&EPA
United States
Environmental Protection
Agency
Office of Water
4303
EPA-821-B-98-020
February 1999
Economic Analysis of Proposed Effluent
Limitations Guidelines and Standards for
Synthetic-Based Drilling Fluids and Other
Non-Aqueous Drilling Fluids in the Oil and
Gas Extraction Point Source Category
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ECONOMIC ANALYSIS OF PROPOSED EFFLUENT
LIMITATIONS GUIDELINES AND STANDARDS FOR
SYNTHETIC-BASED DRILLING FLUIDS AND
OTHER NON-AQUEOUS DRILLING FLUIDS IN THE
OIL AND GAS EXTRACTION POINT SOURCE CATEGORY
Office of Water
Office of Science and Technology
Engineering and Analysis Division
U.S. Environmental Protection Agency
401 M Street, SW
Washington, D.C. 20460
February 1999
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CONTENTS
SECTION ONE INTRODUCTION 1-1
SECTION TWO SOURCES OF DATA 2-1
SECTION THREE PROFILE OF AFFECTED OFFSHORE DRILLING OPERATIONS 3-1
3.1 Introduction 3-1
3.2 Processes of Offshore Oil and Gas Exploration and Development Drilling
and the Wastes Generated 3-1
3.2.1 Exploratory, Developmental, and Other Drilling 3-1
3.2.2 Drilling Rigs 3-2
3.2.3 Description of Drilling Operations 3-3
3.2.4 Drilling Fluids and Drill Cuttings 3-4
3.3 Profile of the Affected Regions 3-8
3.3.1 Gulf of Mexico Beyond Three Miles from Shore 3-8
3.3.2 Offshore California 3-22
3.3.3 Cook Inlet, Alaska 3-25
3.3.4 Offshore Alaska 3-29
3.4 Summary of Well Counts and Operator Counts 3-33
SECTION FOUR REGULATORY OPTIONS AND AGGREGATE COSTS OF
THE EFFLUENT GUIDELINES 4-1
4.1 Regulatory Options 4-1
4.2 Total Compliance Costs 4-3
SECTION FIVE ECONOMIC IMPACTS OF THE PROPOSED RULEMAKING 5-1
5.1 Impacts on Existing Sources 5-1
5.1.1 Impacts on Costs of Drilling Wells 5-1
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Page
5.1.2 Impacts on Platforms and Production 5-4
5.1.3 Impacts on Firms 5-5
5.1.4 Secondary Impacts 5-7
5.2 Impacts on New Sources 5-11
SECTION SIX REGULATORY FLEXIBILITY ANALYSIS 6-1
6.1 Introduction 6-1
6.2
6.3
6.4
Initial Assessment
Regulatory Flexibility Analysis Components
6.3.1 Need for and Objectives of the Rule
6.3.2 Estimated Number of Small Business Entities to Which
the Regulation Will Apply
6.3.3 Description of the Proposed Reporting, Recordkeeping, and
Other Compliance Requirements
6.3.4 Identification of Relevant Federal Rules Which May Duplicate,
Overlap, or Conflict With the Proposed Rule
635 Significant Regulatory Alternatives
Small Business Analvsis
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.... 6-2
.... 6-3
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SECTION SEVEN COST-BENEFIT ANALYSIS 7-1
APPENDIX A COSTS OF COMPLIANCE PER WELL BY TYPE OF WELL
APPENDIX B COSTS OF COMPLIANCE BY FIRM
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SECTION ONE
INTRODUCTION
The U.S. Environmental Protection Agency (EPA) is proposing to regulate the discharge of
synthetic based drilling fluids (SBFs) and other non-aqueous drilling fluids and the resultant contaminated
drill cuttings from drilling operations. This Economic Analysis (EA) report is written to address the
impacts of this proposed Effluent Limitation Guidelines and Standards for Synthetic-Based and Other Non-
Aqueous Drilling Fluids. Currently, effluent guidelines pertaining to the discharge of drilling fluids address
two specific types of fluids:
• Oil-based drilling fluids (OBFs) that use diesel and mineral oil, which are prohibited from
being discharged.
• Water-based drilling fluids (WBFs), which can be discharged subject to meeting certain
discharge requirements, including a sheen test and an aqueous toxicity test, in certain
limited offshore regions.
In many cases, SBFs and SBF-contaminated cuttings are not clearly prohibited from discharge, nor
are they clearly allowed to be discharged, since the relevant effluent guidelines that define allowable
conditions for discharge of drilling fluids and cuttings were developed before SBFs and other non-aqueous
drilling fluids were widely available. To address this lack of clarity in existing effluent guidelines and to
more clearly define allowable discharge conditions for SBF and other non-aqueous drilling wastes, EPA is
proposing these Effluent Limitations Guidelines and Standards for Synthetic-Based and Other Non-
Aqueous Drilling Fluids (known hereafter as the SBF Guidelines; where this report uses the term SBF,
other non-aqueous fluids and associated cuttings are included in this term). These guidelines are being
proposed as part of an expedited rulemaking process and thus the analyses in this report rely on publicly
available or industry-provided data exclusively.
The SBF Guidelines would control the discharge of SBF-contaminated drill cuttings (SBF-
cuttings). Discharge of the fluids themselves would be prohibited. Furthermore, the SBF guidelines would
only apply where discharge of drilling waste is currently allowed. Because drilling fluids and cutting may
only be discharged in a portion of offshore areas, the operations that might be affected by this proposed
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rulemaking would be limited to a subset of the U.S. oil and gas industry. EPA subdivides the oil and gas
extraction point source category into several major subcategories, including the Onshore Subcategory, the
Stripper Subcategory (marginal producing wells), the Beneficial Use Subcategory (wells whose produced
water can be used beneficially for irrigation or other purposes), the Coastal Subcategory (wells located in
water located landward of the territorial seas and associated wetlands), and the Offshore Subcategory (see
40CFR Part 435 for more details on the subcategorization of the oil and gas extraction point source
category). Discharge of drilling fluids or drill cuttings into surface waters is completely prohibited for the
Onshore, Stripper and Beneficial Use Subcategories, no matter what the composition of the fluid, as is the
discharge of any drilling fluid in regions defined as coastal, with the exception of Cook Inlet, Alaska.
Furthermore, discharge of any type of drilling fluid also is prohibited within 3 miles of shore in the
Offshore region except Offshore Alaska, where there is no distance restriction.
Currently, the potentially affected offshore regions where drilling activity is taking place include
the Gulf of Mexico, California, and Alaska. Drilling activity is also underway in the coastal region of
Cook Inlet, Alaska. Outside of these regions, significant amounts of drilling activity are very unlikely to
occur or discharge of drilling waste is prohibited.1 Therefore, the focus of the industry profile and the
analyses in this EA is on:
• The Federal Outer Continental Shelf (OCS) region of the Gulf of Mexico and the state
waters off Texas between 3 miles and 3 leagues (Texas defines state waters out to 3
leagues, unlike most other states).
• The Federal Offshore region farther than 3 miles from the California shore.
• The Coastal Subcategory Region of Upper Cook Inlet, Alaska
• All Alaska Offshore areas.
Drilling operations in all these regions are investigated to determine how these operations would be affected
by the proposed rule.
:See discussions in the Economic Impact Analysis of Final Effluent Limitations Guidelines and
Standards of Performance for the Offshore Oil and Gas Industry, U.S. EPA, 1993, EPA-821/R-93.001,
and the Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards for the
Coastal Subcategory of the Oil and Gas Extraction Point Source Category, U.S. EPA 1995, EPA
821/R95.013.
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This report is divided into seven sections. Following this introduction, Section Two presents
sources of data, Section Three presents the industry profile, Section Four discusses the regulatory costs of
options under consideration for the proposed rulemaking, and Section Five discusses the impacts of the
proposed rule on firms, well drilling, and production, and also briefly discusses secondary impacts such as
those on employment, output, inflation, balance of trade and other industries. Section Six presents EPA's
initial regulatory flexibility analysis as required under the Regulatory Flexibility Act (RFA) as amended by
the Small Business Regulatory Enforcement Fairness Act (SBREFA). Section Seven provides a brief
summary of costs and benefits of the rule. Finally Appendix A documents how the per-well incremental
costs were derived from EPA's engineering cost estimates, and Appendix B presents numbers of wells
estimated to be drilled annually by potentially affected firms and the resulting compliance costs associated
with those firms.
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SECTION TWO
SOURCES OF DATA
As discussed in Section One, EPA has undertaken an expedited approach to this proposed rule.
This means that EPA is not using a survey authorized under the Clean Water Act (Section 308 Survey) but
instead is relying on public data and data that industry has submitted on a voluntary basis. This section
discusses the primary sources of data used throughout this document. Certain additional references are
cited where they occur in the document.
EPA is relying on information developed by Minerals Management Service (MMS) for EPA. This
information includes wells drilled in federal waters during 1995, 1996, and 1997, along with the MMS-
assigned numbers identifying the operators. These data were summarized by MMS from MMS's
Technical Information Management System (TIMS). MMS grouped wells by location (Pacific and Gulf
drilling operations were tallied separately), water depth (up to 999 ft and 1,000 ft or more), and by type
(exploratory or development). MMS also provided a list of operators by operator number. EPA linked the
name of the operators to wells drilled using the operator number. Names of all operators who had drilled
any well in any of the three years were then compiled. EPA used the Security and Exchange Commission's
(SEC's) Edgar database, which provides access to various filings by publicly held firms, such as 8Ks and
lOKs. The former documents are useful for determining mergers and acquisitions in more detail, and lOKs
provide annual balance sheet and income statements, as well as listing corporate subsidiaries. The
information in the Edgar database was used to identify parent companies or recent changes of ownership.
EPA also used a database maintained by Dun & Bradstreet (D&B), to which EPA subscribes, which
provides estimates of employment and revenue for many privately held firms. This database is the U.S.
EPA Facility Index System Dun & Bradstreet Detail and is referenced in this document as the D&B
database. EPA also relied on financial data compiled by Oil and Gas Journal (OGJ) in two articles
collectively known as the "OGJ 200 Report" in the issue: "OGJ 200 Companies Posted Strong Financial
Year in 1997" and "Government Oil Companies Dominate OGJ 100 List of Production Leaders Outside
U.S." These articles provided financial data on publicly held U.S. and foreign firms. This EA references
the OGJ 200 Report as OGJ 200.
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Other sources of data used in the economic analyses include:
Development Document for Proposed Effluent Guidelines and Standard for Synthetic-
Based Drilling Fluids and Other Non-Aqueous Drilling Fluid in the Oil and Gas
Extraction Point Source Category, U.S. EPA, 1999 (EPA-821-B-98-021) (hereinafter
known as the SBF Development Document). This document supports this proposed
rulemaking and presents all cost data.
Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry (hereinafter known as Offshore EIA)
(EPA 821/R-93.004) EPA, 1993
Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards for
the Coastal Subcategory of the Oil and Gas Extraction Point Source Category
(hereinafter known as Coastal EIA) (EPA 821/R95.013), EPA, 1995.
The Joint Association Survey on 1996 Drilling Costs, published by the American
Petroleum Institute (API), November, 1997 (hereinafter known as the Joint Association
Survey). This document was used to determine baseline costs of drilling wells in the
various offshore regions potentially affected by the rule.
USA Oil Industry Directory, 37th Edition, PennWell Publishing Co., 1998 (hereinafter
known as PennWell Directory), was used to provide additional information on potentially
affected firms.
Additional sources are cited in detail where they are mentioned in this report.
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SECTION THREE
PROFILE OF AFFECTED OFFSHORE DRILLING OPERATIONS
3.1 INTRODUCTION
This profile focuses on the drilling activity taking place in the Offshore regions of the Gulf of
Mexico, California, and Alaska where discharge of drilling fluids with controls is authorized.1 As
discussed in Section One, the key areas include the Federal OCS region of the Gulf of Mexico and the state
waters off Texas between 3 miles and 3 leagues, the California Federal OCS, the Coastal Subcategory
region of Upper Cook Inlet, Alaska, and all Alaska Offshore areas. This section first discusses the
processes of oil and gas drilling and the wastes created. It then presents current practices regarding use of
OBFs, platforms, operators, and drilling activity in the regions of interest: Gulf of Mexico, California,
Alaska Coastal, and Alaska Offshore.
3.2 PROCESSES OF OFFSHORE OIL AND GAS EXPLORATION AND DEVELOPMENT
DRILLING AND THE WASTES GENERATED
3.2.1 Exploratory, Developmental, and Other Drilling
The two primary types of drilling operations conducted as part of the oil and gas extraction process
are exploratory and developmental. Exploratory operations involve drilling wells to determine potential
hydrocarbon reserves. Once a hydrocarbon reserve has been discovered and delineated, development wells
are drilled for production. Although the rigs used for each type of drilling can differ, the drilling process is
generally the same.
1 Other operations related to oil and gas drilling, including drilling fluid suppliers, solids control
equipment rental firms, and waste transport and disposal firms, which may experience indirect impacts as a
result of the rule, are discussed briefly in Section Five when secondary impacts on these operations are
analyzed.
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In the initial phases of exploration, wells usually are drilled to discover the presence of oil and gas
reservoirs. Deeper wells subsequently are drilled to establish the extent of a reservoir (delineation).
Exploration activities are usually of short duration, involve a small number of wells, and are conducted
from mobile drilling rigs.
Other than being conducted to begin extracting recently discovered reserves of hydrocarbons,
development drilling also is conducted to increase production or to replace nonproducing wells on existing
production sites. Since development wells tend to be smaller in diameter than exploratory wells less waste
is generated.2
3.2.2 Drilling Rigs
Exploratory drilling is usually accomplished using mobile offshore drilling units (MODU). These
units are used to drill exploratory wells because they can be easily moved from one drilling site to another.
The two basic types of MODUs are bottom-supported units and floating units. Bottom-supported units
include submersibles and jackups. Floating units include inland barge rigs, drill ships, ship-shaped barges,
and semisubmersibles.
Bottom-supported drilling units are typically used when drilling occurs in shallow waters.
Submersibles are barge-mounted drilling rigs that are towed to the drill site and sunk to the bottom. There
are two common types of submersible rigs: posted barge and bottle-type.
Jackups are barge-mounted drilling rigs that have extendable legs that are retracted during
transport. At the drill site, the legs are extended to the seafloor. As the legs continue to extend, the barge
hull is lifted above the water. Jackup rigs, which can be used in waters up to 300 feet deep, are of two
basic types: columnar leg and open-truss leg.
^Development Document for the Final Effluent Limitation Guidelines and Standards for the
Coastal Subcategory of the Oil and Gas Extraction Point Source Category, EPA, 1996.
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Floating drilling units are typically used when drilling occurs in deep waters and at locations far
from shore. Semisubmersibles are a type of floating drill unit that can withstand rough seas with minimal
rolling and pitching tendencies. Semisubmersibles are hull-mounted drilling rigs which float on the surface
of the water when empty. At the drilling site, the hulls are flooded and sunk to a certain depth below the
surface of the water. When the hulls are fully submerged, the unit is stable and not susceptible to wave
motion due to its low center of gravity. The unit is moored with anchors to the seafloor. Semisubmersibles
are used for drilling projects in ultra-deep water Gulf regions. There are two types of semisubmersible
rigs: bottle-type and column-stabilized.
Drill ships and ship-shaped barges are vessels equipped with drilling rigs that float on the surface
of the water. These vessels maintain position above the drill site by anchors on the seafloor or the use of
propellers mounted fore, aft, and on both sides of the vessel (dynamic positioning). Drill ships are the other
major drilling rig used in ultra-deep Gulf waters. In these locations, drill ships typically operate using
dynamic positioning.3 Drill ships and ship-shaped barges are susceptible to wave motion since they float
on the surface of the water, and thus are not suitable for use in heavy seas.
