.00
33
67
133
167
333
667
1,667
100
Gas rate
per well
(Mcfd)
162
300
678
2,394
28
65
116
162
213
392
996
95
.21
.85
.81
.68
.20
.90
.82
.73
.22
.94
.68
.07
' 'umber
of
veils
649
833
810
547
1
1
2
1
5
4
4
1
Number
of
fields
124
131
107
86
1
1
1
1
1
1
1
1
Revised 1993
Number
of
wells
686
880
866
579
1
2
2
1
6
4
4
1
1993
Number Total gas
of production
fields (Mcdf)
131 111
138 264
113 587
,278.89
,747.52
,852.20
91 1,386,517.3
6
1
1
1
1
1 1
1 1
1 3
1
28.20
131.80
233.63
162.73
,279.32
,571.77
,986.73
95.07
Pennsylvania
PAGAS
PAGAS
PAGAS
PAGAS
PAGAS
PAGAS
1
2
3
4
5
6
0-4
0-4
0-4
0-4
0-4
0-4
0.0
20
34
67
134
200
20
33
67
100
167
333
5
24
46
89
157
345
.75
.76
.76
.33
.29
.63
23,975
2,301
1,660
516
359
148
N/A
N/A
N/A
N/A
N/A
N/A
25709
2467
1780
553
386
159
147
61
83
49
60
54
,934.68
,087.79
,238.16
,401.62
,714.43
,955.66
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
PAGAS 7
South Dakota
SDGAS 1
SDGAS 2
SDGAS 3
SDGAS 4
SDGAS 5
SDGAS 6
Tennessee
TNGAS 1
TNGAS 2
TNGAS 3
TNGAS 4
TNGAS 5
TNGAS 6
Texas -Gulf Coast
TXGCGAS 1
TXGCGAS 2
TXGCGAS 3
TXGCGAS 4
TXGCGAS 5
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
4-10
0-2
0-2
0-2
0-2
0-2
0-2
0-4
0-4
0-4
0-4
0-4
Range
(Mcfd)
667
0.0
20
34
67
100
20
0.0
20
34
67
134
334
0.0
20
34
67
100
1,667
20
33
67
100
133
33
20
33
67
100
167
667
20
33
67
100
133
Gas rate
per well
(Mcfd)
1,063.
10.
27.
52.
72.
120.
25,
3,
27
40
77
164
440
6
21
40
66
93
94
77
.64
.23
.63
.33
.10
.94
.86
.35
.66
.16
.47
.61
.47
.17
.48
.24
Number
of
wells
43
14
5
28
3
1
1
560
15
11
7
3
1
722
348
566
384
242
Number
of
fields
N/A
3
3
3
1
1
1
N/A
N/A
N/A
N/A
N/A
N/A
328
211
293
227
150
Revised 1993
Number Number
of of
wells fields
46
10 2
4 2
20 2
2 1
1 1
1 1
582
16
11
7
3
1
661 300
319 193
518 268
351 207
220 138
1993
Total gas
production
(Mcdf )
48, 941
107
110
1,044
145
120
25
2,292
445
443
543
492
440
4,369
6,848
20,807
23,334
20,513
.25
.69
.56
.60
.27
.33
.10
.87
.72
.80
.63
.47
.47
.22
.57
.10
.55
.79
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
w
Gruy
State/ wellgroup
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
TXGCGAS
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
10+
10+
Range
(Mcfd)
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
Gas rate
per well
(Mcfd)
117.
148.
210.
391.
704.
7,122.
7.
20.
40.
69.
95.
124.
155.
217.
387.
804.
2,232.
6.
19.
40.
71.
