United States
Environmental Protection
Agency
Office of Water
Mail Code 4303
Washington, DC 20460
EPA-821-B-00-012
December 2000
Economic Analysis of Final 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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Acknowledgments
This report was prepared by Mr. James C. Covington, HI of the Engineering and Analysis
Division. Assistance was provided by the Ms. Anne Jones and Ms. Maureen Kaplan of Eastern
Research Group. References to proprietary technologies are not intended to be an endorsement by
the Agency.
Questions or comments regarding this report should be addressed to:
Mr. James C. Covington, HI, Economist
Engineering and Analysis Division (4303)
U.S. Environmental Protection Agency
1200 Pennsylvania Avenue, N.W.
Washington, DC 20460
(202)260-5132
covington.james@epa.gov
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CONTENTS
Page
SECTION ONE INTRODUCTION 1-1
SECTION TWO SOURCES OF DATA 2-1
SECTION THREE
PROFILE OF AFFECTED OFFSHORE DRILLING
OPERATIONS
3-1
3.1
3.2
3.3
Introduction 3-1
Updated Profile of the Gulf of Mexico , 3-1
3.2.1 Current Practices 3-1
3.2.2 Platforms 3-2
3.2.3 Operators 3-3
3.2.4 Estimates of Drilling Activity 3-13
Overview of Deepwater Oil and Gas Drilling and Production
in the Gulf of Mexico 3-17
3.3.1 Deep Water Royalty Relief Act 3-18
3.3.2 Leasing ...'.. 3-18
3.3.3 Exploration and Development Drilling 3-20
3.3.4 Development 3-23
3.3.5 Reserves 3-31
3.3.6 Production 3-32
3.4 References 3-36
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 5-2
5.1.1 Impacts on Costs of Drilling Wells 5-2
5.1.2 Impacts on Platforms and Production 5-5
5.1.3 Impacts on Firms 5-11
5.1.4 Secondary Impacts 5-11
5.2
Impacts on New Sources 5-14
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5.3 References 5_21
SECTION SIX FINAL REGULATORY FLEXIBILITY ANALYSIS 6-1
6.1 Introduction 6_1
6.2 Regulatory Flexibility Analysis Components 6-1
6.2.1 Need for and Objectives of the Rule 6-2
6.2.2 Significant Issues Raised by Public Comments on the IRFA 6-2
6.2.3 Steps Taken By the Agency To Minimize Significant Economic
Impact on Small Entities 6-2
6.2.4 Estimated the Number of Small Entities To Which the Rule Will Apply . . 6-3
6.3 Small Business Analysis 6-6
6.4 References 6-7
SECTION SEVEN COST-BENEFIT ANALYSIS 7-1
SECTION EIGHT ENVIRONMENTAL JUSTICE ANALYSIS 8-1
8.1 Overview of the Environmental Justice Screening Analysis 8-2
8.2 Identification of Oil and Gas Waste Disposal Sites 8-3
8.3 Summary of Methodology 8-3
8.4 Results 8-4
8.5 References 8-5
APPENDIX A DERIVATION OF WEIGHTED AVERAGE COST
OF COMPLIANCE PER WELL TYPE A-l
APPENDIX B ECONOMIC MODEL FOR OIL AND GAS PRODUCTION
IN THE DEEPWATER GULF OF MEXICO B-l
APPENDIX C
ENVIRONMENTAL JUSTICE ANALYSIS C-l
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TABLES
Table
3-1 Identification of Structures in the Gulf of Mexico OCS 3-2
3-2 Companies Drilling in the Federal Offshore Gulf of Mexico
Name Changes or Ownership Defined 3-5
3-3 Financial Data on Operators in the Gulf of Mexico 3-9
3-4 Minimum, Median, and Maximum Financial Data for Large and Small Firms 3-14
3-5 Number of Wells Drilled in the Gulf of Mexico OCS and Texas
Where Controlled Discharge of Drilling Fluids and Cuttings Is Allowed 3-15
3-6 Number of Leases Issued in the Gulf of Mexico 1992 - 1999 3-19
3-7 Number of Deepwater Plans Approved by MMS in the Gulf of Mexico 1992 - 1999 3-21
3-8 Average Number of Rigs Drilling in the Deepwater Gulf of Mexico: 1992 - 2001 3-23
3-9 Deepwater Production and Discoveries 3-25
3-10 Number of Subsea Completions in the Gulf of Mexico: 1992 - 1999 3-31
3-11 Number of Deepwater Discoveries Including Proved, Unproved, Known, and
Industry Announced Discoveries: 1975 - 1999 3-33
3-12 Deepwater Production as a Percentage of Total Production: 1985 - 1999 3-34
4-1 Incremental Costs/Cost Savings of Compliance with the SBF Guidelines 4-4
5-1 Cost Savings of the BAT Discharge Option as a Percentage of Baseline Costs 5-3
5-2 Impact of BAT Options on Small Deepwater GOM Projects (1999$) 5-7