Development wells are often drilled from fixed platforms because once exploratory drilling has
confirmed that an extractable quantity of hydrocarbons exists, a platform is constructed at that site for
drilling and production operations. Frequently, directional drilling is conducted to access different parts of
a geological formation from a fixed location such as a platform. This type of drilling involves drilling the
top part of the well straight down and then directing the wellbore to the desired location.
3.2.3 Description of Drilling Operations
In the drilling process, drillers use a rotating drill bit attached to the end of a drill pipe, referred to as
the "drill string." Circulating fluid (i.e., drilling fluid or mud) is used to move drill cuttings (bits of rock)
away from the bit and out of the borehole. This fluid is frequently a mixture of water and/or various types of
oils, special clays, and certain minerals and chemicals that is pumped "downhole" through the drill string and
3 Drilling Contractor, 1997. "Survey Measures Growth of Ultra Deep-Water Fleet," pg. 18,
November 1997.
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ejected through the nozzles in the drill bit at high speeds and at high pressure. The jets of drilling fluid lift
the cuttings from the bottom of the hole and away from the bit so the cuttings do not interfere with the
effectiveness of the drill bit. The drilling fluid circulates and rises to the surface through the space between
the drill string and the casing, called the annulus. As the wellbore deepens, the walls of the hole tend to
cave in and widen; thus, periodically the drill string musty be lifted out so that a casing, which is a tube-
shaped liner, can be placed in the hole. Cement is then is pumped into the space between the casing and the
hole wall to secure the casing. Each new portion of casing must be smaller in diameter than the previous
portion to allow for installation. The process of drilling and adding sections of casing continues until final
well depth is reached. Figure 3-1 shows atypical drilling fluids circulation system.
3.2.4 Drilling Fluids and Drill Cuttings
3.2.4.1 Types of Drilling Fluids
WBFs are the most commonly used drilling fluids, but OBFs occasionally must be used such as when
directional drilling is performed or when stuck pipe must be freed. OBFs also might be used in certain
intervals or below certain depths. Diesel oil- or mineral oil-based OBFs are becoming less common primarily
due to discharge prohibitions and toxicity limitations on the waste fluids and cuttings generated during OBF
drilling. These fluids contain diesel or mineral oil as well as other constituents similar to those used in
WBFs. In some locations, such as in the Gulf of Mexico, use of OBFs can be markedly reduced by the use of
newer SBFs and other water non-dispersible drilling fluids. These SBFs have technical performance
properties and uses similar to traditional OBFs, but might have significantly reduced toxicities relative to
OBFs. The key advantage of SBFs is that cuttings associated with these fluids appear to pass limits on crude
contamination and toxicity and are currently being discharged in many Gulf locations instead of being barged
to shore for disposal at a possibly significant cost savings. The SBFs are, like traditional OBFs, invert
emulsions, meaning that they are oils with water mixed in, but their base fluid differs from OBFs. SBF oils,
or base fluids, can be vegetable esters, linear alpha olefins, internal olefms, or others currently in development
or theoretically usable. Another group considered in the "other water non-dispersible fluids" group, include
the enhanced mineral oils, which are highly refined mineral oils in which the major toxic components have
been removed. Finally there is the group of synthetic and nonsynthetic paraffmic oils.
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Mud-Mixing
Hopper
Mud Tank
Mud Pump
Spent Mud
To Disposal
Solids
Control System
Cuttings
To Disposal
A
Swivel
Kelley
-Drill Pipe
• Annulus
.Drill Collar
orehole
Figure 3-1. Typical drilling fluids circulation system.
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3.2.4.2 Drilling Wastes
Drilling fluids and drill cuttings become wastes at different stages of the well drilling process. Drill
cuttings are generated throughout the drilling project, although higher quantities of cuttings are generated when
drilling the first few thousand feet of the well because the borehole is the widest during this stage. In contrast,
the largest quantities of excess drilling fluids are generated as the project approaches final well depth. Most
waste fluid is generated at completion of well drilling because the entire drilling fluid system must be removed
from the hole and the tanks used to hold the drilling fluid. Some constituents can be recovered after completion
of the drilling, either at the rig or by the supplier of the drilling fluid. Typically, OBFs and SBFs are recovered
for recycling and waste fluid per se is not generated. A certain amount of the OBF or SBF remains adhered to
the drill cuttings, however, and so is disposed of as a contaminant of the cuttings.4 When drilling is continuous,
such as at certain platforms, drilling fluid can be reused to drill the next well in a series. The following sections
discuss the two types of wastes in more detail.
Cuttings
Drill cuttings are a major portion of the wastestream generated by the drilling process. At the well's
surface, the cuttings, along with silt, sand, and any gases, are removed from the drilling fluid before the
drilling fluid is returned downhole to the bit. The cuttings, silt, and sand are separated from the drilling fluid
by a solids separation process. This process typically involves shale shakers, desilters, desanders, and
centrifuges (each removing sequentially smaller waste particles from the drilling fluid). Some of the drilling
fluid remains adhered to the cuttings after solids separation. If the cuttings, silt, sand, and any residual
drilling fluid clinging to the cuttings do not contain free oil or other regulated contaminants and they meet the
specific requirements for discharge they may be discharged in certain portions of the Offshore and Coastal
subcategories defined above. To meet requirements of the proposed SBF Guidelines (see Section Four),
operators might need to add onto their usual solids separation equipment. An add-on technology that EPA
investigated as part of the rulemaking process is a vibratory centrifuge, which processes the larger cuttings
from the primary shale shakers. This process is described in the SBF Development Document in more detail.
4SBF Development Document.
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This type of system can achieve a high removal rate (and thus a low retention rate) of residual fluid on
cuttings.
Drilling Fluid
Drilling fluid itself can also become a waste. Drilling fluid can become contaminated, and thus
constitute a waste, during several different stages of the drilling process. Additionally, drilling fluid can
become a waste if it cannot be adjusted to provide the required flow properties, lubricity, or wellbore
stabilization. When a drilling fluid no longer meets the technical requirements or the operator decides that it
is advantageous to change to a new drilling fluid system, a "mud changeover" is performed. The drilling
fluid system replaced can become a waste at this stage if it is not recycled or reused later in the drilling
process. OBFs and SBFs are recycled because of the expense of the fluid and because of disposal
considerations. Any drilling waste or cuttings to be discharged must first be tested for sheen (which indicates
the level of hydrocarbon contamination of the fluid or cuttings) and also must be tested for toxicity. As
noted in Section Two, EPA is assessing additional tests and controls on SBF and SBF-cuttings discharge as
part of this rulemaking.
Very small drill cuttings called "fines" can build up in the drilling fluid, increasing the drilling fluid
solids and spoiling the flow properties of the drilling fluid. If drilling fluid solids cannot be controlled
efficiently, dilution with fresh drilling fluids might be necessary to reduce the solids content of the circulating
drilling fluid system, in which case the displaced drilling fluid can become a waste. More recently developed
solids control systems are much more efficient than older systems. Thus, waste drilling fluid stemming from
the need to displace fluid that has become overloaded with fine solids is now less of a problem. Furthermore
these systems are able to separate and recycle more fluid from the waste cuttings, reducing the amount of
drilling fluid adhering to the cuttings, further reducing contaminants such as free oil and toxics. Very recent
advances in the area of solids control incorporate the use of a vibrating centrifuge in the drilling fluid
recovery system. These types of systems are able to remove and recycle such a large portion of drilling fluid
that EPA is considering the use of these systems as part of the SBF Guidelines options (see Section Four).
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3.3 PROFILE OF THE AFFECTED REGIONS
3.3.1 Gulf of Mexico Beyond Three Miles from Shore
The Gulf of Mexico beyond 3 miles from shore is the most active of the four oil and gas regions of
interest. Nearly all exploration and development activities in the Gulf are taking place in the Western Gulf of
Mexico, that is, the regions off the Texas and Louisiana shores. Very little drilling is occurring off Mississippi,
Alabama, and Florida.
3.3.1.1 Current Practices
The Gulf of Mexico is the location of the majority of the drilling activity currently occurring in the
regions affected by this proposed rulemaking. This region also is associated with the only known current use of
SBF and discharge of SBF-cuttings. SBFs are used preferentially in drilling deeper formations, in deeper water,
in formations of reactive shale, and during directional drilling. They generally replace traditional OBFs for these
purposes.
3.3.1.2 Platforms
EPA updated its count of active platforms in the federal OCS region of the Gulf of Mexico that was
originally presented in the Offshore EIA, using the most recent version of the MMS Platform Inspection System,
Complex/Structure database as of May, 1998. The database was downloaded and counts of structures were
noted. Abandoned structures, platforms considered production facilities only, platforms with no productive
wells, platforms with missing production data, and platforms with service wells only were counted and removed
from totals, in the same way as was done for the Offshore Effluent Guidelines.5 Out of a total of 5,026
structures, EPA identified 2,381 platforms that fit this description (see Table 3-1).
5Offshore EIA.
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Table 3-1
Identification of Structures in the Gulf of Mexico OCS
Remaining
Category Count Count
All structures 5026 5026
Abandoned structures 1403 3623
Structures classified as production
structures, i.e. with no well slots
and with production equipment 245 3378
Structures known not to be in
production 688 2690
Structures with missing information
on product type (oil or gas or both) 309 2381
Structures whose drilled well slots
are used solely for injection,
disposal, or as a water source
0 2381
Source: MMS, 1998. Platform Inspection System, Complex/Structure.
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3.3.1.3 Operators
The expenditures required to comply with the SBF Guidelines will be financed by the affected firms and
their investors. Affected firms can be divided into two basic categories. The first category consists of
the major integrated oil companies, which are characterized by a high degree of vertical integration (i.e., their
activities encompass both "upstream" activities—oil exploration, development, and production—and
"downstream" activities—transportation, refining, and marketing). The second category of affected firms
consists of independents engaged primarily in exploration, development, and production of oil and gas and
not typically involved in downstream activities. Some independents are strictly producers of oil and gas,
while others maintain some service operations, such as contract drilling and well servicing. The major
integrated oil companies are generally larger than the independents. As a group, the majors typically produce
more oil and gas, earn significantly more revenue and income, and have considerably more assets and greater
financial resources than most independents. Furthermore, majors tend to be relatively homogeneous in terms
of size and corporate structure. All majors are considered large firms under the Regulatory Flexibility Act
(RFA) guidelines and generally are C corporations (i.e., the corporation pays income taxes).
Independents can vary greatly by size and corporate structure. Larger independents tend to be C
corporations; small firms might also pay corporate taxes, but they also can be organized as S corporations
(which elect to be taxed at the shareholder level rather than the corporate level under subchapter S of the
Internal Revenue Code). Small firms also might be organized as limited partnerships, sole proprietorships,
etc., whose owners, not the firms, pay taxes.
For this profile, EPA is relying on information developed by MMS for EPA that includes wells
drilled in federal waters during 1995, 1996, and 1997, along with the identification number of the operator.
These data were summarized from MMS's Technical Information Management System (TIMS). MMS
grouped wells by location (Pacific and Gulf drilling operations were tallied separately), water depth (up to
999 ft and 1,000 ft or more), and by type (exploratory or development). MMS also provided a list of operators
by operator number. EPA linked the name of the operators to wells drilled using the operator number. Names
of all operators who had drilled any well in any of the three years were then compiled. The first column of Table
3-2 shows these operators. EPA then used the Security and Exchange Commission's (SEC's) Edgar database,
which provides access to various filings by publicly held firms, such as 8Ks and lOKs. The former documents
are useful for determining mergers and acquisitions in more detail, and lOKs provide annual balance sheet and
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income statements, as well as listing corporate subsidiaries. The information in the Edgar database as well as
data from the OGJ 200 and D&B (see Section Two) was used to identify parent companies or recent changes of
ownership (for example, Ocean Energy acquired UMC Petroleum in February 1998). Note that EPA's analysis
is based on the status of the industry as of July 1998. Merger and acquisitions continue to occur among this
group of firms.
Table 3-2 shows the results of EPA's search for parent companies and recent acquisitions. Generally,
EPA characterized a firm at the higher level of organization if it was majority owned by the larger entity (except
in a few instances when the subsidiary is large and publicly available information is available for that level of
the corporation; e.g., Vastar, which is about 80 percent owned by ARCO). This approach is consistent with the
Small Business Administration's (SBA's) definition of affiliation. Small firms that are affiliated (e.g., 51
percent owned) by firms defined as large by SBA's standards (13CFR Part 121) are not considered small for the
purposes of regulatory flexibility analysis (see Section Six for more details).
Once EPA accounted for these relationships and transactions, EPA's count of potentially affected firms
in the Gulf of Mexico became 96 firms, of which 15 are listed as majors.6 Twelve firms are identified as foreign
owned (not including majors such as Shell Oil, which is affiliated with Royal Dutch/Shell Group), and these
firms are included in the analysis. Nonforeign independents total 69 firms, including those not listed in PennWell
as majors or independents.7 EPA currently has not received information on the names of the firms drilling in the
area between 3 miles and 3 leagues in Texas, but it is likely that most of the same firms that are drilling in
federal waters are also drilling in this area off Texas.
Table 3-3 shows the firms considered affected firms in the Gulf and their relevant financial data. These
data include number of employees, assets, liabilities, and revenues, along with several ratios that provide a
general indication of financial health. Note that blank lines in Table 3-3 indicate firms that are likely to be
privately held and for which no public data are available.
Of these operators drilling in the Gulf, EPA has identified 41 (43 percent) that either meet the Small
Business Administration's definition of a small business (which for the oil and gas extraction industry is
6PennWell Directory.
7Ibid.
3-11
-------
Table 3-2
Companies Drilling in the Federal Offshore
Gulf of Mexico
Name Changes or Ownership Defined
Company as listed in
MMS, 1997
Company listed by
Corporate Parent
AEDC (USA) Inc.
Agip Petroleum Co., Inc.
Amerada Hess Corp.
American Exploration Co.
American Explorer
Amoco Production Co.
Anadarko Petroleum Corp.
Apache Corp.
Apex Oil & Gas, Inc.
Ashland Exploration Holdings, Inc.
ATP Oil & Gas Co.
Aviara Energy Co.
Aviva America, Inc.
Barrett Resources Corp.
Basin Exploration, Inc.
BHP Petroleum (COM), Inc.
Bois d'Arc Operating Corporation
BP Exploration & Oil, Inc.
British-Borneo Exploration, Inc.
BT Operating Co.
Burlington Resources Offshore, Inc.
Cairn Energy USA, Inc.
Gallon Petroleum Operating Co.
CXY Energy Offshore, Inc.
Century Offshore Management Corp.
Chateau Oil and Gas, Inc.
Chevron USA Incorporated
Chieftain International (U.S.), Inc.
CNG Producing Co.
Coastal Oil & Gas Corp.
Cockrell Oil Corp.
Conoco, Inc.
Davis Petroleum Corp.
Elf Exploration, Inc.
Energy Development Corp.
Energy Resources Technology, Inc.
AEDC (USA) Inc.
Agip Petroli (Italy)
Amerada Hess Corp.
S.A. Louis Dreyfus et Cie. (France)
American Explorer
Amoco Corp.
Anadarko Petroleum Corp.
Apache Corp.
Apex Oil & Gas, Inc.
Statoil (Norway)
ATP Oil & Gas Co.
HW & T Acquisition Company
Aviva Petroleum
Barrett Resources Corp.
Basin Exploration, Inc.
BHP Petroleum Pty Ltd. (Australia)
Bois d'Arc Operating Corporation
British Petroleum Co. pic (U.K.)
British-Borneo Petroleum Syndicate, pic (U.K.)
BT Operating Co.
Burlington Resources Co.
Meridian Resource Corp.
Gallon Petroleum Co.
Canadian Occidental Petroleum Ltd.
Century Offshore Management Corp.
Chateau Oil and Gas, Inc.