98
55
55
74
65
61
23
99
10
98
90
85
43
77
37
99
76
73
69
21
14
lumber
of
wells
190
139
282
119
39
15
1,493
884
1,810
1,330
963
853
721
1,837
1,998
1,558
539
206
145
381
336
Number
of
fields
1?8
94
150
74
25
12
582
386
648
542
480
436
351
692
656
492
191
149
98
225
187
Revised 1993
Number
of
wells
174
127
258
109
34
14
1367
809
1657
1217
881
783
660
1681
1829
1426
493
189
133
351
308
Number
of
fields
117
86
137
68
23
11
533
353
593
496
439
399
321
633
601
450
175
137
90
206
171
1993
Total gas
production
(Mcdf )
20,528.61
18,866.35
54, 323.12
42,699.76
23,958.00
99,716.49
9,885.28
16,982.14
66,439.96
85,165.84
84,486.31
97,754.72
102,586.06
366,067.63
708,494.06
1,147,911.69
1,100,751.34
1,271.77
2,619.00
14,114.56
21,912.31
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State /wellgroup
TXGCGAS 27
TXGCGAS 28
TXGCGAS 29
TXGCGAS 30
TXGCGAS 31
TXGCGAS 32
TXGCGAS 33
tfl Texas -North
1
10 TXNGAS 1
TXNGAS 2
TXNGAS 3
TXNGAS 4
TXNGAS 5
TXNGAS 6
TXNGAS 7
TXNGAS 8
TXNGAS 9
TXNGAS 10
TXNGAS 11
TXNGAS 12
Depth
Range
(Mft)
10 +
10 +
10 +
10 +
10 +
10 +
10 +
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
Range
(Mcfd)
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
0.0
20
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
20
33
Gas rate
per well
(Mcfd)
99
131
159
228
411
868
3,066
8
24
44
78
110
143
175
245
423
835
9
24
.40
.87
.80
.37
.79
.09
.41
.21
.27
.49
.28
.26
.11
.42
.36
.04
.42
.06
.08
Number
of
wells
325
292
243
696
884
828
514
4,337
1,512
1,776
951
500
373
273
613
358
78
1,779
1,083
Number
of
fields
159
160
130
282
291
280
170
596
342
351
179
84
59
39
51
28
10
439
307
Revised 1993
Number
of
wells
297
267
222
637
809
758
470
4133
1441
1692
906
476
355
260
584
341
74
1695
1032
Number
of
fields
145
146
119
258
266
256
155
568
326
334
171
80
56
37
49
27
9
418
293
1993
Total gas
production
(Mcdf )
29
35
35
145
333
658
1,441
33
34
75
70
52
50
45
143
144
61
15
24
, 522.10
,208.28
,476.27
,470.97
,137.29
,014.31
,213.61
,929.83
,969.22
,284.47
,917.48
,484.52
,804.43
,609.81
,290.86
,255.16
,820.90
,364.73
,850.20
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
w
Gruy
State/ wellgroup
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
TXNGAS
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Depth
Range
(Mft)
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10+
10+
10 +
Range
(Mcfd)
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
44.
77.
106.
136.
169.
225.
389.
771.
1,765.
8.
22.
40.
68.
94.
127.
162.
221.
410.
883.
2,623.
32
05
43
38
82
90
43
45
23
67
45
45
77
23
38
23
84
15
81
55
Number
of
wells
1,689
937
509
348
270
516
334
95
13
78
55
119
122
74
70
53
168
173
148
64
Number
of
fields
433
271
159
140
91
143
102
58
11
43
31
43
48
34
29
24
57
52
43
25
Revised 1993
Number
of
wells
1609
893
485
332
257
492
318
91
12
74
52
113
116
71
67
51
160
165
141
63
Number
of
fields
412
258
152
134
87
136
97
56
10
41
29
41
46
33
28
23
54
50
41
25
1993
Total gas
production
(Mcdf )
71,318.36
68,803.79
51,618.71
45,279.17
43,643.84
111, 143.53
123,839.80
70,201.87
21,182.71
641.40
1,167.45
4,571.40
7,976.77
6,690.47
8,534.20
8,273.48
35,494.03
67,675.47
124,617.32
165,283.49
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
Depth
Range
(Mft)
Range
(Mcfd)
Gas rate
per well
(Mcfd)
Number
of
wells
Number
of
fields
Revised 1993
Number
of
wells
Number
of
fields
1993
Total gas
production
(Mcdf )
Texas-West
ro
i
10
00
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
TXWGAS
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
6.