5-3 Impact of BAT Options on Medium Deepwater GOM Projects (1999$) 5-8
5-4 Impact of BAT Options on Large Deepwater GOM Projects (1999$) 5-9
5-5 Impact of BAT Options on All Deepwater GOM Projects (1999$) 5-10
5-6 Employment and Output Effects Associated With SBF Guidelines Options 5-13
5-7 Impact of NSPS Options on Small Deepwater GOM Platforms (1999$) 5-16
5-8 Impact of NSPS Options on Medium Deepwater GOM Platforms (1999$) 5-17
5-9 Impact of NSPS Options on Large Deepwater GOM Platforms (1999$) 5-18
5-10 Impact of NSPS Options on All Deepwater GOM Platforms (1999$) 5-19
6-1 SIC and NAICS Size Standards 6-4
6-2 Financial Data On Small Operators in the Gulf of Mexico 6-5
Figure
3-1
FIGURES
Breakdown of Wells by Drilling Fluid 3-16
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SECTION ONE
i
INTRODUCTION
The U.S. Environmental Protection Agency (EPA) is regulating the discharge of synthetic-based
drilling fluids (SBFs), other non-aqueous drilling fluids, and the resultant contaminated drill cuttings from
drilling operations. This Economic Analysis (EA) report is -written to address the economic impacts of this
Final Effluent Limitation Guidelines 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: x
• 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 in certain limited offshore
regions subject to meeting certain discharge requirements, including a sheen test and an
aqueous toxicity test.
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
promulgating Final Effluent Limitations Guidelines 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). The analyses in this report rely on publicly
available or industry-provided data exclusively.
The SBF Guidelines will control the discharge of SBF-contaminated drill cuttings (SBF-cuttings).
Discharge of the fluids themselves will be prohibited. Furthermore, the SBF guidelines will 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 will 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 40 CFR 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 Subcategory, 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 Met, 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.2 The EA for EPA's proposal of this rulemaking3 discussed the Alaska and California
drilling activities in detail; no further information on these areas appears in this report.
'Stripper wells are defined by level of production and Beneficial Use by produced water
disposition. These wells follow the requirements set by their location. That is, discharge of drilling fluids
or drill cuttings is prohibited for Stripper and Beneficial Use wells when they are located within onshore,
coastal, and offshore regions where discharge is prohibited.
2See 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, EPA-821-R-93-
001, January 1993, (hereafter called "Offshore EIA") 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, EPA 821-R-96-022, October 1996 (hereafter called
"Coastal EIA"). Outside of these regions, significant amounts of drilling activity are unlikely in the near
future but it is reasonable to expect that the economic characteristics of projects elsewhere would lie
within the range of projects in areas already considered.
3See Section Three of the 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, U. S. EPA, EPA 821-B-98-020, February 1999.
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This report contains only an updated analysis of impacts on drilling activities in these regions. The
EA industry profile and most of the analyses focuses 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). Furthermore, within this area, the profile
and many of the analyses focus primarily on deepwater Gulf of Mexico activities, since it is these drilling
operations that are likeliest to experience impacts from the Final SBF Guidelines. The profile of shallow
water Gulf of Mexico drilling operations is, however, updated to include more recent financial information
and to add operators who have only recently (1998 and 1999) begun to drill in the Gulf of Mexico
Offshore region.