Chevron USA Incorporated
Chieftain International, Inc. (Canada)
Consolidated Natural Gas Co.
The Coastal Corp.
Cockrell Oil Corp.
E.I. duPont de Nemours
Davis Petroleum Corp.
Elf Aquitaine (France)
Noble Affiliates
Cal Dive International Inc.
3-12
-------
Table 3-2 (continued)
Company as listed in
MMS, 1997
Company listed by
Corporate Parent
Enron Oil & Gas Co.
Enserch Exploration, Inc.
EEX Corporation
Equitable Resources Energy Co.
Exxon Corp.
Falcon Offshore Operating Co.
Fina Oil and Chemical Co.
Flextrend Development Co., LLC
Forcenergy GOM, Inc.
Forcenergy, Inc.
Forest Oil Corp.
Freeport-McMoRan Resource Partners, LLC
F-W Oil Interests, Inc.
Global Natural Resources Corp.
Gulfstar Energy, Inc.
Hall-Houston Oil Co.
Houston Exploration Co.
IP Petroleum Co., Inc.
Kelley Oil
Kerr-McGee Corp.
Kerr-McGee Oil & Gas Corp.
King Ranch Energy, Inc.
King Ranch Oil and Gas, Inc.
Linder Oil Co., A Partnership
Louisiana Land & Exploration
LLOG Exploration Offshore, Inc.
Louis Dreyfus Natural Resources
Louis Dreyfus Natural Gas Corp.
Marathon Oil Co.
Mariner Energy, Inc.
Matrix Oil & Gas, Inc.
McMoRan Oil & Gas Co.
Mobil Oil Exploration & Production South, Inc.
Mobil Producing Texas & New Mexico, Inc.
Murphy Exploration & Production Co.
NCX Company, Inc.
Newfield Exploration Co.
Enron Oil & Gas Co.
EEX Corporation
EEX Corporation
Equitable Resources, Inc.
Exxon Corp.
Falcon Offshore Operating Co.
Fina
Flextrend Development Co., LLC
Forcenergy, Inc.
Forcenergy, Inc.
Forest Oil Corp.
McMoRan Oil & Gas Co.
F-W Oil Interests, Inc.
Seagull Energy Corp.
Domain Energy Corp.
Hall-Houston Oil Co.
Houston Exploration Co.
International Paper
Kelley Oil
Kerr-McGee Corp.
Kerr-McGee Corp.
King Ranch Energy, Inc.
King Ranch Energy, Inc.
Linder Oil Co., A Partnership
Burlington Resources Corp.
LLOG Exploration Offshore, Inc.
S.A. Louis Dreyfus et Cie. (France)
S.A. Louis Dreyfus et Cie. (France)
USX-Marathon Group
Mariner Energy, Inc.
Matrix Oil & Gas, Inc.
McMoRan Oil & Gas Co.
Mobil Oil Corp.
Mobil Oil Corp.
Murphy Oil Co.
NCX Company, Inc.
Newfield Exploration Co.
3-13
-------
Table 3-2 (continued)
Company as listed in
MMS, 1997
Company listed by
Corporate Parent
Nippon Oil Exploration USA, Ltd.
Norcen Explorer, Inc.
Ocean Energy, Inc.
OEDC Exploration & Production, L.P.
Oryx Energy Co.
OXY USA, Inc.
Panaco, Inc.
Pel-Tex Oil Co.
Pennzoil Exploration & Production Co.
Petrobras America, Inc.
Petsec Energy, Inc.
Phillips Petroleum Co.
Pioneer Natural Resources (GPC), Inc.
Pioneer Natural Resources USA, Inc.
Pogo Producing Co.
Reading & Bates Development Co.
Samedan Oil Corp.
Santa Fe Energy Resources, Inc.
Seagull Energy E&P, Inc.
Seneca Resources Corp.
Shell Deepwater Development, Inc.
Shell Deepwater Production, Inc.
Shell Offshore, Inc.
Shell Frontier Oil & Gas, Inc.
SOCO Offshore, Inc.
SONAT Exploration, Inc.
Sonat Exploration GOM, Inc.
Statoil Exploration (US), Inc.
Stone Energy Corp.
Tana Oil and Gas Corp.
Tatham Offshore, Inc.
Taylor Energy Co.
Texaco Exploration & Production, Inc.
Total Minatome Corp.
TDC Energy Corp.
Transworld Exploration and Production
Nippon Oil (Japan)
Union Pacific Resources Group, Inc.
Ocean Energy, Inc.
Offshore Energy Development Corp.
Oryx Energy Co.
Occidental Petroleum Corp.
Panaco, Inc.
Pel-Tex Oil Co.
Pennzoil Co.
Petroleo Brasileiro SA
Petsec Energy, Inc.
Phillips Petroleum Co.
Pioneer Natural Resources, Inc.
Pioneer Natural Resources, Inc.
Pogo Producing Co.
R&B Falcon
Noble Affiliates
Santa Fe Energy Resources, Inc.
Seagull Energy Corp.
National Fuel Gas Co.
Shell Oil Co.
Shell Oil Co.
Shell Oil Co.
Shell Oil Co.
Snyder Oil Co.
SONAT, Inc.
SONAT, Inc.
Statoil (Norway)
Stone Energy Corp.
TRT Holdings, Inc.
Deeptech, Inc.
Taylor Energy Co.
Texaco, Inc.
Total (France)
TDC Energy Corp.
Transworld Exploration and Production
3-14
-------
Table 3-2 (continued)
Company as listed in Company listed by
MMS, 1997 Corporate Parent
UMC Petroleum Corp. Ocean Energy, Inc.
Union Oil Co. of California Unocal Corp.
Union Pacific Resources Co. Union Pacific Resources Group, Inc.
Vastar Resources, Inc. Vastar Resources, Inc.
W & T Offshore, Inc. W & T Offshore, Inc.
Walter Oil & Gas Corp. Walter Oil & Gas Corp.
Sources: U.S. Department of the Interior, Minerals Management Service,
TIMS database, Herndon, VA, MMS 97-0007, 1997; SEC's EDGAR Database at http:\\www.sec.gov
U.S. EPA Facility Index System Dun & Bradstreet Detail, 1998.
3-15
-------
Table 3-3
Financial Data on Operators in the Gulf of Mexico ($l,OOOs)
Operator
AEDC (USA) Inc.
Agip Petroli (Italy)
Amerada Hess Corp.
American Explorer
Amoco Corp.
Anadarko Petroleum Corp.
Apache Corp.
Apex Oil & Gas, Inc.
ATP Oil & Gas Co.
Aviva Petroleum
Barrett Resources
Basin Exploration
BHP Petroleum Pty Ltd. (Australia)
Bois d'Arc Operating Corporation
British Petroleum Co. pic (U.K.)
British-Borneo Petroleum Syndicate, pic (U.K.)
BT Operating Co.
Burlington Resources Corp.
Cal Dive International, Inc.
Gallon Petroleum Co.
Cal Resources, LLC
Canadian Occidental Petroleum Ltd.
Century Offshore Management Corp.
Chateau Oil and Gas, Inc.
Chevron USA Incorporated
Chieftain International, Inc. (Canada)
Cockrell Oil Corp.
Consolidated Natural Gas Co.
Davis Petroleum Corp.
Deeptech, Inc.
Domain Energy Corp.
EEX Corporation *
Elf Aquitaine (France)
Enron Oil & Gas Co.
Equitable Resources, Inc.
Exxon Corp.
E.I. duPont de Nemours
Falcon Offshore Operating Co.
Fina
Flextrend Development Co., LLC
Forcenergy, Inc.
Size
S
L
L
S
L
L
L
S
S
S
S
S
L
S
L
L
S
L
S
S
S
L
S
S
L
L
S
L
S
S
S
L
L
L
L
L
L
S
L
S
S
Type
Independent
Foreign
Major
Independent
Major
Major
Independent
Independent
Independent
Independent
Independent
Independent
Foreign
Independent
Foreign
Foreign
Independent
Independent
Independent
Independent
Independent
Foreign
Independent
Independent
Major
Foreign
Independent
Independent
Independent
Independent
Independent
Independent
Foreign
Major
Independent
Major
Independent
Independent
Independent
Independent
Independent
No. of
Employees
8
501
9,216
18
41,700
1,229
1,287
3
12
10
207
61
501
3
15,000
501
35
1,819
400
143
na
501
20
2
39,362
40
45
7,194
14
67
52
65
501
7,000
1,978
79,000
16,000
3
14,675
3
275
Assets
na
$16,948,000
7,934,619
na
32,489,000
2,992,465
4,138,633
na
na
16,445
872,701
161,959
29,259,400
na
54,576,000
266,000
na
5,821,000
125,600
190,421
na
344,560
na
na
35,473,000
278,550
na
6,313,700
na
97,130
212,549
807,789
42,252,000
23,422,000
2,411,010
96,064,000
15,692,000
na
3,014,674
na
824,230
Equity
na
na
$3,215,699
na
16,319,000
1,116,780
1,729,177
na
na
3,748
412,381
121,365
na
na
na
na
na
3,016,000
89,369
113,701
na
na
na
na
17,472,000
249,466
na
2,358,300
na
18,862
132,034
274,663
na
5,618,000
823,520
43,660,000
na
na
1,277,112
na
214,991
Revenues
$26,104
7,283,000
8,340,046
1,800
36,287,000
675,139
1,176,273
12,000
160
9,848
382,600
24,720
18,351,500
280
71,274,000
61,000
4,819
2,000,000
109,386
43,638
na
165,710
16,583
162
41,950,000
72,055
4,000
5,710,000
2,000
16,183
52,268
314,787
45,087,100
20,273,000
2,151,015
137,242,000
20,579,000
190
4,468,547
300
287,539
Net Income
na
$1,257,000
7,500
na
2,720,000
107,318
154,896
na
na
(22,482)
29,261
2,456
968,800
na
4,051,000
16,000
na
319,000
14,482
8,437
na
28,470
na
na
3,256,000
10,160
na
304,400
na
790
3,163
(216,103)
961,000
105,000
78,057
8,460,000
860,000
na
126,401
na
(134,818)
Return
on Assets
na
7.4%
0.1%
na
8.4%
3.6%
3.7%
na
na
-136.7%
3.4%
1.5%
3.3%
na
7.4%
6.0%
na
5.5%
11.5%
4.4%
na
8.3%
na
na
9.2%
3.6%
na
4.8%
na
0.8%
1.5%
-26.8%
2.3%
0.4%
3.2%
8.8%
5.5%
na
4.2%
na
-16.4%
Return
on Equity
na
na
0.2%
na
16.7%
9.6%
9.0%
na
na
-599.8%
7.1%
2.0%
na
na
na
na
na
10.6%
16.2%
7.4%
na
na
na
na
18.6%
4. 1%
na
12.9%
na
4.2%
2.4%
-78.7%
na
1.9%
9.5%
19.4%
na
na
9.9%
na
-62.7%
Profit Margin
(net income to
total revenue)
na
17.3%
0.1%
na
7.5%
15.9%
13.2%
na
na
-228.3%
7.6%
9.9%
5.3%
na
5.7%
26.2%
na
16.0%
13.2%
19.3%
na
17.2%
na
na
7.8%
14.1%
na
5.3%
na
4.9%
6. 1%
-68.7%
2.1%
0.5%
3.6%
6.2%
4.2%
na
2.8%
na
-46.9%
3-16
-------
Table 3-3 (continued)
Operator
Forest Oil Corp.
F-W Oil Interests, Inc.
Hall-Houston Oil Co.
Houston Exploration Co. *
HW & T Acquisition Company
International Paper
Kelley Oil
Kerr-McGee Corp.
King Ranch Energy, Inc.
Linder Oil Co., A Partnership
LLOG Exploration Offshore, Inc. *
Mariner Energy, Inc.
Matrix Oil & Gas, Inc.
McMoRan Oil & Gas Co. *
Meridian Resource Corp.
Mobil Oil Corp.
Murphy Oil Co.
National Fuel Gas Co.
NCX Company, Inc.
Newfield Exploration Co.
Nippon Oil (Japan)
Noble Affiliates
Occidental Petroleum Corp.
Ocean Energy, Inc.
Offshore Energy Development Co. *
Oryx Energy Co.
Panaco, Inc.
Pel-Tex Oil Co.
Pennzoil Co.
Petroleo Brasileiro SA
Petsec Energy, Inc.
Phillips Petroleum Co.
Pioneer Natural Resources, Inc.
Pogo Producing Co.
R&B Falcon
Santa Fe Energy Resources, Inc.
Seagull Energy Corp.
Shell Oil
Size
S
S
L
L
S
L
S
L
S
S
L
S
S
L
S
L
L
L
S
S
L
L
L
L
L
L
S
S
L
L
S
L
L
S
L
L
L
L
Type
Independent
Independent
Independent
Independent
Independent
Independent
Independent
Major
Independent
Independent
Independent
Independent
Independent
Independent
Independent
Independent
Major
Independent
Independent
Independent
Foreign
Independent
Independent
Independent
Independent
Independent
Independent
Independent
Independent
Foreign
Independent
Major
Independent
Independent
Independent
Independent
Major
Major
No. of
Employees
177
20
25
104
85
82,000
81
3,851
30
18
35
48
20
16
60
42,700
1,339
2,524
11
86
501
614
12,380
670
18
1,046
40
25
10,036
501
53
17,200
1,321
160
5,700
1,209
950
19,400
Assets
$647,782
na
na
491,391
na
27,753,000
322,602
3,096,000
na
na
na
212,577
na
101,088
292,558
43,559,000
2,238,319
2,267,331
na
553,621
22,763,400
1,875,484
15,282,000
1,707,963
50,941
2,108,000
179,629
na
4,405,887
34,220,700
234,104
13,860,000
3,946,590
676,617
1,034,683
788,900
1,411,066
29,601,000
Equity
$261,827
na
na
256,187
na
8,793,000
(5,621)
1,440,000
na
na
na
57,174
na
90,698
145,102
19,461,000
1,079,351
913,704
na
292,048
na
812,989
4,286,000
764,671
41,571
157,000
55,188
na
1,138,539
na
48,635
4,814,000
1,548,845
146,106
504,614
454,700
647,204
14,878,000
Revenues
$339,641
2,200
47,206
117,646
19,100
9,896,000
76,138
1,711,000
3,500
2,000
25,000
64,050
2,200
13,552
58,333
65,906,000
2,137,767
1,269,008
4,452
200,521
22,020,000
1,116,623
8,101,000
560,232
21,563
1,197,000
38,586
2,200
2,654,304
27,944,000
125,100
15,424,000
546,029
286,753
291,360
517,200
552,313
28,959,000
Net Income
($9,270)
na
na
23,250
na
(385,000)
1,951
194,000
na
na
na
(20,210)
na
(10,538)
(28,541)
3,272,000
132,406
114,688
na
40,603
104,100
99,278
668,000
37,936
6,450
170,000
43
na
175,067
1,353,000
13,100
959,000
(890,671)
37,116
48,453
54,700
49,130
2,104,000
Return
on Assets
-1.4%
na
na
4.7%
na
-1.4%
0.6%
6.3%
na
na
na
-9.5%
na
-10.4%
-9.8%
7.5%
5.9%
5.1%
na
7.3%
0.5%
5.3%
4.4%
2.2%
12.7%
8.1%
0.0%
na
4.0%
4.0%
5.6%
6.9%
-22.6%
5.5%
4.7%
6.9%
3.5%
7.1%
Return
on Equity
-3.5%
na
na
9.1%
na
-4.4%
-34.7%
13.5%
na
na
na
-35.3%
na
-11.6%
-19.7%
16.8%
12.3%
12.6%
na
13.9%
na
12.2%
15.6%
6.8%
15.5%
108.3%
0.1%
na
15.4%
na
26.9%
19.9%
-57.5%
25.4%
9.6%
12.0%
7.6%
14.1%
Profit Margin
(net income to
total revenue)
-2.7%
na
na
19.8%
na
-3.9%
2.6%
11.3%
na
na
na
-31.6%
na
-77.8%
-48.9%
5.0%
6.2%
9.0%
na
20.2%
0.5%
8.9%
8.2%
6.8%
29.9%
14.2%
0.1%
na
6.6%
4.8%
10.5%
6.2%
-163.1%
12.9%
16.6%
10.6%
8.9%
7.3%
3-17
-------
Table 3-3 (continued)
Operator
Snyder Oil Co.