23.
43.
73.
101.
130.
171.
223.
411.
788.
171,517.
9.
24.
45.
78.
108.
139.
170.
225.
383.
75
44
86
62
61
59
70
51
73
33
88
16
16
12
01
90
86
31
65
79
603
185
300
143
101
60
49
86
75
7
2
1,239
635
1,231
724
455
324
198
442
266
157
71
97
49
36
24
18
28
21
7
3
184
141
181
129
99
80
60
106
83
619
190
308
147
104
62
50
88
77
7
2
1268
651
1263
743
467
332
203
453
273
161
73
100
50
37
25
18
29
22
7
3
189
145
186
132
102
82
62
109
85
4,
4,
13,
10,
10,
8,
8,
19,
31,
5,
343,
11,
15,
56,
57,
50,
46,
34,
102,
104,
180
453
507
822
567
096
585
668
703
518
035
616
728
983
964
855
434
572
218
773
.32
.09
.96
.73
.40
.34
.00
.72
.06
.30
.77
.24
.74
.77
.74
.48
.88
.30
.12
.60
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
TXWGAS 21
TXWGAS 22
TXWGAS 23
TXWGAS 24
TXWGAS 25
TXWGAS 26
TXWGAS 27
W
1 TXWGAS 28
to
^° TXWGAS 29
TXWGAS 30
TXWGAS 31
TXWGAS 32
TXWGAS 33
Utah
UTGAS 1
UTGAS 2
UTGAS 3
UTGAS 4
UTGAS 5
UTGAS 6
Depth
Range
(Mft)
4-10
4-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10 +
0-4
0-4
0-4
0-4
0-4
0-4
Range
(Mcfd)
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
Gas rate
per well
(Mcfd)
767
2,366
7
23
42
69
102
131
161
225
424
984
3,705
5
18
38
64
95
130
.62
.38
.65
.40
.23
.86
.26
.07
.94
.42
.77
.36
.64
.74
.60
.23
.59
.18
.15
" umber
of
Jells
103
27
76
33
73
52
35
41
41
115
178
254
294
42
21
26
20
16
11
Number
of
fields
44
12
51
25
55
35
27
32
32
61
62
62
51
10
8
10
7
9
6
Revised 1993
Number
of
wells
106
28
78
34
75
53
36
42
42
118
183
261
302
57
29
35
27
22
15
Numbe
r of
field
s
45
12
52
26
57
36
28
33
33
63
64
64
52
14
11
13
9
12
8
1993
Total gas
production
(Mcdf )
81,
66,
3,
3,
3,
5,
6,
26,
77,
256,
1,119,
1,
1,
2,
1,
367.42
258.51
596.49
795.74
167.50
702 .80
681.19
504.90
801.58
599.90
732.54
917.51
103.18
327.39
539.26
338.03
744.02
093.94
952.23
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
W
1
GO
O
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
UTGAS
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
10 +
10 +
10 +
10 +
10+
10 +
Range
(Mcfd)
167
200
334
667
0.0
20
34
67
100
134
167
200
334
667
1,667
20
34
100
200
334
667
200
333
667
1,667
20
33
67
100
133
167
200
333
667
1,667
0.00
33
67
133
333
667
1,667
Gas rate
per well
(Mcfd)
141
167
427
749
8
17
37
58
90
114
138
196
341
644
10,117
18
66
127
113
148
699
.58
.92
.94
.47
.67
.72
.79
.23
.71
.97
.45
.51
.48
.98
.78
.20
.67
.30
.83
.52
.65
Number
of
wells
5
9
3
2
38
29
110
92
79
73
42
86
79
25
9
2
1
1
2
4
2
Number
of
fields
6
5
4
3
12
13
18
15
13
15
12
17
17
10
7
3
1
1
1
4
3
Revised 1993
Number
of
wells
7
12
4
3
55
39
149
125
107
99
57
117
107
34
12
3
1
1
3
5
3
Number
of
fields
8
7
5
5
16
17
24
20
18
20
16
23
23
14
9
5
1
1
2
5
5
1993
Total gas
production
(Mcdf )
991
2,015
1,711
2,248
476
691
5,630
7,278
9,705
11,382
7,891
22,992
36,537
21,929
121,413
54
66
127
341
742
2,098
.06
.07
.78
.40
.86
.20
.76
.85
.62
.06
.92
.13
.88
.37
.38
.60
.67
.30