This report is divided into eight sections. Following this introduction, Section Two presents
sources of data that have been added since proposal, Section Three presents the updated industry profile,
and Section Four discusses the regulatory costs of options under consideration for the rulemaking.
Section Five discusses the impacts of the final 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. This section adds a discussion of a computer model that simulates the financial conditions at
deepwater Gulf oil and gas drilling and production projects to address industry concerns that the
deepwater Gulf has unique economic and financial conditions and thus analyses performed for the
Offshore Guidelines are not sufficient for analyzing impacts of zero discharge on these projects. 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, Section Eight presents EPA's
. methodology and results for analyzing the environmental justice implications of a zero discharge option.
The EA also contains several appendices. Appendix A documents how the per-well incremental
costs were derived from EPA's engineering cost estimates. Appendix B presents an overview of EPA's
deepwater Gulf financial model and a detailed line-by-line explanation of the model assumptions and
calculations. Appendix C presents the details of the Environmental Justice analysis summarized in Section
Eight.
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SECTION TWO
SOURCES OF DATA
As discussed in Section One, for this analysis, EPA is relying on public data and data that industry
has submitted on a voluntary basis. This section discusses the primary sources of updated data used
throughout this document that have been added since the SBF Guidelines were proposed.
Primarily, EPA has added data necessary for modeling financial impacts on oil and gas projects
in the deepwater Gulf of Mexico. Much of this data was downloaded from Minerals Management
Services (MMS) website and included information on lease ownership and costs, 1998 production, 1998
and 1999 drilling data, reserve history data, platform information, and pipeline information. Additionally,
industry sources provided updated data on various operating costs, platform construction costs, deepwater
well drilling costs, etc. MMS also provided information on existing and planned oil and gas projects in the
deepwater regions. For more information on these data sources and an overview of the data provided by
these sources, see Summary of Data To Be Used in Economic Modeling, March 2000, which is located
in Section HLG of the Rulemaking Record.
Other updated sources of data used in the economic analyses include:
Development Document for Final 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, 2000 (EPA 821-B-00-013, hereafter
known as the SBF Development Document). This document supports this rulemaking and
presents all cost data.
Oil and Gas Journal, Special Report: Operating, financial results for OGJ 200. Volume
98(42). October 16, 2000.
Additional sources, including those used at proposal, are cited where they are mentioned in this
report.
2-1
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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 Gulf of Mexico (GOM or "the
Gulf) where discharge of drilling fluids with controls is authorized. For overview information on GOM,
California, and Alaska drilling operations, see the EA for the proposal.
This section begins with an updated discussion of the firms that are drilling both in deepwater and
shallow water regions of the Gulf and presents financial information on these firms. It then continues with
a focus on deepwater drilling operations in the Gulf. The number of wells drilled—a pertinent factor for
calculating the cost of the regulation—has not been changed from proposal.
3.2 UPDATED PROFILE OF THE GULF OF MEXICO
3.2.1 Current Practices
The Gulf of Mexico beyond three miles from shore is the most active oil and gas region of interest.1
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 at this time although oil and gas deposits are known to exist. The
Western Gulf 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.
'Under the Clean Water Act, state authority extends only three miles from shore. MMS has
leasing authority beyond three leagues (approximately 10 miles from shore) for Florida and Texas. The
Railroad Commission of Texas (RRC) provided annual counts of wells drilled in state waters in the three
miles to three leagues area for 1996 -1998, but could not provide the operator names for these wells.
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3.2.2 Platforms
The number of platforms has not been updated since the proposal. In 1998, 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,2 using the Minerals Management Service (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. Out of a total of
5,026 structures, EPA identified 2,381 platforms that fit this description (see Table 3-1).