SONAT, Inc.
Statoil (Norway)
Stone Energy Corp.
S.A. Louis Dreyfus et Cie. (France)
Taylor Energy Co.
TDC Energy Corp.
Texaco, Inc.
The Coastal Corp.
Total (France)
Transworld Exploration and Production
TRT Holdings, Inc.
Union Pacific Resources Group, Inc.
Unocal Corp.
USX-Marathon Group
Vastar Resources, Inc.
W & T Offshore, Inc.
Walter Oil & Gas Corp. *
Size
S
L
L
S
L
S
S
L
L
L
S
L
L
L
L
L
S
L
Type
Independent
Major
Foreign
Independent
Foreign
Independent
Independent
Major
Major
Foreign
Independent
Independent
Major
Independent
Independent
Independent
Independent
Independent
No. of
Employees
327
2,110
501
90
501
113
20
28,247
13,200
501
na
2,200
1,500
8,394
20,461
1,063
30
33
Assets
$546,088
4,431,514
17,851,600
354,144
733,613
na
na
29,600,000
11,613,100
25,335,400
na
na
4,472,000
7,530,000
10,565,000
1,924,800
na
na
Equity
$263,756
1,635,420
na
156,637
263,693
na
na
12,766,000
3,036,500
na
na
na
1,761,000
2,314,000
3,618,000
505,500
na
na
Revenues
$255,728
4,178,305
17,671,700
70,987
189,505
41,584
8,182
46,667,000
12,166,900
32,781,000
na
200,000
1,925,000
6,064,000
15,754,000
1,013,700
3,700
50,000
Net Income
$32,617
175,920
610,800
11,919
21,102
na
na
2,664,000
402,600
1,305,700
na
na
333,000
581,000
456,000
240,500
na
na
Return
on Assets
6.0%
4.0%
3.4%
3.4%
2.9%
na
na
9.0%
3.5%
5.2%
na
na
7.4%
7.7%
4.3%
12.5%
na
na
Return
on Equity
12.4%
10.8%
na
7.6%
8.0%
na
na
20.9%
13.3%
na
na
na
18.9%
25.1%
12.6%
47.6%
na
na
Profit Margin
(net income to
total revenue)
12.8%
4.2%
3.5%
16.8%
11.1%
na
na
5.7%
3.3%
4.0%
na
na
17.3%
9.6%
2.9%
23.7%
na
na
Source: Oil & Gas Journal. OGJ 200, 1998; Pennwell Petroleum Directory, 1998; SEC's Edgar Database at http:\\www.sec.gov.; U.S. EPA Facility Index System Dun & Bradstreet Detail 1998.
3-18
-------
defined as a business entity with 500 or fewer employees or for the oil field service industry as a business entity
with $5 million or less in annual revenues) or that cannot be identified as large because their employment or
revenue figures are not known. These latter firms might be privately owned, or they do not file with the SEC as
an independent firm but their parent company could not be identified. The small and unknown-sized firms are
discussed in more detail in Section Six, Regulatory Flexibility Analysis.
Note that operators owned by foreign firms are assumed to be large, even when data on employment
could not be found, for the following reasons. First, SBA defines a small business as one "with a place of
business in the United States, and which operates primarily in the United States or which makes a significant
contribution to the economy" (13 CFR Part 121). EPA assumes that if the U.S. firm is foreign-owned, it
would not meet these criteria. Second, the parent corporation most likely would not meet the size criteria.
Multinational foreign firms operating in the United States typically operate in many other locations throughout
the world and thus would generally require a workforce in excess of 500 persons.
Financially, the potentially affected operators are a healthy group of firms. Table 3-4 presents
summary financial statistics for the large and small firms. Financially, the potentially affected operators are a
healthy group of firms. Among publicly held firms, median return on assets for the group is 4.3 percent,
median return on equity is 10.2 percent, and median profit margin (net income/revenues) is 6.6 percent,
according to 1997 financial data. Among these publicly held firms, 60 out of 69 firms, or 87 percent,
reported positive net income for 1997.
3.3.1.4 Estimates of Drilling Activity
Table 3-5 presents data from MMS on drilling activity in 1995, 1996, and 1997 by type of drilling and
by depth. As the table shows, most wells drilled in the Gulf of Mexico Federal OCS are development wells
drilled in less than 1,000 feet of water. Exploratory drilling in waters less than 1,000 ft. deep also makes up a
major portion of wells drilled annually. The numbers of wells drilled has been rising over the 3-year period, and
an average of 1,119 wells were drilled in the Federal OCS during this timeframe.
Data on wells drilled in the state waters off Texas in the 3 miles to 3 leagues area are not included in the
MMS count, but the Railroad Commission of Texas (RRC) indicated that 10 wells were drilled in 1996, 5
3-19
-------
Table 3-4
Minimum, Median, and Maximum Financial Data for Large and Small Firms ($ 1,000s)
No. of
Employees
Assets
Equity
Revenues
Net Income
Return on
Assets
Return on
Equity
Profit Margin
(net income to
total revenue)
Small firms
Minimum
Median
Maximum
2
37.5
400
$16,445
$263,331
$872,701
($5,621)
$126,700
$412,381
$160
$16,383
$382,600
($134,818)
$2,810
$40,603
-136.7%
1.5%
11.5%
-599.8%
3.3%
26.9%
-228.3%
6.8%
20.2%
Large firms
Minimum
Median *
Maximum
16
1,339
82,000
$50,941
$4,405,887
$96,064,000
$41,571
$812,989
$43,660,000
$13,552
$2,151,015
$137,242,000
($890,671)
$154,896
$8,460,000
-26.8%
4.4%
12.7%
-78.7%
9.5%
108.3%
-163.1%
6.2%
29.9%
All firms
Minimum
Median *
Maximum
2
400
82,000
$16,445
$2,267,331
$96,064,000
($5,621)
$705,938
$43,660,000
$160
$286,753
$137,242,000
($890,671)
$99,278
$8,460,000
-136.7%
4.3%
12.7%
-599.8%
10.2%
108.3%
-228.3%
6.6%
29.9%
Source: Oil & Gas Journal. OGJ 200, 1998; Pennwell Petroleum Directory, 1998; SEC's Edgar Database at http:\\www.sec.gov.; U.S. EPA
Facility Index System Dun & Bradstreet Detail, 1998.
* Used hypothetical number (501) for employees for larger firms when number of employees was not available.
3-20
-------
Table 3-5
Number of Wells Drilled in the Gulf of Mexico OCS and Texas
Where Controlled Discharge of Drilling Fluids and Cuttings Is Allowed
Year
1995
1996
1997
Annual Average OCS
Estimated Wells Drilled
3 Miles to 3 Leagues
Offshore TX
Total Annual Estimate
Shallow Water Wells
(<1,000 feet)
Development
577
617
726
640
5
645
Exploratory
314
348
403
355
3
358
Deep Water Wells
(>1,000 feet)
Development
32
42
69
48
0
48
Exploratory
52
73
104
76
0
76
Total Wells
975
1,080
1,302
1,119
8
1,127
Source: MMS TIMS data and personal communication with RRC (James Covington, EPA, and Donna Burks, RRC, Sept. 1, 1998).
5-21
-------
in 1997, and 9 so far in 1998 in the Texas offshore region (which includes everything offshore, including less
than 3 miles from shore) or an average of 8 wells per year (communication between James Covington, EPA, and
Donna Burks, RRC, September 1, 1998).8 When this number of wells is added to the OCS numbers, EPA
projects that a total of 1,127 wells on average are drilled per year in the Gulf. EPA also estimates that 10
percent, or 113 wells, are drilled currently with SBFs and 10 percent, or 112 wells, are drilled with OBFs. EPA
further estimates that no OBFs are used in deep water drilling, and of the 112 OBF wells estimated to be drilled
annually in shallow water, 20 percent, or 23 wells, would convert to using SBFs if discharge of SBF-cuttings
was allowed.9 The remaining 902 wells that are estimated to be drilled annually in the Gulf of Mexico are
assumed to be drilled exclusively using WBFs and thus would not incur costs or realize savings under this
proposed rule.
3.3.2 Offshore California
Most production activity in the Offshore California region is occurring in an area 3 to 10 miles from
shore off of Santa Barbara and Long Beach, California.
3.3.2.1 Current Practice
Currently, no wells use SBF or discharge SBF-cuttings in the California OCS region. As noted in
Section Two, the General Permit expired, and no wells have been drilled with an individual permit since 1993.
Newer SBFs are not believed to be used in California at this time, although oil-based fluids are used.10
8These are not NPDES CWA permits, but permits issued by the state of Texas.
9SBF Development Document.
wlbid.
3-22
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3.3.2.2 Platforms in the Region
Currently 23 platforms operate on the California OCS, of which two are processing platforms only. All
are located greater than 3 miles from shore, with Platform Grace located the farthest from shore at 10.5 miles.
Most of the platforms are located in the Santa Barbara Channel, with a few located in the Santa Maria Basin,
and several offshore Long Beach, CA. The largest platform, Platform Gilda, has 96 well slots. The smallest
platform, Platform Gina, has 15 well slots.11
3.3.2.3 Operators
There are five operators currently actively drilling (1995-1997) in the California Offshore OCS region.12
These operators are Chevron; Aera Energy, LLC; Exxon; Torch Energy Advisors (through their subsidiary
Torch Operating Co.); and Nuevo Energy Co. (which has an affiliation with Torch, who operates the platforms).
Detailed employment and financial information on Torch Energy Advisors (other than employment) and Aera
Energy is not available. Table 3-6 presents the available data on the five operators. As the table shows,
Chevron, Exxon, and Torch are large firms, and Nuevo by affiliation with Torch is also considered large (Nuevo
and Torch have the same headquarters, and Nuevo lists Torch's employment along with their own in their 10K
form, among other evidence of affiliation), while Aera Energy could not be found in the SEC Edgar database
and is thus assumed small for lack of data. Among the remaining firms, median return on assets is 7.5 percent,
median return on equity is 16.7 percent, and median profit margin is 5.2 percent. No operators reported
negative net income among publicly held firms. Thus, the California firms, like the Gulf firms, generally appear
to be financially healthy.
"httpV/www.mms.gov/pacific/explorat/plfintro.html
12MMS, TIMS database.
3-23
-------
Table 3-6
Financial Information on Operators in the California Offshore Region ($ 1,000s)
Operator
Chevron USA Incorporated
Aera Energy, LLC
Texaco, Inc.
Torch Energy Advisors
Nuevo Energy
Medians
No. of
Employees
39,362
28,247
729
59
14,488
Assets
$35,473,000
29,600,000
904,773
$29,600,000
Equity
$17,472,000
12,766,000
388,867
$12,766,000
Revenues
$41,950,000
46,667,000
358,193
$41,950,000
Net Income
$3,256,000
2,664,000
18,751
$2,664,000
Return on
Assets
9.2%
9.0%
2.1%
9.0%
Return on
Equity
18.6%
20.9%
4.8%
18.6%
Profit Margin
(net income to
total revenue)
7.8%
5.7%
5.2%
5.7%
Source: Oil & Gas Journal. OGJ 200, 1998; Pennwell Petroleum Directory, 1998; SEC's Edgar Database at http:\\www.sec.gov.; U.S. EPA Facility
Index System Dun & Bradstreet Detail, 1998.
3-24
-------
3.3.2.4 Drilling Activity
In offshore California waters, no exploratory wells were drilled in the three years 1995-1997.13 In 1995,
15 development wells were drilled in water depths greater than 1,000 ft and 4 were drilled in water depths of 999
ft or less (19 wells total). In 1996, the number of wells drilled grew to 16 wells in greater than 1,000 ft of water
and 15 wells in 999 ft or less (31 wells total). In 1997 the number of wells drilled dropped slightly, with 14
wells drilled in greater than 1,000 ft of water and 14 wells in 999 ft or less (28 wells total). Thus EPA estimates
that an average of 26 development wells and no exploratory wells are drilled in the California OCS each year.
EPA further estimates that 12 wells are drilled using OBFs each year (none are drilled using SBFs) and that
these wells would be drilled with SBFs if the SBF Guidelines allow discharge of SBFs.14
3.3.3 Cook Inlet, Alaska
Cook Inlet, Alaska, is divided into two regions, Upper Cook Inlet, which is in state waters and is
governed by the Coastal Oil and Gas effluent guidelines and Lower Cook Inlet, which is considered Federal
OCS waters and is governed by the Offshore Oil and Gas Effluent Guidelines. Lower Cook Inlet is discussed as
part of the Alaska Offshore region in Section 3.3.4 below. This section refers to Upper Cook Inlet only. Figure
3-2 shows the configuration of operations in Cook Inlet relative to the Kenai Peninsula and Anchorage, with the
dividing line between the Coastal and Offshore Regions shown.
3.3.3.1 Current Practice
Most drilling in Cook Inlet takes place at the platforms. Exploratory drilling, such as that undertaken in
the Sunfish Field a few years ago, generally is conducted from jackup rigs, which are barge-mounted rigs with
extendable legs that are retracted during transport. At the drill site, the legs are extended to the floor of the
waterbody, gradually lifting the barge hull above the water.
13MMS, TIMS Database.
14SBF Development Document.
3-25
-------
N
Production Platform
On Shore
Separation Facility
• Subsea Pipeline
Susitna
River
Knik Arm
AREA OF
DETAIL
0
l_
20
i
i'rnate Scate
(Statute Mites)
Inner
Boundary of
Territorial Sea
Gulf of Alaska
Bermen Islands
Figure 3-2. Map of Cook Inlet region.
3-26
-------
Currently no operators are believed to be using SBFs in Cook Inlet.15 The General Permit for Cook
Inlet is expected not to allow discharge of SBF-cuttings, but the permit will be reopened when effluent guidelines
or guidance are provided to address discharge of SBFs. At least one operator has requested to discharge SBF-
cuttings.16
3.3.3.2 Platforms
Fifteen platforms are located in Cook Inlet, Alaska (see Figure 3-2). However, at least two of these
platforms are currently shut in. An additional platform might also be shut in, but this information was not
confirmed at this time.17 Table 3-7 presents data on number of wells, production, and operator for each of the
active and nonactive platforms as of 1995. As shown, there are 197 oil wells and 27 gas wells in Cook Inlet,
with an annual production of 13.7 million barrels of oil and 140,525 million Mcf (thousand cubic feet) of
marketable gas in 1995.18 A potential area of development in Cook Inlet is the Sunfish field, which is located in
North Upper Cook Inlet. At this time the Sunfish Field development is underway at the Tyonek platform, and no
new platforms are planned. The last platform constructed in Cook Inlet was built in the late 1980s.19
3.3.3.3 Operators
Three operators are currently active in Cook Inlet: Unocal, Phillips, and Shell (as Shell Western).20 All
three are major integrated oil firms, and all three also operate in the Gulf of Mexico. ARCO also has
15API, 1998. Responses to Technical Questions for Oil and Gas Exploration and Production
Industry Representatives. Email from Mike Parker, Exxon, to Joe Daly, U.S. EPA, August 7, 1998.
16John Veil, 1998. "Data Summary of Offshore Drilling Waste Disposal Practices." November,
1998.
17 Coastal EIA.
18 Ibid.
19Coastal EIA.