.50
.58
.95
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellqrouo
UTGAS
Virginia
VAGAS
VAGAS
VAGAS
VAGAS
VAGAS
|# VAGAS
1
W VAGAS
VAGAS
VAGAS
28
1
2
3
4
5
6
7
8
9
Depth
Range
(Mft)
10 +
0-5
0-5
0-5
0-5
0-5
0-5
0-5
0-5
0-5
Range
(Mcfd)
1,667
0.0
34
67
134
167
200
334
667
1,667
0.00
20
67
100
167
200
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
15,430
11
37
100
154
209
286
508
1,331
4,761
.77
.28
.38
.52
.88
.58
.09
.35
.08
.80
" umber
of
jells
28
325
286
59
23
12
7
21
4
1
Number
of
fields
1
N/A
N/A,
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Revised
Number
of
wells
36
590
519
107
42
22
13
38
7
2
1993
1993
Number Total gas
of production
fields (Mcdf)
1 555,
6,
19,
10,
6,
4,
3,
19,
9,
9,
507.73
657.50
402.37
755.19
504.83
610.71
719.11
317.15
317.53
523.60
West Virginia
WVGAS
WVGAS
WVGAS
WVGAS
WVGAS
WVGAS
WVGAS
1
2
3
4
5
6
7
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0.0
20
34
67
134
200
667
20
33
67
100
167
333
1,667
5
23
43
83
146
322
988
.37
.12
.66
.36
.69
.51
.16
29,959
2,875
2,074
645
449
185
54
N/A
N/A
N/A
N/A
N/A
N/A
N/A
31645
3037
2191
681
474
195
57
169,
70,
95,
56,
69,
62,
56,
963.19
200.86
648.45
765.80
528.80
888.84
324.90
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/wellgroup
Wyoming
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
W WYGAS
1
^ WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Depth
Range
(Mft)
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
0-4
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
4-10
Range
(Mcfd)
0.0
20
34
67
100
134
167
200
334
667
1,667
0.0
20
34
67
100
134
167
200
334
20
33
67
100
133
167
200
333
667
1,667
0.00
20
33
67
100
133
167
200
333
667
Gas rate
per well
(Mcfd)
6
21
42
66
85
132
150
218
330
581
5,628
6
21
41
66
95
120
160
219
388
.63
.66
.31
.79
.06
.51
.99
.29
.86
.26
.49
.83
.31
.52
.49
.48
.08
.95
.44
.14
Number
of
wells
77
30
83
36
26
18
19
44
34
28
10
74
59
178
122
128
96
100
241
268
Number
of
fields
43
18
39
23
22
16
14
30
24
15
10
47
38
75
59
58
47
43
65
64
Revised 1993
Number
of
wells
80
31
86
37
26
19
20
46
35
30
10
77
61
185
125
133
100
104
250
278
Number
of
fields
45
19
40
24
23
17
15
31
25
16
10
49
39
78
61
60
49
45
67
66
1993
Total gas
production
(Mcdf)
3
2
2
2
3
10
11
17
56
1
7
8
12
12
16
54
107
530.42
671.46
,638.66
,471.26
,211.60
,517.68
,019.75
,041.21
,580.13
,437.75
,284.90
525.79
,299.95
,680.51
,310.83
,699.39
,008.44
,738.38
,858.96
,902.03
(continued)
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
State/ wellgroup
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
ft) WYGAS
1
£J WYGAS
WYGAS
WYGAS
WYGAS
WYGAS
21
22
23
24
25
26
27
28
29
30
31
32
33
Depth
Range
(Mft)
4-10
4-10
10 +
10 +
10 +
10 +
10 +
10 +
10 +
10+
10 +
10 +
10+
Range
(Mcfd)
667
1,667
0.0
20
34
67
100
134
167
200
334
667
1,667
1,667
0.00
20
33
67
100
133
167
200
333
667
1,667
0.00
Gas rate
per well
(Mcfd)
765
2,124
4
13
30