Table 3-1
Identification of Structures in the Gulf of Mexico OCS
Category
All Structures
Abandoned Structures
Structures classified as production-structures, i.e., with
no well slots and production equipment
Structures known not to be in production
Structures with missing information on product type
(oil or gas or both)
Structures whose drilled well slots are used solely for
injection, disposal, or as a water source
":•'•••'.-". Countv :-.'V;C
5,026
1,403
245
688
309
0
Remaining Count
5,026
3,623
3,378
2,690
2,381
2,381
Source: Minerals Management Service, Platform Inspection System, Complex/Structure.
^Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry, U.S. EPA, EPA-821-R-93-001, January 1993.
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3.2.3 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. Independents typically are not 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 subcriapter 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 that includes wells
drilled in federal waters from 1995 through 1999 together with the identification number of the operator.
These data are summarized from MMS's Technical Information Management System (TIMS) and from the
publicly available data file on boreholes available from the MMS website. Using TIMS data, MMS
grouped wells by location (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. EPA
then updated this listing of operators using 1999 borehole data from the MMS website (MMS, 1999).
Names of all operators who had drilled any well in any of the five years were then compiled. The first
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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 income statements, as well as listing corporate subsidiaries. The
information in the EDGAR database as well as data from the OGJ 200, Lycos Companies Online (Lycos,
2000), and Hoovers Online (Hoovers, 2000) were used to identify parent companies or recent changes of
ownership (for example, The Coastal Corporation and El Paso Energy Corporation announced a merger in
January 2000). Note that EPA's analysis is based on the status of the industry as of October 2000. 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. EPA
followed the Small Business Administration's (SBA's) definition of affiliation in determining the point in
the corporate hierarchy at which to classify a firm as large or small. 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 100 firms, of which 15 are listed as majors.3 Thirteen 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 72 firms,
including those not listed in PennWell as majors or independents.4
As mentioned in footnote 1, Texas could not provide EPA with the names of the firms drilling in
the area between three miles and three leagues. However, it is likely that the same set—or nearly the same
set—of firms that are drilling in federal waters are also drilling in this area off Texas.
3 USA Oil Industry Directory. PennWell Directories; division of PennWell Publishing Co. Tulsa,
Oklahoma, 37th edition. 1998.
4lbitL
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Table 3-2
Companies Drilling in the Federal Offshore Gulf of Mexico
Name Changes or Ownership Defined
Company ;as listedm;MMS, 1997 and 1999 ; Cbmpanyflisted^by-Corporate Parent
AEDC (USA) Inc.
Agip Petroleum Company, Inc.
Amerada Hess Corporation
American Exploration Company
American Explorer
Amoco Petroleum Company
Anadarko Petroleum Corporation
Apache Corporation
Apex Oil and Gas, Inc.
Ashland Exploration Holdings, Inc.
ATP Oil and Gas Corporation
Aviara Energy Corporation
Aviva Petroleum
Barrett Resources Corporation
Basin Exploration, Inc.
Bellwether Exploration Company
BHP Petroleum (Americas), Inc.
Bois d'Arc Operating Corporation
Bois d'Arc Offshore Limited
BP Exploration & Oil, Inc.
British Borneo Exploration, Inc.
BT Operating Company
Burlington Resources Offshore, Inc.
Cairn Energy USA, Inc.
Cal Resources, LLC
Gallon Petroleum Operating Company
Calpine Natural Gas
Century Exploration Company
Century Offshore Management Corporation
Challenger Minerals, Inc.
Chateau Oil and Gas, Inc.
Chevron USA, Inc.
Chieftain International (U.S.), Inc.
Coastal Oil and Gas Corporation*
Cockrell Oil Corporation
Conoco, Inc.
Consolidated Natural Gas Company*
CXY Energy Offshore, Inc.
Davis Petroleum Corporation
Domain Energy Corporation
AEDC (USA) Inc.
Agip Petroleum Company, Inc.
Amerada Hess Corporation
S.A.Loius Dreyfus et Cie (France)
Petroquest Energy, Inc.
BP Amoco Corporation (U.S.)
Anadarko Petroleum Corporation
Apache Corporation
Apex Oil and Gas, Inc.
Statoil (Norway)
ATP Oil and Gas Corporation
HW&T Acquisition Company
Aviva Petroleum
Barrett Resources Corporation
Basin Exploration, Inc.