20Ibid
3-27
-------
TABLE 3-7
PLATFORMS, OPERATORS, AND WELLS IN COOK INLET
Platform
King Salmon
Monopod
Grayling
Granite Point
Dillon
Bruce
Anna
Baker
Dolly Varden
Spark*
Steelhead
Spurr*
SWEPI "A"
SWEPI "C"
Tyonek "A"
Operator
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Shell Western
Shell Western
Phillips
No. of
Active
Oil
Wells
19
22
23
11
10
13
23
14
24
0*
4
0*
17
17
0
No. of
Active
Gas
Wells
1
0
1
0
0
0
0
2
1
0*
9
0*
0
0
13
Oil
Production
(barrels per
day)
3,864
1,981
5,207
6,086
841
865
3,117
1,301
4,983
0
4,184
0
3,200
1,800
0
Gas
Production
(Mcf/day)
Plat, use
Plat, use
Plat, use
Plat, use
0
Plat, use
Plat, use
Plat, use
Plat, use
0
165,000
0
Plat, use
Plat, use
22,000
Discharge
Location
Trading
Bay
Trading
Bay
Trading
Bay
Granite
Point
Platform
Platform
Platform
Platform
Trading
Bay
Platform
Trading
Bay
Granite
Point
E. Foreland
E. Foreland
Platform
* Spark and Spurr are considered completely nonactive in this EA. One additional platform might also have
shut in since these data were compiled.
Source: U.S. EPA. 1996. Development Document for Final Effluent Limitations Guidelines and
Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category.
3-28
-------
been involved in exploratory drilling in the Sunfish Field, but Alaska state data indicate that Phillips has
bought out ARCO's interests in this field 21 and is pursuing drilling from its Tyonek platform.22 Unocal is the
largest producer of oil in the Upper Cook Inlet region. This operator owned 12 of the 15 platforms (9
believed to be currently active) and produced 86 percent of the oil in the Inlet in 1995. Phillips is the major
producer of gas, with its one Tyonek platform, producing 57 percent of the region's marketable gas in 1995.
Shell, through its subsidiary Shell Western operates SWEPIA and B platforms.23 Table 3-8 presents relevant
financial information on these operators. Median return on assets for this group is 7.1 percent, median
return on equity is 14.1 percent, and median profit margin is 7.3 percent. No firm reported negative net
income in 1997. Again, these firms appear financially healthy.
3.3.3.4 Estimates of Drilling Activity in the Region
Over the past three years (1995-1997) operators have drilled seven wells on average—five
development and two exploration wells.24 Based on discussions with industry (see Coastal EIA), EPA
estimates that no off-platform drilling will be undertaken in Cook Inlet. Thus for the purpose of this report,
EPA assumes seven wells per year will be drilled in Cook Inlet, and all are considered existing sources. EPA
further assumes that one well is drilled annually with OBFs and that SBFs would replace OBFs if the SBF
Guidelines allow discharge of SBF-cuttings.25
3.3.4 Offshore Alaska
The offshore Alaska region comprises several areas, which are located both in state waters and in
federal OCS areas. The most active area for exploration has been the Beaufort Sea, the northernmost
21http:www.dnr.state.ak.us\oil\data\wells.htm, page 14.
22Coastal EIA.
23Ibid
24SBF Development Document.
25Ibid.
3-29
-------
Table 3-8
Financial Data on Operators in Cook Inlet ($ 1,000s)
Operator
Phillips Petroleum Co.
Shell Oil
Unocal Corp.
Medians
No. of
Employees
17,200
19,400
8,394
17,200
Assets
13,860,000
29,601,000
7,530,000
$13,860,000
Equity
15,424,000
14,878,000
2,314,000
$14,878,000
Revenues
15,424,000
28,959,000
6,064,000
$15,424,000
Net Income
959,000
2,104,000
581,000
$959,000
Return on
Assets
6.9%
7.1%
7.7%
7.1%
Return on
Equity
6.2%
14.1%
25.1%
14.1%
Profit Margin
(net income to
total revenue)
6.2%
7.3%
9.6%
7.3%
Source: Oil & Gas Journal. OGJ 200, 1998; Pennwell Petroleum Directory, 1998; SEC's Edgar Database at httpAYwww.sec.gov.; U.S. EPA Facility
Index System Dun & Bradstreet Detail, 1998.
3-30
-------
offshore area on the Alaska coastline. Other areas where some exploration has occurred include Chukchi Sea to
the northwest, Norton Sound to the West, Navarin Basin to the west, St. George Basin to the southwest, lower
Cook Inlet to the south, and Gulf of Alaska along the Alaska panhandle (see Figure 3-3). The only commercial
production of any note is occurring in the Beaufort Sea region.26
3.3.4.1 Current Practice
To EPA's knowledge, no operations are discharging any drilling fluids, including WBFs, in the offshore
Alaska region. No discharge is occurring in state waters due to state law requiring operators to meet zero
discharge. In the federal offshore region, the Offshore Guidelines do not specifically prohibit discharge of SBF-
cuttings, but all operators historically have injected their drilling wastes. No commercial production has
occurred in any federal offshore area.27 Some promising finds have been made in federal offshore water in
recent years, but development may be several years off. These fields include the Liberty (Tern Island) Field and
the Northstar Field, both in the Beaufort Sea. Currently a draft Environmental Impact Statement (EIS) is being
prepared for the Liberty Field (DNR). The Northstar Field has encountered significant resistance to
development.28 The operator (BP) halted construction for over a year as a result of a lawsuit (which was
resolved in May 1998).29 The operator has just begun the task of responding to comments on its draft
environmental impact statement, which must be finalized before production operation can start.30
26http://www.mms.gov/alaska/re/96-0033/10.htm and State of Alaska, Alaska Oil and Gas
Conservation Commission, 1996. 1996 Annual Report.
27http://www.mms.gov/alaska/re/96-0033/10.htm
28"Stop BP's Northstar Project," http://www.greenpeace.org/~climate/arctic/act.html
29"BP Puts Project On Hold," http://www.adn.com/TOPSTORY/T9702141.HTM; "Baxley v.
Alaska DNR (5/15/98)," http://www.touchngo.com/sp/html sp-4988.htm
30http ://www .mms .gov/alaska/cproj ect/northstar/northstar .htm
3-31
-------
Sale Areas Offshore Alaska Where Exploratory Drilling Has Occurred
Area
Beaufort Sea
Chukchi Sea
Norton Sound
Navann Basin
St. George Basin
Cook Inlet
Gulf of Alaska
Total
Wells
Drilled
30
4
1 «
8
1 i°
13
1 12
1.
S3
Chukchi
Sea
St. George
Basin
Beaufort
Sea
Figure 3-3. Map of Alaska offshore exploration areas showing total number of wells drilled to date (1998).
Source: http: //www .mms .gov/alaska/fo/history/salearea.htm
3-32
-------
3.3.4.2 Estimates of Drilling Activity in the Area
Historically, drilling in the offshore Alaska regions has been typically exploratory (with the primary
exception of the Endicott Field development in the Beaufort Sea). Since the beginning of exploration in the
Alaska Offshore region, 83 exploratory wells have been drilled in Federal Offshore waters (see Figure 3-3),
primarily in the Beaufort Sea, where nearly 40 percent of all exploratory wells in the Alaska federal offshore
region have been drilled. Exploratory well drilling in federal waters has slacked off significantly in recent years
(see Figure 3-4). From a peak of about 20 wells per year in 1985, no wells were drilled in 1994, 1995, and
1996, and two were drilled in 1997 for an average of less than one well drilled per year. EPA therefore assumes
that no significant drilling activity will be occurring in the Federal Offshore regions of Alaska. Offshore Alaska,
therefore, is within the scope of the regulation but is not expected to be associated with costs or savings as a
result of the proposed effluent guidelines, either in state offshore waters (because of state law) or in federal
waters (due to historic practice and lack of activity). Wells drilled in this region are not included in the count of
potentially affected wells.
3.4 SUMMARY OF WELL COUNTS AND OPERATOR COUNTS
EPA estimates that a total of 1,160 wells, on average, are drilled each year in the regions potentially
affected by the SBF Guidelines (see Table 3-9). Of these, EPA estimates that 113 wells are drilled, on average,
each year using SBFs in the Gulf (none in California and none in Cook Inlet). EPA further estimates that a total
of 125 wells are drilled annually using OBFs, of which 112 are drilled in the Gulf, 12 in California, and 1 in
Cook Inlet. EPA assumes that a total of 23 wells in shallow water Gulf locations, 12 wells in California, and 1
well in Alaska, for a total of 36 wells annually, would switch from OBFs to SBFs if the SBF Guidelines allow
discharge.31
The number of operators currently drilling wells in the regions total 99 firms, of which 42 (42
percent) are estimated to be small. These operators include the 96 operators in the Gulf of Mexico, and the 3
additional operators in the Pacific (two Pacific operators also drill in the Gulf). All Cook Inlet operators also
31 SBF Development Document.
3-33
-------
25 -i
Total Number of Wells
Drilled Per Year,
Alaska OCS Region
D Exploration
D Strati graphic Test Wells
5:
Figure 3-4. Total number of wells drilled per year, Alaska OCS region.
Source: http://www.mms.gov/alaska/fo/history/allwellc.htm
3-34
-------
Table 3-9
Total Number of Wells Drilled in All Affected Regions
Gulf of Mexico OCS (including Texas state
waters)*
California OCS
Alaska Cook Inlet Coastal
Total, All Regions
Shallow Water Wells
(<1,000 ft)
Developmen
t
645
11
5
661
Exploratory
358
0
2
360
Deep Water Wells
(>1,000 ft)
Developmen
t
48
15
0
63
Exploratory
76
0
0
76
Total
1,127
26
7
1,160
Source: SBF Develoment Document.
Texas wells were apportioned to type and depth using the same proportions as those found among Gulf OCS wells.
-------
drill in the Gulf. These counts will be used in later sections of this report as baseline data for the economic
analysis.
3-36
-------
SECTION FOUR
REGULATORY OPTIONS AND AGGREGATE COSTS
OF THE EFFLUENT GUIDELINES
This section presents the regulatory options considered for offshore drilling operations and the total
costs of compliance for the SBF Guidelines. Only wells that are drilled with SBFs or those drilled with
OBFs that are assumed to convert to SBFs are determined to have costs or realize savings under the
regulation.
4.1 REGULATORY OPTIONS
EPA considered two options for the proposed rule: one is a discharge option allowing SBF cuttings
discharge (discharge of SBF not associated with cuttings would not be allowed and is not current practice)
and a zero discharge option. These options are considered for both existing sources under Best Available
Treatment Economically Achievable (BAT) and new sources, under New Source Performance Standards
(NSPS).1 There is also an implicit no-action option under which zero costs are incurred. See Table 4-1 for
a description of these options and a shortened name that will be used in the EA.
The discharge option involves the discharge of SBF cuttings after treatment by a solids control
device that achieves an average of 7 percent retention of the base fluid on cuttings (see Section 3.2.4.2).
The discharge costs and cost savings include costs for: the add-on solids control device, retrofit of the
drilling platform to accommodate the device, the value of the SBF retained on the cuttings (which generates
the overall cost savings), and monitoring analyses.
'Best Practical Control Technology (BPT) and Best Conventional Pollutant control Technology
(BCT) are associated with no incremental costs so are not discussed in this report. Additionally, there are
no known indirect dischargers so Pretreatment Standards for Existing Sources (PSES) and Pretreatment
Standards for New Sources (PSNS) also are not discussed.
4-1
-------
Table 4-1
Summary of Regulatory Options
Regulation
Option 1
Option 2
Short Option Description
Discharge
Zero Discharge*
Option
• SBF-cuttings alone may be discharged.
• Control of base fluids acceptable for discharge in
terms of polynuclear aromatic hydrocarbon
content, sediment toxicity, and biodegradation
rate.
• Control of SBF retained on cuttings.
• New monitoring methods for formation oil
contamination.
• Maintenance of current stock barite limitations
for cadmium and mercury.
• Maintenance of static sheen test.
• Zero discharge of SBF drilling fluids and SBF-
cuttings.
Current zero discharge requirements are zero discharge within 3 miles of shore, except in Offshore Alaska
and Coastal Cook Inlet Alaska, which allow discharge per limitations.
4-2
-------
The zero discharge option has the potential to generate additional costs, but only for wells in the
Gulf of Mexico because the Alaska and California wells are at zero discharge in the baseline. The SBF
wells in the Gulf of Mexico are discharging, but at an 11% retention of base fluid on cuttings in the
baseline, while OBF-drilled wells are at zero discharge. Thus under the zero discharge option only wells
drilled with SBFs in the Gulf are affected. The zero discharge option is associated with costs to haul
cuttings to shore with land treatment/disposal or to inject the wastes at or near the site of the drilling
operation. EPA's preferred option for this proposal, for both BAT and NSPS, is the discharge option.
4.2 TOTAL COMPLIANCE COSTS
As Table 4-2 shows, total compliance costs for the preferred discharge option are actually cost
savings (due to the value of the drilling fluids captured for recycling). These cost savings amount to $6.6
million per year for BAT and $0.6 million per year for NSPS for a total cost savings of $7.2 million per
year. Under the zero discharge option, costs would be $7.0 million per year under BAT and $1.6 million
per year under NSPS for a total of $8.6 million per year.
4-3
-------
Table 4-2
Incremental Costs/Cost Savings of Compliance
with the SBF Guidelines
(thousands, 1997 dollars)
Option
Discharge
Zero Discharge
BAT
Gulf
($5,985)
$6,964
CA
($509)
$0
AK
($92)
$0
Total
($6,586)
$6,964
NSPS
Gulf
($570)
$1,594
CA
$0
$0
AK
$0
$0
Total
($570)
$1,594
Total
Costs/ Cost
Savings
($7,156)
$8,558
Source: SBF Development Document
4-4
-------
SECTION FIVE
ECONOMIC IMPACTS OF THE PROPOSED RULEMAKING
Under the preferred discharge option, the proposed effluent guidelines would provide a cost savings
to industry. This cost savings would be experienced by wells currently discharging cuttings contaminated
with SBFs and other water non-dispersible fluids and by wells currently land-disposing or injecting OBF
cuttings that convert to SBF. As discussed in Section Four, the cost savings for SBF dischargers result
from the use of improved solids control equipment and the subsequent ability of operators to recycle
additional volumes of expensive SBFs, which more than offsets the costs of the improved solids control
equipment. For wells that would have been drilled with OBF, the cost savings result from switching to
SBF and discharging, thus avoiding higher zero discharge disposal costs. Operations using WBFs would
not be affected by the SBF Guidelines.
For each regulatory option, EPA estimated the change in the cost of drilling wells, impacts on
operating a production unit (typically a platform), impacts on firms, both large and small (impacts on small
firms specifically are discussed in Section Six), employment impacts in the oil and gas industry, and
impacts on related industries (e.g., drilling contractors, drilling fluid companies, mud cleaning equipment
rental firms, transport and disposal firms, etc.) as a result of the proposed BAT and NSPS requirements.
The results of these analyses are summarized below in Section 5.1 (for existing sources) and Section 5.2
(for new sources).