55
75
100
128
185
370
721
9,085
.06
.09
.60
.95
.37
.20
.65
.22
.87
.36
.15
.65
.16
Number
of
wells
209
60
51
30
88
80
57
37
40
97
145
90
120
Number
of
fields
53
22
37
25
56
51
36
22
31
36
48
41
33
Revised 1993
Number
of
wells
217
62
53
31
91
83
59
38
42
101
150
96
124
Number
of
fields
55
23
38
26
58
53
37
23
33
37
50
42
34
1993
Total gas
production
(Mcdf)
166,017.94
131,693.82
243.83
432.59
2,763.99
4,581.46
4,463.06
3,808.18
5,412.40
18,721.03
55,521.76
69,278.04
1,126,560.0
5
-------
APPENDIX B: GRUY ENGINEERING CORPORATION'S GAS WELLGROUPS BY STATE (CONTINUED)
Gruy
Revised 1993
State/wellgroup
Depth
Range
(Mft)
Range
(Mcf«)
Gas rate
per well
(Mcfd)
Number
of
wells
Number
of
fields
Number
of
wells
Number
of
fields
1993
Total gas
production
(Mcdf )
ro
i
OJ
(continued)
-------
APPENDIX C
DERIVATION AND INTERPRETATION OF
SUPPLY FUNCTION PARAMETER (3
-------
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:
q,- = YJ + -
1 D 2
1/2
1 (4-1)
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:
3q /q dq /dr
Sj = -7—— = ;— (C-la)
dr/r q-j/r
or
^j ~ -7— ' — (C-lb)
dr q.
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
r
*J
4q.
1/2
(C-2)
Since economic theory dictates that the supply elasticity
is positive (i.e., ^ > 0) and qd and r are positive, Equation
(C-2) above indicates that the parameter 3 is negative, i.e.,
3 < 0. Finally, the solution for (3 from Equation (C-2)
reveals the following expression:
-1/2
(C-3)
where
E, = market supply elasticity, and
q = production-weighted average annual level of natural
gas production per well.
This approach derives a single (3 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
nf Demand elasticity for natural gas by end-user
(i) .
^ 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).
Bf 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).
pi 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 (q^ • q1) and market supply of natural
gas (Q
s\
D-l
-------
q^ • QD Domestic end-user demand (q^) and market demand
for natural gas (QD) .
D.3 MODEL EQUATIONS
Market Supply of Natural Gas:
Qs - q1 +E q/ ,
where
q =
and
or
1/2
without regulation
y^ s
r - c.
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
Q/t
(a) Change in Consumer Surplus with Regulation
$/Q
Q2 Q, Q/t
(b) Change in Producer Surplus with Regulation
,S'
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 Pl with quantity Qj. 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 Px. 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
-------
TABLE F-l. DATA SUMMARY OF COMPANIES INCLUDED IN FIRM-LEVEL ANALYSIS: 1993
Comp.
ID
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Company Name
Adams Resources &
Energy Inc .
Alamco, Inc.
Alexander Energy
Corp.
Alfa Resources
Corp.
Allegheny &
Western Energy
Corp.
Alta Energy Corp.
Amber Resources
Co.
Amerada Hess
Corp.
American
Exploration Co.
American Natural
Energy Corp.