Bellwether Exploration Company
BHP Petroleum (Americas), Inc.
Bois d'Arc Operating Corporation
Bois d'Arc Operating Corporation
BP Amoco Corporation (U.S.)
British Borneo Exploration, Inc.
BT Energy
Burlington Resources, Inc.
Meridian Resource Corporation
Shell Oil Company
Gallon Petroleum Limited
Calpine Corporation
Century Exploration Company
Century Offshore Management Corporation
Global Marine
Chateau Oil and Gas, Inc.
Chevron Corporation
Chieftain International, Inc.
El Paso Energy Corporation
Cockrell Oil Corporation
Conoco, Inc.
Dominion Resources, Inc.
Canadian Occidental Petroleum, Ltd.
Davis Petroleum Corporation
Range Resources Corporation
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Table 3-2 (cont.)
I Company as listed in MMS, 1997 and 1999 : Company listed by Corporate Parent
Dominion Exploration and Production
EEX Corporation
El Paso Production
Elf Aquitaine
Energy Development Corporation
Energy Partners
Energy Resource Technology, Inc.
Enron Oil and Gas Company
Enserch Exploration, Inc.
Equitable Resources Energy Company
Exxon-Mobil Corporation
Fairways Specialty Sales & Service
Falcon Offshore Operating Company
Fina Oil and Chemical Company
Flextrend Development Company, LLC
Forcenergy, Inc.
Forest Oil Corporation
Freeport-McMoran Resources Partners, LLC
F-W Oil Interests, Inc.
Global Production
Gulfstar Energy, Inc.
Hall-Houston Oil Company
Houston Exploration Company
Howell Petroleum
Hunt Oil Company
HW&T Acquisition Company
IP Petroleum Company, Inc.
JM Huber Corporation
Juniper Energy
Kelly Oil Company
Kerr McGee Corporation
Kerr McGee Oil and Gas Corporation
King Ranch Energy, Inc.
Linder Oil Company, A Partnership
LLOG Exploration Offshore, Inc.
Louis Dreyfus Natural Gas Corporation
Louisiana Land and Exploration Company
Magnum Hunter Production
Marathon Oil Company
Mariner Energy
Matrix Oil and Gas, Inc.
Maxus US Exploration
McMoran Oil and Gas Company
Murphy Exploration & Production
Dominion Resources, Inc.
EEX Corporation
El Paso Energy Corporation
Total Fina Elf S.A.
Noble Affiliates
Energy Partners Limited
Cal Dive International Inc.
EOG Resources, Inc
EEX Corporation
Equitable Resources, Inc.
Exxon-Mobil Corporation
Fairways Specialty Sales & Service
R&B Falcon
Total Fina Elf S.A.
El Paso Energy Corporation
Forcenergy, Inc.
Forest Oil Corporation
McMoran Exploration Company
Prime Natural Resources
Global Industries
Domain Energy Corporation
Hall-Houston Oil Company
Houston Exploration Company
Howell Corporation
Hunt Consolidated Inc.
Hunt Oil Company
International Paper
JM Huber Corporation
Enron Corporation
Contour Energy Company
Kerr McGee Corporation
Kerr McGee Corporation
St. Mary Land and Exploration Company
Linder Oil Company, A Partnership
LLOG Exploration Offshore, Inc.
S.A.Loius Dreyfus et Cie (France)
Burlington Resources, Inc.
Magnum Hunter Resources
USX Corporation
Mariner Energy, Inc.
Matrix Oil and Gas, Inc.
Maxus US Exploration Company
McMoran Exploration Company
MurphyOil Corporation
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Table 3-2 (cont.)
Company as lifted inMMS, 1997' and 1999
Company listed :by Corporat& Parent :
NCX Company, Inc.
Newfield Exploration Company
Nippon Oil Exploration USA, Inc.
Norcen Explorer, Inc.
Ocean Energy, Inc
Occidental Petroleum Corporation
Offshore Energy Development Corporation
Oryx Energy Company
Panaco, Inc
Pel-Tex Oil Company
Pennzenergy
Penzoil Exploration and Production Company
Petrobras America, Inc.