5.1 IMPACTS ON EXISTING SOURCES
5.1.1 Impacts on Costs of Drilling Wells
As discussed in Section Four, under the discharge option, EPA projects aggregate costs savings for
wells using SBFs and for wells using OBFs that convert to SBFs. Table 5-1 shows the four model well
types defined in Section Four and provides estimates of potential costs or cost savings as a percentage of
total costs to drill a well associated with various subsets of these well types. Costs and cost savings vary
5-1
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TABLE 5-1
COST SAVINGS OF THE BAT DISCHARGE OPTION AS A PERCENTAGE OF BASELINE DRILLING COSTS ($1997)
Type of Well
Number
of Wells
Incremental
Cost of
Discharge
Option (per
well)
Incremental
Cost of Zero
Discharge
Option (per
well)
Total
Baseline
Cost of
Drilling Well
($MM)
Cost/Cost Savings as a
Percentage of Total Drilling Cost
Discharge
Option
Zero
Discharge
Option
GULF OF MEXICO
Deep Water SBF Developmental (haul)
Deep Water SBF Developmental
(inject)
Shallow Water SBF Developmental
(haul)
Shallow Water SBF Developmental
(inject)
Shallow Water OBF Developmental
(haul)
Shallow Water OBF Developmental
(inject)
Deep Water SBF Exploratory (haul)
Deep Water SBF Exploratory (inject)
Shallow Water SBF Exploratory (haul)
Shallow Water SBF Exploratory (inject)
14
4
10
2
12
3
46
11
6
1
($29,302)
($29,302)
($17,502)
($17,502)
($36,615)
($6,947)
($70,502)
($70,502)
($41,502)
($41,502)
$95,507
$57,205
$19,113
($10,555)*
$0
$0
$79,813
$127,825
$28,315
($21,950)*
$2.9
$2.9
$2.9
$2.9
$2.9
$2.9
$3.9
$3.9
$4.9
$4.9
-1.0%
-1.0%
-0.6%
-0.6%
-1.3%
-0.2%
-1.8%
-1.8%
-0.8%
-0.8%
3.3%
2.0%
0.7%
-0.4%
0.0%
0.0%
2.0%
3.3%
0.6%
-0.4%
5-2
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TABLE 5-1 (continued)
Shallow Water OBF Exploratory (haul)
Shallow Water OBF Exploratory
(inject)
Type of Well
6
2
Number of
Wells
($69,817)
($19,552)
Incremental
Cost of
Discharge
Option (per
well)
$0
$0
Incremental
Cost of Zero
Discharge
Option (per
well)
$4.9
$4.9
Total
Baseline
Cost of
Drilling Well
($MM)
-1.4%
-0.4%
0.0%
0.0%
Cost/Cost Savings as a
Percentage of Total Drilling Cost
Discharge
Option
Zero
Discharge
Option
CALIFORNIA
Deep Water OBF Developmental
Shallow Water OBF Developmental
11
1
($43,658)
($28,899)
$0
$0
$1.6
$1.6
-2.7%
-1.8%
ALASKA
Shallow Water OBF Developmental
1
($92,266)
$0
$2.8
-3.3%
0.0%
0.0%
0.0%
Note: negative value or values in parentheses represent a cost savings.
*See SBF Development Document for explanation of cost savings.
Source: Development Document, Appendix A, and the Joint Association Survey.
5-3
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depending on the region, the type of fluid currently used, and the operator's choice of zero discharge
(under the zero discharge option only)-hauling to shore for disposal or injecting the waste (the latter, less
expensive option is not technically feasible at all locations). See the SBF Development Document for
detailed information on how the numbers of wells were estimated in each category and Appendix A of this
report for how the aggregate costs of each well type were disaggregated to estimate a per-well cost.
Table 5-1 shows that most cost savings under the preferred discharge option would be about 1 to 2
percent of total well drilling costs, with a few exceptions. Deep water development wells using OBFs in
California would realize cost savings of as much as 2.7 percent of total costs, and the estimated one Alaska
well using OBFs in Cook Inlet would realize a cost savings of 3.3 percent of total well drilling costs. In
general, these cost savings are not a large portion of costs to drill and therefore should have no to at most a
small incentive on well drilling activity.
Under zero discharge, wells using OBFs would incur no incremental costs of compliance since they
already meet zero discharge requirements. Among those currently using SBFs, the median percentage of
compliance costs to the total cost of drilling wells is 2.0 percent.
5.1.2 Impacts on Platforms and Production
Neither the discharge option nor the zero discharge option would have a significant impact on
production decisions on platforms. As noted above, cost savings among operations currently using SBFs
are a small fraction of the overall cost to drill a well in the offshore, so the cost savings associated with the
preferred discharge option would have a small effect on an operator's decisions to drill, although some
small encouragement to drilling may result.
Under EPA's zero discharge option, EPA investigated potential impacts based on previous work
performed as part of the offshore oil and gas effluent guidelines rulemaking.1 The costs of such an option,
compared to the baseline costs of drilling wells in the Gulf are presented in Table 5-1. EPA previously
'Offshore EIA.
5-4
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investigated the impact of zero discharge of all drilling fluids and cuttings on platform-based production
operations in the offshore regions of the Gulf and found, at that time, "none of the options considered ...
[including zero discharge] for drilling fluids and drill cuttings has an adverse impact on hydrocarbon
production." (58 FR 12454-12152). Furthermore, as stated in the Offshore EIA, EPA estimated no change
in the total production for any project (by platform type and location) analyzed under any regulatory
scenario for drilling waste (including zero discharge). EPA believes a similar impact would occur today.
5.1.3 Impacts on Firms
EPA estimated impacts on firms by assessing the costs and cost savings of the regulatory options
as a percentage of revenues. The cost savings associated with the preferred discharge option would have
from no impact to a very small impact on the investment decisions by the majority of the companies
affected by the proposed rule. EPA assumes that the likeliest users of SBF in shallow water locations are
the same operators who use SBF in deep water operations. Only a few operators drill where SBF is
primarily used, in the Gulf deepwater locations. A total of 18 firms (19 percent of the 98 firms considered
potentially affected) drilled in deepwater locations over the period 1995-1997. As Table 5-2 shows, total
cost savings among these firms would probably be at most nearly 0.3 percent of revenues.2 EPA has
assumed for this calculation that these 18 firms' deep water wells would be drilled using SBFs at the
frequency of use for all deep water wells (75 percent of wells are estimated to be drilled currently using
SBF in deep water locations).3 To estimate the number of SBF wells drilled in shallow water by each of
the 18 firms, EPA distributed the shallow water SBF wells according to the ratio of wells drilled by each
firm in shallow water to the total number of wells drilled in shallow water by these 18 firms. For example,
Shell Oil is currently estimated to drill an average of 57 shallow water development wells per year (see
Appendix B). This is 21 percent of the 271 development wells drilled in shallow water by the 18 firms
considered to be likeliest users of SBFs (see Appendix B). As noted earlier, EPA estimated that 12
development wells are drilled annually using SBFs in shallow water. Shell Oil is assumed, therefore, to drill
2Note that cost savings to firms who might switch from OBFs to SBFs are not estimated because
EPA cannot determine which firms might switch.
Development Document.
5-5
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Table 5-2
Estimated Cost or Cost Savings of the Discharge Option and Zero Discharge Option as a Percentage of Revenue, By Potentially Affected Firm
Firms
E.I. duPont de Nemours
Amerada Hess Corp.
Chevron USA Incorporated
Occidental Petroleum Corp.
Amoco Corp.
Union Pacific Resources Group, Inc.
Exxon Corp.
Shell Oil Co.
USX-Marathon Group
Texaco, Inc.
Mariner Energy, Inc.
Elf Aquitaine (France)
Santa Fe Energy Resources, Inc.
British-Borneo Petroleum Syndicate,
British Petroleum Co. pic (U.K.)
Vastar Resources, Inc.
Falcon Offshore Operating Co.
EEX Corporation
Total Cost of the
Discharge Option
($85,825)
($228,399)
($320,706)
($143,179)
($221,011)
($88,675)
($314,678)
($2,010,173)
($214,127)
($645,357)
($60,811)
($37,555)
($105,269)
pic (E1K2)009)
($572,275)
($108,845)
($93,501)
($76,177)
Total Cost of the
Zero Discharge Option
$150,174
$317,700
$624,897
$236,733
$322,062
$97,977
$461,812
$2,888,931
$256,336
$1,044,592
$70,795
$45,802
$119,554
$225,452
$1,105,930
$84,117
$155,751
$202,811
Firm Revenues
(In Milliions)
$20,579
$8,340
$4,195
$1,197
$36,287
$1,925
$137,242
$28,959
$15,754
$46,667
$64
$45,087
$517
$61
$71,274
$1,014
$291
$315
Revenues as % of
Discharge Option Costs
-0.0004%
-0.0027%
-0.0008%
-0.0120%
-0.0006%
-0.0046%
-0.0002%
-0.0069%
-0.0014%
-0.0014%
-0.0949%
-0.0001%
-0.0204%
-0.2492%
-0.0008%
-0.0107%
-0.0321%
-0.0242%
Revenues as % of
Zero Discharge Option Costs
0.0007%
0.0038%
0.0015%
0.0198%
0.0009%
0.0051%
0.0003%
0.0100%
0.0016%
0.0022%
0.1105%
0.0001%
0.0231%
0.3696%
0.0016%
0.0083%
0.0535%
0.0644%
Source: MMS TIMS Database, SBF Development Document, and Appendix B.
5-6
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21 percent of these 12 development wells estimated to be drilled using SBFs in shallow water, or 3 wells.
See Appendix B for more detailed information on numbers of wells drilled by the 18 potentially affected
firms. Appendix B also presents the cost estimates for each firm broken down by type of well. These costs,
when aggregated, equal the costs (with rounding) shown in Table 5-2.
Among the 18 firms likely to be using SBFs (the 18 deepwater drilling firms), costs of zero
discharge of SBF cuttings would be at most 0.4 percent of revenues among these firms, under the same
assumption discussed above. Section Six discusses costs for zero discharge as a percent of revenues for
each potentially affected small firm currently drilling with SBFs and discharging cuttings.
5.1.4 Secondary Impacts
5.1.4.1 Impacts on Employment and Output
EPA anticipates no negative impacts on employment and output (revenues) from the discharge
option because, in the aggregate, cost savings are realized. Changes in employment and output are directly
proportional to costs of compliance (that, is higher costs lead to lower employment and output) thus cost
savings would minimally increase employment and output in the oil and gas industry, but these gains would
be offset by loses elsewhere in the economy (e.g., waste disposal firms). To the extent that any costs
savings might be reinvested in additional drilling or otherwise encourage additional drilling, employment
and output could increase in the oil and gas industry by more than that associated with the costs savings
alone. EPA has not quantified this potentially positive, albeit small, effect. Under the zero discharge option,
the costs of compliance are positive, leading to small loses and employment losses in the oil and gas
industry. These losses, however, would be offset by gains elsewhere in the economy (e.g., waste disposal
firms). The net effect of the rule on the U.S. economy under either option is likely to be close to zero.
To determine impacts on employment and output, EPA uses input-output multipliers developed by
the Bureau of Economic Analysis (BEA).4 Input-output multipliers allow EPA to calculate the total number
4Bureau of Economic Analysis. 1996. "Table A-2.4-Total Multipliers, by Industry Aggregation for
Output, Earnings, and Employment." Regional Input/Output Modeling Systems (RIMS II). Regional
5-7
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of jobs gained or lost throughout the U.S. economy in all industries associated with a change of $1 million
of output in a specific industry and the total amount of output gained or lost throughout the U.S. economy
based on the change in output in the specific industry. Compliance costs or savings resulting from the SBF
Guidelines can be considered equivalent to the change in output for the oil and gas industry.5
The BEA national level employment multiplier relevant to the oil and gas industry is 13.0, which
means for every $1 million output loss, 13 jobs in the U.S. economy will be lost.
Additional output losses (those additional to output losses in the oil and gas industry) can also be
calculated for a full accounting of economic losses because the losses in the oil and gas industry can lead to
additional losses in related industries, such as those providing services to the oil and gas industry. BEA's
final demand output multiplier allows the calculation of the total output loss to the U.S. economy as a
whole based on each million dollar change in output in a particular industry. The relevant BEA output
multiplier for the oil and gas industry is 1.9420, which means for every $1 million of output loss an
additional $942,000 million is lost throughout the U.S. economy.
Table 5-3 presents the results of the analysis of employment and output effects stemming from the
preferred discharge option as well as the zero discharge option. As the table shows, the preferred discharge
option is estimated to result in employment gains of 93 full-time equivalents (1 FTE=2,080 hours and can
be equated with one full-time job) and a gain of $ 13.9 million per year in output for the U.S. economy as a
whole. The zero discharge option is estimated to result in a loss of 111 FTEs and a loss of $16.6 million
per year in output for the U.S. economy as a whole (losses within the oil and gas industry would be less).
Note, however, these are not net losses and gains. Other industries, such as the waste disposal
industry will lose output and employment under the discharge option and will gain output and employment
under the zero discharge option. When these changes are subtracted from changes identified above, both
gains and losses will be reduced. The net impact on output and employment would be close to zero under
Economic Analysis Division.
5For more information on input-output analysis in the oil and gas industry, see the Coastal EIA.
5-8
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Table 5-3
Employment and Output Effects Associated With SBF Guidelines Options ($1997)
Option
Discharge
Zero Discharge
Compliance Cost (+)/
Cost Savings (-)
($ Millions)
-$7.2
+$8.6
Gains (+) or Loss (-)
in Employment*
+93 FTEs
-lllFTEs
Total Gains (+) or Loss
(-) in Output**
($ Millions)
+$13.9
-$16.6
Source: Section Four and Bureau of Economic Analysis. 1996. "Table A-2.4-Total Multipliers, by
Industry Aggregation for Output, Earnings, and Employment." Regional Input/Output Modeling
Systems (RIMS II). Regional Economic Analysis Division.
* Based on 13 jobs gained or lost per $1 million change in output on the affected industry.
** Based on $942,000 additional output changes in other industries in the U.S. for each $1 million change
in output for the oil and gas industry.
5-9
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either option. Even these gross changes in employment and output, however, are very small relative to total
U.S. employment (130 million persons) and gross domestic product ($8.1 trillion) in 19916
5.1.4.2 Secondary Impacts on Associated Industries
EPA qualitatively analyzed the secondary impacts on associated industries from the preferred
option. Impacts on drilling contractors should be neutral to positive, with some increase in employment in
these firms occurring if they reinvest the cost savings. Impacts on firms supplying drilling fluids should be
neutral to positive, since most firms supplying drilling fluids stock both OBFs and SBFs. To the extent
that SBFs have, at a minimum, the same profit margin as OBFs, there would be little to no impacts on
these firms, because SBFs would replace OBFs in some instances under the preferred discharge option. If
drilling increases as a result of reinvestment, some positive impacts might occur.
Firms that provide rental of solids separation systems presumably would purchase and provide
improved solids separation systems once demand for these systems developed with the promulgation of the
rule. Because these more efficient systems would most likely be rented in addition to, rather than in place
of, less efficient systems, impacts on these firms would be positive.
Firms that manufacture the improved solids separation equipment and firms that manufacture
equipment or provide services needed to comply with the new testing requirements will prosper.
The firms providing transport and landfilling or injection of OBF-contaminated cuttings would
sustain economic losses as a result of the rule. Under the preferred option, EPA estimates that waste
generated for disposal by landfill and injection would be reduced by 34 million pounds per year. Under a
zero discharge option, these firms would experience potential economic gains, because more waste (178
million pounds per year) would be generated for land disposal or injection than is currently generated.
6U.S. Government Printing Office. 1998. Economic Report of the President.
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5.1.4.3 Other Secondary Impacts
There will be no measurable impacts on the balance of trade or inflation as the result of this
proposed rule. EPA projects insignificant impacts on domestic drilling and production and, therefore
insignificant impacts on the U.S. demand for imported oil. Additionally, even if there were costs associated
with this rule, the industry has no ability to pass on costs to consumers as price takers in the world oil
market and thus this rule would have no impact on inflation.7
5.2 IMPACTS ON NEW SOURCES
The proposed NSPS option is the same discharge option proposed for BAT. Under the definitions
of new source in the Offshore Oil and Gas Effluent Guidelines, an oil and gas operation is considered a new
source only when significant site preparation work and other criteria are met (see 40 CFR 435.11).
Individual exploratory wells, wells drilled from existing platforms and wells drilled and connected to an
existing separation/treatment facility without substantial construction of additional infrastructure are not
new sources.