Amoco Corp.
Apache Corp .
ARCO
Ashland Oil Inc.
Barrett Resources
Corp.
Basic Earth
Science Systems
Inc .
Basin Expl. Inc.
SIC
Code
1311
1311
1311
1311
4924
1311
1311
2911
1311
1311
2911
1311
2911
2911
1311
1382
1311
Employment
(#)
291
87
46
11
565
31
2
10,100
297
121
46,994
884
26,800
31,800
60
13
123
Sales
($000/yr)
695,
11,
14,
1,
185,
16,
5,872,
59,
8,
28,617,
466,
19,183,
10,283,
42,
1,
37,
445
900
207
354
534
926
469
741
088
425
000
638
000
325
686
653
968
Assets
($000)
50,
43,
54,
1,
195,
58,
3,
8,641,
185,
21,
28,486,
1,592,
23,894,
5,551,
90,
2,
131,
295
261
158
261
680
467
604
546
598
169
000
407
000
817
740
745
520
Total
Liquid
Net Income Production
($000/yr) (Bcf)
1,452
1,552
1,245
5
3,746
(3,750)
(10)
(268,203)
(19,186)
704
1,820,000
37,334
269,000
142,234
5,756
(23)
5,150
0.54
0.37
2.02
0.6
0.05
4.92
0.02
260
11.89
0.81
1000
121
2210
4
0.75
0.77
8.44
Total
Natural
Gas
Production
(Bcf)
0.
3.
3.
0.
1.
1.
0.
183.
11.
2.
867.
109.
332.
36.
7.
0.
13.
885
197
692
Oil
518
665
232
000
790
640
000
300
000
200
214
126
330
(continued)
-------
TABLE F-l. DATA SUMMARY OF COMPANIES INCLUDED IN FIRM-LEVEL ANALYSIS: 1993 (CONTINUED)
Comp .
ID
18
19
20
21
22
23
24
I 25
to
26
27
28
29
30
31
32
33
34
Company Name
Belden & Blake
Corp.
Bellwether
Exploration Co.
Berry Petroleum
Co.
Black Dome Energy
Corp.
Black Hills Corp.
Box Energy Corp .
Western Gas
Resources
Louis Dreyfus
Natural Gas Corp.
Gallon
Consolidated
Partners LP
Castle Energy
Corp.
Chevron Corp.
Cliffs Drilling
Co.
Coastal Corp.
Columbia Gas
System
Columbus Energy
Corp.
Corns tock
Resources Inc .
Conoco Inc .
SIC
Code
1311
1311
1311
1311
1311
1311
4923
1311
1311
1311
2911
1381
1311
1311
1382
1311
2911
Employment
(#)
292
6
125
3
449
57
825
556
126
402
49,245
352
16,570
10,172
36
27
25,782
Sales
($000/yr)
77,
3,
67,
139,
37,
932,
95,
8,
601,
37,082,
66,
10,136,
3,398,
12,
22,
15,771,
718
655
761
678
373
102
338
181
805
000
000
396
100
500
913
453
000
Assets
($000)
135,
12,
135,
1,
352,
128,
1,114,
481,
19,
392,
34,736,
133,
10,277,
6,957,
22,
74,
11,938,
174
480
159
040
853
882
748
488
349
738
000
523
100
900
938
095
000
Total
Liquid
Net Income Production
($000/yr) (Bcf)
3
22
2
38
2
67
1,265
3
115
152
3
2
812
,220
41
32
62
,946
,161
,102
,260
165
,837
,000
,626
,800
,200
,806
,324
,000
4.53
0.49
36.17
0.03
3.27
8.04
1.07
21.06
2.64
0.45
1440
0.44
49.4
36.03
2.93
2.78
400
Total
Natural
Gas
Production
(Bcf)
7.373
0.483
0.771
0.286
0.777
3.912
15.850
30.540
6.847
3.472
751.000
1.651
122.000
71.500
1.693
7.274
305.000
(continued)
-------
TABLE F-l. DATA SUMMARY OF COMPANIES INCLUDED IN FIRM-LEVEL ANALYSIS: 1993 (CONTINUED)
Comp.