Petroquest Energy, Inc.
Petsec Energy, Inc.
Phillips Petroleum Company
Pioneer Natural Resources, Inc.
Pogo Producing Company
Prime Natural Resources
Reading & Bates Development Company
Range Energy Ventures, Inc.
Ridgelake Energy
Samedan Oil Corporation
SantaFe Energy Resources, Inc.
Seagull Energy Exploration and Production, Inc.
Seneca Resources Corporation
Shell Deepwater Development, Inc.
Shell Deepwater Production, Inc.
Shell Offshore, Inc.
SOCO Offshore, Inc.
SONAT, Inc,
Spinnaker Exploration Company
St. Mary Energy
Statoil Exploration (U.S.), Inc.
Stone Energy Corporation
Tana Oil and Gas Corporation
Tatham Offshore, Inc.
Taylor Energy Company
TDC Energy Corporation
Texaco Exploration and Production, Inc.
Torch Operating Company
Total (France)
Transworld Exploration and Production
NCX Company, Inc.
Newfield Exploration Company
Nippon Mitsubishi Oil Corporation
Union Pacific Resources Group, Inc.
Ocean Energy, Inc
Occidental Petroleum Corporation
Titan Exploration
Kerr McGee Corporation
Panaco, Inc
3Tec Energy Corporation
Devon Energy Corporation
Devon Energy Corporation
Petroleo Brazileiro SA
Petroquest Energy, Inc.
Petsec Energy, Inc.
Phillips Petroleum Company
Pioneer Natural Resources, Inc.
Pogo Producing Company
Prime Natural Resources
R&B Falcon
Range Resources Corporation.
Ridgelake Energy
Noble Affiliates
Santa Fe Snyder Corporation
Ocean Energy, Inc.
National Fuel Gas Company
Shell Oil Company
Shell Oil Company
Shell Oil Company
SanteFe Synder Corporation
El Paso Energy Corporation
Spinnaker Exploration Company
St. Mary Land and Exploration Company
Statoil Exploration (U.S.), Inc.
Stone Energy Corporation
TRT Holdings, Inc.
El Paso Energy Corporation
Taylor Energy Company
TDC Energy Corporation
Texaco, Inc.
Torch Energy Advisors, Inc.
Total Fina Elf S.A.
Transworld Exploration and Production
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Table 3-2 (cont.)
Company as listed in MMS, 1997 arid 1999 \ •. . Company listed by C^orateParmt
UMC Petroleum Corporation
Union Pacific Resources Company
Union Oil Company of California
Vastar Resources, Inc.
W&T Off shore, Inc.
Walter Oil & Gas Corporation
Westport Oil and Gas
Westport Resources**
Ocean Energy, Inc.
Union Pacific Resources Group, Inc.
Unocal Corporation
BP Amoco Corporation (U.S.)
W&T Off shore, Inc.
Walter Oil & Gas Corporation
Westport Oil and Gas
Westport Oil & Equitable Resources
**
These mergers have taken place only as of January 2000.
Equitable Production, a subsidiary of Equitable Resources, and Westport Oil and Gas pooled
resources to form Westport Resources.
Table 3-3 shows the firms considered affected firms in the Gulf and their relevant 1999 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 40 (40 percent) that either meet the
Small Business Administration's definition of a small business (which for the oil and gas extraction
industry is 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.
3-8
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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. Due to a relatively hard year for the oil and gas
industry, among publicly held firms, median return on assets for the group is 2 percent, median return on
equity is 6 percent, and median profit margin (net income/revenues) is 3 percent, according to 1999
financial data. In the oil and gas industry, financial health varies as swiftly as oil prices. In 1999, the
average domestic first purchase price was $15.56/bbl and the wellhead price for gas was $2.08/Mcf. In the
first seven months of 2000, oil prices averaged $25.50/bbl and gas prices averaged $2.82/Mcf (DOE,
2000). The financial health of the oil firms should show a corresponding increase.