As discussed above, the lack of negative economic impacts from allowing SBF discharge leads
EPA to the conclusion that the effluent guidelines are economically achievable for both existing and new
sources. Additionally, on a per-well basis, NSPS is expected to result in greater cost savings than BAT
because new platforms do not require the retrofit costs to enable the improved solids control equipment to
be placed on existing platforms. Because the preferred NSPS option results in cost savings and those cost
savings are greater than those realized by existing operations, there are no barriers to entry. In fact, the
rule might act as an small incentive to new source development (see discussion in Section 5.1.4.1).
7Coastal EIA and Offshore EIA.
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SECTION SIX
REGULATORY FLEXIBILITY ANALYSIS
6.1 INTRODUCTION
This section examines the projected effects of the costs from incremental pollution control on small
entities as required by the Regulatory Flexibility Act (RFA, 5 U.S.C. 601 et seq., Public Law 96-354) as
amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA). The RFA
acknowledges that small entities have limited resources and makes the regulating federal agency responsible
for avoiding burdening such entities unnecessarily. Although EPA has certified that this rule will not have a
significant impact on a substantial number of small entities, EPA has prepared an analysis equivalent to an
initial regulatory flexibility analysis (IRFA).1 Section 6.2 reviews the steps suggested in Agency guidance
materials to determine whether a regulatory flexibility analysis is required and how to identify significant
impacts on small businesses. Section 6.3 responds to the regulatory flexibility analysis components
required for a proposed rule by Section 603 of the RFA. Section 6.4 is a detailed description of the small
business economic analysis performed for the proposed regulation.
6.2 INITIAL ASSESSMENT
The following passage lists the initial assessment steps suggested in current EPA guidance.2 The
steps are posed as a series of questions and answers:
1 The preparation of an IRFA or any small business analysis for a proposed rule does not legally
foreclose certifying no significant impact for the final rule; see U.S. EPA, 1997. Interim Guidance for
Implementing the Small Business Regulatory Enforcement Fairness Act and Related Provisions of the
Regulatory Flexibility Act. February 5.
2 U.S. EPA, 1992. EPA Guidelines for Implementing the Regulatory Flexibility Act. U.S.
Environmental Protection Agency, Office of Policy, Planning, and Evaluation, April; and U.S. EPA, 1997.
Op. cit.
6-1
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Is the Rule Subject to Notice-and-Comment Rulemaking Requirements?
The Effluent Limitations Guidelines for the Synthetic Drilling Fluids is subject to
notice-and-comment rulemaking requirements.
Profile of Affected Entities
EPA prepared a profile of the regulated universe of entities; see Section Three and
Section 6.3.2.
Will the Rule Affect Small Entities?
Yes.
Will the Rule Have an Adverse Economic Impact on Small Entities?
EPA has determined that some small entities might incur costs for incremental pollution
control as a result of the rule, if a zero discharge option were promulgated. EPA
examines the impacts of these additional costs in Section 6.4.
6.3 REGULATORY FLEXIBILITY ANALYSIS COMPONENTS
Section 603 of the RFA requires that an IRFA must contain the following:
• An explanation of why the rule may be needed.
• A short explanation of the objectives and legal basis for the proposed rule.
• A description of, and where feasible, an estimate of the number of small business entities
to which the proposed rule will apply.
• A description of the proposed reporting, recordkeeping, and other compliance requirements
(including an estimate of the types of small entities which will be subject to the
requirement and the type of professional skills necessary for the preparation of the report
or record).
• An identification, to the extent practicable, of all relevant federal rules which may
duplicate, overlap, or conflict with the proposed rule.
• A description of "any significant regulatory alternatives" to the proposed rule which
accomplish the statement objectives of the applicable statutes and which minimize any
significant economic impact of the rule on small entities.
6-2
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6.3.1 Need for and Objectives of the Rule
The rule is being proposed under the authority of Sections 301, 304, 306, 307, 308, and 501 of the
Clean Water Act, 33 U.S.C. Sections 1311, 1314, 1316, 1317, 1318, and 1361. Under these sections, EPA
sets standards for the control of discharge of pollutants for the Offshore and Coastal Oil and Gas Point
Source Subcategories.
The objective of the CWA is to "restore and maintain the chemical, physical, and biological
integrity of the Nation's waters." To assist in achieving this objective, EPA issues effluent limitations
guidelines, pretreatment standards, and new source performance standards for industrial dischargers.
Sections 301, 304, and 306 authorize EPA to issue BPT, BAT, and NSPS regulations for all pollutants.
6.3.2 Estimated Number of Small Business Entities to Which the Regulation Will Apply
The section begins with a discussion of the definition of "small business" for the purpose of
responding to the requirements of the regulatory flexibility analysis, then summarizes the data available for
the estimated number of small business entities and the methodology used in calculating that estimate.
6.3.2.1 Definition
The RFA and SBREFA both define "small business" as having the same meaning as the term
"small business concern" under Section 3 of the Small Business Act (unless an alternative definition has
been approved). The latter defines a small business at the business entity or company level, not the facility
level. Furthermore, 13 CFR Part 121 defines a business concern eligible for SB A assistance as "a business
entity organized for profit, with a place of business located in the United States and which makes a
significant contribution to the U.S. economy through payment of taxes and/or use of American products,
materials and/or labor." Additionally, "such business entity may be in the legal form of an individual
proprietorship, partnership, corporation, joint venture, association, trust or a cooperative..."
6-3
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The definition of "small" generally is defined by standards for each SIC code as set by the Small
Business Administration (SBA). As discussed in the industry profile (see Section Three), the oil and gas
industry is covered by a number of SIC codes. The predominant SIC codes also are discussed in Section
Three. In SIC code 1311, Crude Petroleum and Natural Gas, SBA defines "small" as firms with fewer than
500 employees. SBA, however, states, in 13 CFR Part 121, that "number of employees means the average
employment of the concern, including the employees of its domestic and foreign affiliates [emphasis
added]." Therefore, where a firm is a subsidiary of a much larger corporate entity, the employment is
considered to be the employment of the parent corporation, not the employment of the subsidiary. The
analysis, then, needs to determine whether an oil or gas operator is a small business or is owned by a small
business entity. This work was undertaken and presented in Section Three of this EA.
6.3.2.2 Estimated Number of Small Business Entities
In Section Three, EPA determined that as many as 41 firms drilling in the Gulf of Mexico might be
considered small under SBA definitions outlined above. Furthermore one additional firm operating in the
Pacific Offshore Region is considered small. No firm operating in Cook Inlet Alaska is considered small,
however. Thus a total of 42 firms out of a total of 99 firms operating in the key regions (or about 42
percent) are considered small.
Small firms were profiled in detail in Section Three, which presents the number of firms and the
financial profile of all firms, both large and small (where data are available). Table 6-1 presents the
available financial data on the small firms in the analysis. As the table shows, EPA has relatively complete
data on about 1/3 of all of the operators considered small for the purposes of this analysis. The remaining
firms could not be located in SEC's Edgar database or in EPA's other data sources. For these firms, EPA
used the D&B database described in Section Two to obtain revenue, SIC, and employment data for the
privately held firms. Table 6-1 summarizes the financial characteristics for firms with available data,
providing some additional comparative measures of financial health: a posttax return on assets ratio, a
posttax return on equity ratio, and a posttax return on revenues (or profit margin).3 The typical small firm
3 Posttax returns are used because the OGJ 200, from which EPA obtained most of the summary
financial data, presents net income. Because some small firms might not pay corporate taxes, some of
6-4
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Table 6-1
Financial Data on Small Operators ($ 1,000s)
Operator
AEDC (USA) Inc.
Aera Energy, LLC
American Explorer
Apex Oil & Gas, Inc.
ATP Oil & Gas Co.
Aviva Petroleum
Barrett Resources
Basin Exploration
Bois d'Arc Operating Corporation
BT Operating Co.
Cal Dive International, Inc.
Gallon Petroleum Co.
Century Offshore Management Corp.
Chateau Oil and Gas, Inc.
Cockrell Oil Corp.
Davis Petroleum Corp.
Deeptech, Inc.
Domain Energy Corp.
Falcon Offshore Operating Co.
Flextrend Development Co., LLC
Forcenergy, Inc.
Forest Oil Corp.
F-W Oil Interests, Inc.
HW & T Acquisition Company
Kelley Oil
King Ranch Energy, Inc.
Linder Oil Co., A Partnership
Mariner Energy, Inc.
Matrix Oil & Gas, Inc.
Meridian Resource Corp.
NCX Company, Inc.
Newfield Exploration Co.
Panaco, Inc.
Pel-Tex Oil Co.
Petsec Energy, Inc.
No. of
Employees
8
18
-3
3
12
10
207
61
-3
3
35
400
143
20
2
45
14
67
52
3
3
275
177
20
85
81
30
18
48
20
60
11
86
40
25
53
Assets
$16,445
872,701
161,959
125,600
190,421
97,130
212,549
824,230
647,782
322,602
212,577
292,558
553,621
179,629
234,104
Equity
$3,748
412,381
121,365
89,369
113,701
18,862
132,034
214,991
261,827
(5,621)
57,174
145,102
292,048
55,188
48,635
Revenues
$26,104
1,800
12,000
160
9,848
382,600
24,720
280
4,819
109,386
43,638
16,583
162
4,000
2,000
16,183
52,268
190
300
287,539
339,641
2,200
19,100
76,138
3,500
2,000
64,050
2,200
58,333
4,452
200,521
38,586
2,200
125,100
Net Income
($22,482)
29,261
2,456
14,482
8,437
790
3,163
(134,818)
(9,270)
1,951
(20,210)
(28,541)
40,603
43
13,100
Return
on Assets
-136.7%
3.4%
1.5%
11.5%
4.4%
0.8%
1.5%
-16.4%
-1.4%
0.6%
-9.5%
-9.8%
7.3%
0.0%
5.6%
Return
on Equity
-599.8%
7.1%
2.0%
16.2%
7.4%
4.2%
2.4%
-62.7%
-3.5%
-34.7%
-35.3%
-19.7%
13.9%
0.1%
26.9%
Profit Margin
(net income to
total revenue)
-228.3%
7.6%
9.9%
13.2%
19.3%
4.9%
6.1%
-46.9%
-2.7%
2.6%
-31.6%
-48.9%
20.2%
0.1%
10.5%
6-5
-------
Table 6-1 (continued)
Operator
Pogo Producing Co.
Snyder Oil Co.
Stone Energy Corp.
Taylor Energy Co.
TDC Energy Corp.
Transworld Exploration and Production
W & T Offshore, Inc.
Totals
Medians (based on individual companies' figures)
Minimum
Maximum
No. of
Employees
160
327
90
113
20
30
2,875
37.5
2
400
Assets
$676,617
546,088
354,144
$6,308,208
$263,331
$16,445
$872,701
Equity
$146,106
263,756
156,637
$2,395,269
$126,700
($5,621)
$412,381
Revenues
$286,753
255,728
70,987
41,584
8,182
3,700
$2,547,267
$16,383
$160
$382,600
Net Income
$37,116
32,617
11,919
($22,546)
$2,810
($134,818)
$40,603
Return
on Assets
5.5%
6.0%
3.4%
-0.4%
1.5%
-136.7%
11.5%
Return
on Equity
25.4%
12.4%
7.6%
-0.9%
3.3%
-599.8%
26.9%
Profit Margin
(net income to
total revenue)
12.9%
12.8%
16.8%
-0.9%
6.8%
-228.3%
20.2%
Source: Oil & Gas Journal. OGJ 200, 1998; Pennwell Petroleum Directory, 1998; SEC's Edgar Database athttpAYwww.sec.gov.
U.S. EPA Facility Index System Dun & Bradstreet Detail, 1998.
6-6
-------
generally has smaller revenues, total assets, and owner equity than the typical large firm, but small size
does not necessarily mean less healthy financially (see Table 3-4 in Section Three). Both small and large
firms, on average, show strong returns on assets and equity, pretax.
The median assets for this group (among publicly held firms) is about $263 million, median equity
is about $127 million, median revenues are about $16 million, and median net income is about $2.8 million.
Median return on assets is about 1.5 percent, median return on equity is about 3.3 percent, and net income
to revenues (net profit margin) is about 6.8 percent. Although returns are not as strong as those associated
with the affected industry as a whole, profit margin is generally about the same as typical margins for the
affected industry, regardless of size of firm. Revenues range from a high of $383 million to a low of
$160,000. Actual or Dun & Bradstreet estimated revenue figures were identified for nearly all small firms,
although other financial information was available for only about half of the small firms. Employment at
these small firms ranges from a high of 400 to a low of 2. Median employment is approximately 38
persons.
These 42 firms comprise those firms drilling in the affected regions whether or not they are likely
to be using SBFs. The only firms that are likely to experience any negative impacts are those, under the
zero discharge option, that are currently using SBFs because under the preferred discharge option no wells
are expected to incur costs, thus no firms would be affected in any negative way by the proposed SBF
Guidelines. As discussed in Section Five, EPA assumes that the likeliest users of SBFs in shallow water
are the same operators who use SBF in deep water operations. Thus the firms with both deep and shallow
water operations are assumed to be the potentially affected firms. Only one firm (Mariner Energy) meets
this definition as well as the SBA definition of small entity and thus would be an affected firm under the
zero discharge option.
these ratios might overstate returns by roughly a third for certain small firms.
6-7
-------
6.3.3 Description of the Proposed Reporting, Recordkeeping, and Other Compliance
Requirements
Under current law, before this rule, as well as after implementation of this rule, all affected firms
are subject to monitoring and permitting requirements.
6.3.4 Identification of Relevant Federal Rules Which May Duplicate, Overlap, or Conflict
With the Proposed Rule
EPA has not identified any relevant federal rules that duplicate, overlap, or conflict with the
proposed rule. In fact, EPA is proposing this rule precisely because this type of drilling fluid is not
appropriately controlled in existing effluent guidelines.
6.3.5 Significant Regulatory Alternatives
EPA investigated the zero discharge option, but determined that this option also would have
minimal impact on nearly all firms, regardless of size, as discussed below in Section 6.4.
6.4 SMALL BUSINESS ANALYSIS
EPA undertook a revenue test, as prescribed by EPA's SBREFA Guidance, but only for the
circumstance in which costs are incurred. Under the preferred discharge option, no wells are expected to
incur costs, thus no firms are affected in any negative way by the proposed effluent guidelines.
EPA also looked at the impacts of the zero-discharge option. As discussed above, one firm meets
the definitions of potentially affected firm and small entity and thus would be an affected small firms under
the zero discharge option. EPA assumes that all wells drilled by this firm would incur costs of compliance.
This is a highly conservative assumption, since overall, this firm drilled so few wells on average over 1995
to 1997 that it would be somewhat unlikely that it used SBFs at all. This firm would not experience costs
6-8
-------
exceeding 1 percent of revenues under the zero discharge option. Thus neither the discharge option nor the
zero discharge option would have a significant impact on a substantial number of small entities.
6-9
-------
SECTION SEVEN
COST-BENEFIT ANALYSIS
Pursuant to E.O. 12866, EPA chose to quantitatively and qualitatively compare the costs and
benefits of the preferred discharge option. The total annual cost savings of the rule in pretax dollars are
$7.2 million, including the costs to both existing and new operations. Benefits also include 72.03 tons of
air emissions reduced from both existing and new sources per year (including nitrogen oxides and sulfur
dioxides, and other ozone precursors). These reductions arise because operators are encouraged to use
SBFs and discharge cuttings rather than use OBFs and transport wastes to shore for disposal or grind and
inject cuttings). SBF use also results in an energy savings of 2,302 barrels of oil equivalent per year when
the cuttings are no longer hauled to shore for disposal or ground up for injection. An additional 14.1
million pounds per year of pollutants, however, will be discharged to surface waters annually, but due to
pollution prevention technology, this discharge prevents 34 million pounds of wastes from being land
disposed or injected each year. See Table 7-1 for a summary of BAT and NSPS costs and benefits under
the discharge option. EPA's Environmental Assessment Report provides more details on these waste
reductions.1
Under the zero discharge option, costs would be $8.6 million, and 177.4 million pounds per year of
pollutants would no longer be discharged, but instead would be land disposed or injected each year.