ID
35
36
37
38
39
40
7 41
w 42
43
44
45
46
47
48
49
50
51
Company Name
Consolidated
Natural Gas Co.
Crystal Oil
Company
Delta Natural Gas
Co . Inc .
Eagle Exploration
Co.
Edisto Resources
Corp.
Energy
Development Corp.
Enron Corp .
Ensearch Corp.
Equitable
Resources Inc.
Espero Energy
Corp.
Exxon Corp .
Forest Oil Corp.
Great Northern
Gas Co.
Hallwood Energy
Prtnr LP
KN Energy Inc .
Lomak Petroleum
Inc .
Louisiana Land &
Exploration
SIC
Code
4923
1311
4923
1311
4923
1311
1382
1311
4923
1311
2911
1311
1311
1311
4923
1311
1382
Employment
(#)
7,615
92
177
2
192
235
7,780
10,400
2,454
8
95,000
183
4
200
1,600
150
709
Sales
($000/yr)
3,194,
35,
31,
175,
281,
8,003,
1,902,
1,094,
6,
111,211,
105,
49,
493,
19,
815,
616
940
221
355
069
066
939
299
794
050
000
148
667
613
349
075
400
Assets
($000)
5,409,
117,
55,
1,
168,
679,
11,504,
2,760,
1,946,
9,
84,145,
426,
1,
171,
731,
76,
1,838,
586
334
130
336
243
437
315
261
907
383
000
755
469
624
269
333
700
Total
Liquid
Net Income Production
($000/yr) (Bcf)
205
1
2
5
46
332
59
73
5,280
(21,
13
24
1
9
,916
,040
,621
120
,600
,341
,522
,237
,455
116
,000
213)
177
,064
,275
,391
,600
39.07
11.06
0
0.03
3.53
26.1
25.2
24.81
21.12
1.26
2020
14.93
0
8.81
1.51
3.18
88
Total
Natural
Gas
Production
(Bcf)
124.000
7.551
0.270
0.009
11.160
95.000
240.000
70.030
53.550
1.891
697.000
41.110
0.384
14.070
5.100
2.590
65.600
(continued)
-------
TABLE F-l. DATA SUMMARY OF COMPANIES INCLUDED IN FIRM-LEVEL ANALYSIS: 1993 (CONTINUED)
Comp.
ID
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
Company Name
Maxus Energy
Corp.
Meridian Oil Inc.
Mesa Inc.
Mitchell Energy &
Development Corp.
Mobil Corp.
Noble Affiliates
Inc.
Nuevo Energy Co .
Occidental
Petroleum Corp.
ONEOK Inc.
Oryx Energy Co .
Pennzoil Co.
Phillips
Petroleum Co.
Plains Petroleum
Co.
Pogo Producing
Co.
Presidio Oil CLA
Questar Corp.
Sage Energy Co.
Samson Energy Co.
LP
Sante Fe Energy
Resources
Shell Oil Co.
Snyder Oil Corp.