Furthermore, 380 additional tons of air emissions would be generated annually, and energy consumption
would increase by 27,057 barrels of oil equivalent per year. See Table 7-1 for a summary of BAT and
NSPS costs and benefits under the zero discharge option.
'U.S. EPA, 1998. Environmental Assessment of Proposed Effluent Limitations Guidelines and
Standards for Synthetic Based Drillings Fluids and Other Non-Aqueous Drilling Fluids in the Oil and
Gas Extraction Point Source Category (EPA-82-B-98-019).
7-1
-------
Table 7-1
Summary of Costs and Benefits under the Discharge Option and Zero Discharge Option
Cost or Benefit
Category
Cost ($ million)
Energy (barrels of oil
equivalent)
Solid Waste (MM Ibs)
Air Emissions (tons
per year)
Water Pollutants
(MMlb/yr)
Discharge Option
BAT
-$6.6
-2,613
-34
-73.3
+15.8
NSPS
-$0.6
+311
0
+1.28
-1.6
Total
-$7.2
-2,302
-34
-72.02
+14.1
Zero Discharge Option
BAT
+$7.0
+24,125
+165
+338.55
-159.1
NSPS
+$1.6
+2,932
+13
+41
-18.3
Total
+$8.6
+27,057
+178
+379.55
-177.4
Note: minus signs indicate a cost savings or benefit; plus signs indicate a cost or an impact.
Source: SBF Development Document and U.S. EPA, 1999. Environmental Assessment of Proposed
Effluent Limitations Guidelines and Standards for Synthetic Based Drillings Fluids and Other
Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category (EPA-82-B-
98-019).
7-2
-------
APPENDIX A
COSTS OF COMPLIANCE PER WELL BY TYPE OF WELL
-------
APPENDIX A
COST OF COMPLIANCE PER WELL BY TYPE OF WELL
Table A-l shows the baseline cost of drill cuttings disposal, the discharge option cost under BAT
requirements for both the preferred discharge option and the zero discharge option, and the incremental
option costs under BAT for both options. These costs are presented in the Development Document as
aggregate costs, but for the purposes of the EA, the cost per well needs to be considered. Table A-2
presents the same information for those wells that must meet NSPS requirements. Total aggregate
incremental costs for both BAT and NSPS options approximately match those presented in the
Development Document. Any small differences are due to independent rounding. The BAT numbers are
used in Table 5-1 of the EA, and are further used to calculate the per firm costs of compliance in Appendix
B and Table 5-2.
A-l
-------
Table A-l
Incremental Per-Well BAT Costs
Type of Well
No. of
Wells
Baseline Costs
Per Well
Aggregate
Discharge Option Costs
Per Well
Aggregate
ZD Option Costs
Per Well
Aggregate
Incremental
Discharge Option Costs
Per Well
Aggregate
ZD Option Costs
Per Well
Aggregate
GULF OF MEXICO
Deep SBF Dev (haul)
Deep SBF Dev (inject)
Shallow SBF Dev (haul)
Shallow SBF Dev (inject)
Shallow OBF Dev (haul)
Shallow OBF Dev (inject)
Deep SBF Expl (haul)
Deep SBF Expl (inject)
Shallow SBF Expl (haul)
Shallow SBF Expl (inject)
Shallow OBF Expl (haul)
Shallow OBF Expl (inject)
Total
14
4
10
2
12
3
46
11
6
1
6
2
$117,975
$117,975
$78,175
$78,175
$97,288
$67,620
$261,575
$261,575
$163,175
$163,175
$191,490
$141,225
$1,739,423
$1,698,840
$424,710
$750,480
$187,620
$1,167,456
$202,860
$11,927,820
$2,981,955
$913,780
$228,445
$1,225,536
$225,960
$21,935,462
$88,673
$88,673
$60,673
$60,673
$60,673
$60,673
$191,073
$191,073
$121,673
$121,673
$121,673
$121,673
$1,288,876
$1,276,891
$319,223
$582,461
$145,615
$728,076
$182,019
$8,712,929
$2,178,232
$681,369
$170,342
$778,707
$194,677
$15,950,541
$213,482
$175,180
$97,288
$67,620
$97,288
$67,620
$341,388
$389,400
$191,490
$141,225
$191,490
$141,225
$2,114,696
$3,074,141
$630,648
$933,965
$162,288
$1,167,456
$202,860
$15,567,293
$4,439,160
$1,072,344
$197,715
$1,225,536
$225,960
$28,899,365
($29,302)
($29,302)
($17,502)
($17,502)
($36,615)
($6,947)
($70,502)
($70,502)
($41,502)
($41,502)
($69,817)
($19,552)
($450,547)
($421,949)
($105,487)
($168,019)
($42,005)
($439,380)
($20,841)
($3,214,891)
($803,723)
($232,411)
($58,103)
($446,829)
($31,283)
($5,984,921)
$95,507
$57,205
$19,113
($10,555)
$0
$0
$79,813
$127,825
$28,315
($21,950)
$0
$0
$375,273
$1,375,301
$205,938
$183,485
($25,332;
$0
$0
$3,639,473
$1,457,205
$158,564
($30,730;
$0
$0
$6,963,903
CALIFORNIA
Deep OBF Dev
Shallow OBF Dev
Total
11
1
$184,725
$125,046
$309,771
$2,031,975
$125,046
$2,157,021
$141,067
$96,147
$237,214
$1,551,737
$96,147
$1,647,884
($43,658)
($28,899)
($72,557)
($480,238)
($28,899)
($509,137)
ALASKA
Shallow OBF Dev
Total
1
$207,733
$2,256,927
$207,733
$24,300,216
$115,467
$1,641,557
$115,467
$17,713,892
$2,114,696
$28,899,365
($92,266)
($615,370)
($92,266)
($6,586,324)
$375,273
$6,963,903
Source: SBF Development Document.
A-2
-------
Table A-2
Incremental Per-Well NSPS Costs
Type of Well
No. of
Wells
Baseline Costs
Per Well
Aggregate
Discharge Option Costs
Per Well
Aggregate
ZD Option Costs
Per Well
Aggregate
Incremental
Discharge Option Costs
Per Well
Aggregate
ZD Option Costs
Per Well
Aggregate
GULF OF MEXICO
Deep SBF Dev (haul)
Deep SBF Dev (inject)
Shallow SBF Dev (haul)
Shallow SBF Dev (inject)
Total
14
4
1
0
$117,975
$117,975
$78,175
$78,175
$392,300
$1,698,840
$424,710
$62,540
$15,635
$2,201,725
$84,750
$56,750
$56,750
$283,000
$1,220,400
$305,100
$45,400
$11,350
$1,582,250
$213,482
$175,180
$97,288
$67,620
$553,570
$3,074,141
$630,648
$77,830
$13,524
$3,796,143
($33,225)
($33,225)
($21,425)
($21,425)
($109,300)
($478,440)
($119,610)
($17,140)
($4,285)
($619,475)
$95,507
$57,205
$19,113
($10,555)
$161,270
$1,375,301
$205,938
$15,290
$1,594,418
Source: SBF Development Document.
A-3
-------
APPENDIX B
COSTS OF COMPLIANCE BY FIRM
-------
APPENDIX B
COSTS OF COMPLIANCE BY FIRM
Tables B-l through B-4 present the firms likeliest to use SBFs along with an estimate of the
number of wells drilled annually, on average, by each of these firms according to MMS TIMS data. These
tables present this information for each of the four model wells: deep water exploratory, deep water
development, shallow water exploratory and shallow water development. The tables also present an
estimate of the wells drilled per year by each firm using SBFs. For all deep water wells, EPA assumes that
75 percent will be drilled using SBFs, as discussed in the Development Document. The potentially affected
firms therefore are assumed to use SBF to drill 75 percent of all wells they drill in deep water. For shallow
water wells, EPA has taken the total number of development and exploratory wells estimated to be drilled
with SBF in each year (12 shallow water development wells and 7 shallow water exploratory wells), and
distributed these numbers of wells to the 18 firms according to the firms' level of activity in the shallow
water of the Gulf. For example, Shell Oil is currently estimated to drill an average of 57 shallow water
development wells per year. This is 21 percent of the 271 development wells drilled by the 18 firms
considered to be likeliest users of SBFs in shallow water. As noted earlier, EPA estimated that 12
development wells are drilled annually with SBFs in shallow water. Shell Oil is assumed, therefore, to drill
21 percent of these 12 development wells estimated to be drilled using SBFs in shallow water, or 3 wells.
The costs of compliance for each option are taken from the incremental per-well costs shown in
Table A-l in Appendix A. These costs are multiplied by the number of wells drilled by each firm in each
category of well type. Note that in some cases, 0 wells might be indicated on a table, but a small cost
appears in the compliance costs columns. This occurs because the number of wells as presented in the
table is rounded, but the calculation is made using the unrounded number. The total costs for each firm,
when the costs of the four well types are added, equal those shown in Table 5-2 in Section Five of the EA.
Note that EPA could not determine which firms using OBFs in shallow water might switch to
SBFs if allowed to discharge, so these firms are not included in Tables B-l through B-4. These types of
wells are associated with cost savings under the discharge option, but would experience no incremental
costs under the zero discharge option. EPA would appreciate any information from industry regarding
B-l
-------
Table B-l
Estimated Number of Affected Deep Water Exploratory Wells Drilled Per Year and Their Costs of Compliance
Average No. /Yr. Estimated No.
Firm Drilled Drilled w/SBF
E.I. duPont de Nemours
Amerada Hess Corp.
Chevron USA Incorporated
Occidental Petroleum Corp.
Amoco Corp.
Union Pacific Resources Group, Inc.
Exxon Corp.
Shell Oil Co.
USX-Marathon Group
Texaco, Inc.
Mariner Energy, Inc.
Elf Aquitaine (France)
Santa Fe Energy Resources, Inc.
British-Borneo Petroleum Syndicate, pic (U.K.)
British Petroleum Co. pic (U.K.)
Vastar Resources, Inc.
Falcon Offshore Operating Co.
EEX Corporation
0
4
2
1
3
1
5
31
4
9
1
1
2
2
7
1
1
0
0
3
1
1
3
1
4
24
3
7
1
1
1
2
5
1
1
0
Compliance Cost
Under Discharge Option
($17,626)
($193,881)
($88,128)
($70,502)
($176,255)
($70,502)
($246,757)
($1,656,797)
($193,881)
($458,263)
($52,877)
($35,251)
($88,128)
($123,379)
($352,510)
($35,251)
($70,502)
$0
Compliance Cost Under
Zero Discharge Option
$22,354
$245,892
$111,769
$89,415
$223,539
$89,415
$312,954
$2,101,262
$245,892
$581,200
$67,062
$44,708
$111,769
$156,477
$447,077
$44,708
$89,415
$0
Source: MMS TIMS Database and SBF Development Document.
B-2
-------
Table B-2
Estimated Number of Affected Deep Water Development Wells Drilled Per Year and Their Costs of Compliance
Average No./Yr.
Firm Drilled
E.I. duPont de Nemours
Amerada Hess Corp.
Chevron USA Incorporated
Occidental Petroleum Corp.
Amoco Corp.
Union Pacific Resources Group, Inc.
Exxon Corp.
Shell Oil Co.
USX-Marathon Group
Texaco, Inc.
Mariner Energy, Inc.
Elf Aquitaine (France)
Santa Fe Energy Resources, Inc.
British-Borneo Petroleum Syndicate, pic (U.K.)
British Petroleum Co. pic (U.K.)
Vastar Resources, Inc.
Falcon Offshore Operating Co.
EEX Corporation
2
1
7
2
1
0
2
11
0
7
0
0
0
1
10
0
1
3
Estimated No.
Drilled w/SBF
1
1
5
2
1
0
2
8
0
5
0
0
0
1
8
0
1
2
Compliance Cost
Under Discharge Option
($36,628)
($21,977)
($153,836)
($43,953)
($29,302)
$0
($43,953)
($241,742)
$0
($146,510)
$0
$0
$0
($21,977)
($219,765)
$0
($21,977)
($65,930)
Compliance Cost Under
Zero Discharge Option
$109,809
$65,885
$461,197
$131,771
$87,847
$0
$131,771
$724,738
$0
$439,235
$0
$0
$0
$65,885
$658,853
$0
$65,885
$197,656
Source: MMS TIMS Database and SBF Development Document.
B-3
-------
Table B-3
Estimated Number of Affected Shallow Water Development Wells Drilled Per Year and Their Costs of Compliance
Average No./Yr.
Firm Drilled
E.I. duPont de Nemours
Amerada Hess Corp.
Chevron USA Incorporated
Occidental Petroleum Corp.
Amoco Corp.
Union Pacific Resources Group, Inc.
Exxon Corp.
Shell Oil Co.
USX-Marathon Group
Texaco, Inc.
Mariner Energy, Inc.
Elf Aquitaine (France)
Santa Fe Energy Resources, Inc.
British-Borneo Petroleum Syndicate, pic (U.K.)
British Petroleum Co. pic (U.K.)
Vastar Resources, Inc.
Falcon Offshore Operating Co.
EEX Corporation
17
2
71
12
16
2
27
57
6
26
1
0
1
1
0
29
0
3
Estimated No.
Drilled w/SBF
1
0
3
1
1
0
1
3
0
1
0
0
0
0
0
1
0
0
Compliance Cost
Under Discharge Option
(13,159)
(1,290)
(55,215)
(9,289)
(12,385)
(1,806)
(20,899)
(44,121)
(4,902)
(20,125)
(774)
(258)
(774)
(516)
0
(22,447)
0
(2,064)
Compliance Cost Under
Zero Discharge Option
9,909
971
41,578
6,994
9,326
1,360
15,738
33,224
3,692
15,155
583
194
583
389
0
16,903
0
1,554
Source: MMS TIMS Database and SBF Development Document.
B-4
-------
Table B-4
Estimated Number of Affected Shallow Water Exploratory Wells Drilled Per Year and Their Costs of Compliance
Average No./Yr.
Firm Drilled
E.I. duPont de Nemours
Amerada Hess Corp.
Chevron USA Incorporated
Occidental Petroleum Corp.
Amoco Corp.
Union Pacific Resources Group. Inc.
Exxon Corp.
Shell Oil Co.
USX-Marathon Group
Texaco, Inc.
Mariner Energy, Inc.
Elf Aquitaine (France)
Santa Fe Energy Resources, Inc.
British-Borneo Petroleum Syndicate, pic (U.K.)
British Petroleum Co. pic (U.K.)
Vastar Resources, Inc.
Falcon Offshore Operating Co.
EEX Corporation
6
4
8
6
1
5
1
22
5
7
2
1
5
2
0
17
0
3
Estimated No.
Drilled w/SBF
0
0
1
0
0
0
0
2
0
0
0
0
0
0
0
1
0
0
Compliance Cost
Under Discharge Option
($18,413)
($11,252)
($23,528)
($19,436)
($3,069)
($16,367)
($3,069)
($67,514)
($15,344)
($20,459)
($7,161)
($2,046)
($16,367)
($6,138)
$0
($51,147)
($1,023)
($8,183)
Compliance Cost Under
Zero Discharge Option
$8,102
$4,951
$10,353
$8,552
$1,350
$7,202
$1,350
$29,708
$6,752
$9,002
$3,151
$900
$7,202
$2,701
$0
$22,506
$450
$3,601
Source: MMS TIMS Database and SBF Development Document.
B-5
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which operators would be interested in switching from OBFs to SBFs in their shallow water drilling
operations and how many such wells might be drilled each year with SBFs.
B-6
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