SIC
Code
1311
1311
1311
1311
2911
1311
1382
1311
4923
1382
2911
1311
1311
1311
1382
1311
1311
1311
1311
2911
1311
Employment
(#)
2,190
1,700
382
2,900
63,700
503
630
23,600
2,208
1,600
9,901
21,400
106
100
137
2,659
105
176
839
28,893
289
Sales
($000/yr)
807,
1,246,
232,
952,
63,975,
286,
107,
8,544,
789,
1,054,
2,782,
12,545,
64,
139,
48,
664,
43,
22,
446,
21,092,
229,
000
502
908
809
000
583
832
000
111
000
397
000
280
568
267
062
399
374
000
000
685
Assets
($000)
1,
4,
1,
2,
40,
1,
17,
1,
3,
4,
10,
1,
1,
26,
987,400
375,165
533,382
415,476
585,000
067,996
287,591
123,000
104,468
624,000
886,203
868,000
126,792
239,774
280,420
417,687
49,632
41,805
076,900
851,000
479,536
Total
Liquid
Net Income Production
($000/yr) (Bcf)
(49,
303
(102,
19
2,084
12
8
283
38
(100,
141
243
1
25
(7,
81
6
4
(77,
781
25
400)
,138
448)
,687
,000
,625
,933
,000
,424
000)
,856
,000
,727
,061
233)
,692
,735
,329
100)
,000
,664
46
153.1
57.88
203
1110
60.64
19.33
210
4.43
240
240
470
12.2
42.2
14.36
20.56
15.18
2.51
219
1470
34.51
Total
Natural
Gas
Production
(Bcf)
76.000
336.000
79.820
74.400
558.000
71.310
16.770
219.000
8.401
191.000
220.000
345.000
23.760
32.320
15.340
67.810
6.305
7.641
60.300
539.000
35.080
(continued)
-------
TABLE F-l. DATA SUMMARY OF COMPANIES INCLUDED IN FIRM-LEVEL ANALYSIS: 1993 (CONTINUED)
Comp.
ID
73
74
75
76
77
78
79
80
Company Name
Sonat Inc.
Sooner Energy
Corp.
Texaco Inc .
Tide West Oil Co.
Unocal Corp.
USX-Marathon
Group
Wainoco Oil Corp.
Wolverine
Exploration Co.
SIC
Code
4923
1311
2911
1311
2911
2911
2911
1311
Employment
(#)
5,300
2
38,000
34
14,687
44, 872
434
4
Sales
($000/yr)
1,966,664
392
34,071,000
96,302
8,344,000
11,962,000
366,556
7,061
Assets
($000)
3,213,997
352
26,626,000
106,606
9,254,000
10,806,000
296,811
10,763
Total
Liquid
Net Income Production
($000/yr)
261,240
219
1,068,000
4, 030
213,000
(29,000)
2,504
4,953
(Bcf)
37.44
0.02
1550
0.58
480
410
7.47
1.12
Total
Natural
Gas
Production
(Bcf)
146.100
0.077
652.000
2.317
365.000
193.000
2.504
1.467
-------
TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
1 REPORT NO 2
EPA-452/R-99-003
4 TITLE AND SUBTITLE
Economic Impact Analysis of the Oil and Natural
Gas Production
NESHAP and the Natural Gas Tranmission and Storage NESHAP
7 AUTHOR(S)
Lisa Conner, Innovative Strategies and Economics Group
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Air Quality Strategies and Standards Division (MD-15)
Research Triangle Park, NC 27711
12. SPONSORING AGENCY NAME AND ADDRESS
John Sietz, Director
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO
5. REPORT DATE
May 1999
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11 CONTRACT/GRANT NO
13. TYPE OF REPORT AND PERIOD COVERED
14 SPONSORING AGENCY CODE
EPA/200/04
15 SUPPLEMENTARY NOTES
16 ABSTRACT
This report evaluates the impacts of the final rule for controls of hazardous air pollutants (HAPs) in the Oil
and Natural Gas Production industry and the Natural Gas Transmission and Storage industry. Total social
costs are estimated by evaluating costs of compliance with the rule and associated market impacts,
including: price changes in the natural gas market, adjustments in quantity produced, small entity impacts,
and employment impacts .
H KEY WORDS AND DOCUMENT ANALYSIS
a DESCRIPTORS
economic impacts
small entity impacts
social cost
18 DISTRIBUTION STATEMENT
Release Unlimited
b. IDENTIFIERS/OPEN ENDED TERMS c COSATI Field/Group
Air Pollution control
Economic Impact Analysis
Regulatory Flexibility Analysis
19 SECURITY CLASS (Repon) 21. NO. OF PAGES
Unclassified
20 SECURITY CLASS (Page) 22. PRICE
Unclassified
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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