3.2.4 Estimates of Drilling Activity
EPA has not revised its estimates of drilling activity in the Gulf since proposal. Table 3-5 presents
data from MMS on drilling activity in 1995, 1996, and 1997 by type of drilling and by depth. In addition
to showing an annual increase in the number of wells drill, the table indicates that most wells drilled in the
Gulf of Mexico Federal OCS are development wells drilled in less than 1,000 feet of water. Exploratory
drilling in waters less than 1,000 ft. deep also makes up a major portion of wells drilled annually. Based on
the MMS data, an average of 1,119 wells were drilled annually in the Federal OCS during the 1995 -1997
time frame.
3-13
-------
Table 3-4
Minimum, Median, and Maximum Financial Data for Large and Small Firms ($l,OOOs)
Number of
Employees
Assets
Equity
Revenues
, Net
Income
Return
on
Assets
Return
on .
Equity
Profit
Margin
Small firms
Minimum
Median
Maximum
23
89
272
8,986
268,798
949,401
(71,313)
140,011
375,018
7,053
71,630
1,004,781
(35,027)
(310)
109,852
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-1%
17%
-15%
0%
46%
-94%
-4%
43%
Large firms
Minimum
Median*
Maximum
47
1584.5
99000
69,276
4,360,762
144,521,000
(3,815)
1,167,006
63,466,000
9,509
1,091,137
185,527,000
(255,000)
99,047
7,910,000
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2%
270%
-30%
9%
50%
All firms
Minimum
Median*
Maximum
23
501
99,000
8,986
800,052
144,521,000
(71,313)
375,018
63,466,000
7,053
387,452
185,527,000
(255,000)
18,228
7,910,000
-32%
2%
270%
-30%
6%
50%
-108%
4%
71%
-108%
3%
71%
Source: Oil & Gas Journal. OGJ 2000; Pennwell Petroleum Directory, 1998; SEC's Edgar Database at
http://www.sec.gov; Hoovers Online at http://www.hoovers.com; and Lycos Companies Online at
http://www.companiesonline.com
* Used hypothetical number (501) for employees for larger firms when number of employees was not
available.
3-14
-------
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 WeDs
(>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 KRC (James Covington, EPA, and Donna
Burks, RRC, Sept. 1, 1998).
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 mat 10 wells were drilled in
1996, 5 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, arid Donna Burks, RRC, September 1, 1998).5 When this number of wells is added to the
OCS numbers, EPA calculates an average of 1,127± wells are drilled per year in the Gulf.
EPA worked with industry to estimate the percentage of wells drilled with each type of fluid (WBF,
OBF, or SBF) prior to the regulation as well as the percentage of WBF or OBF wells that would switch to
SBF after the regulation. EPA estimates that almost 18 percent, or 201 wells, are drilled currently with
SBFs and 6 percent, or 67 wells, are drilled with OBFs. EPA further estimates that no OBFs are used in
5These are not NPDES CWA permits, but permits issued by the state of Texas.
3-15
-------
deep water drilling, and of the 67 OBF wells estimated to be drilled annually in shallow water, 39 percent,
or 27 wells, would convert to using SBFs if discharge of SBF-cuttings was allowed. The remaining 857
wells that are estimated to be drilled annually in the Gulf of Mexico are assumed to be drilled exclusively
using WBFs. Of these, 36 wells or 4 percent, would convert to using SBFs if discharge of SBF-cuttings
was allowed because of the quicker drilling times and greater ability to drill directional wells (see
Development Document). Due to rounding, the total number of wells is 1,125 prior to the regulation. See
Figure 3-1 for a summary of the breakdown and the SBF Development Document for details.
Figure 3-1
Breakdown of Wells by Drilling Fluid Type
BAT Gulf of Mexico Wells
Note: Unshaded boxes reflect current distribution of wells.
Shaded boxes show changes after BAT 1 or BAT 2.
Because of increased drilling efficiencies, 54 WBF wells are
replaced by 36 SBF wells.
3-16
-------
3.3 OVERVIEW OF DEEPWATER OIL AND GAS DRILLING AND PRODUCTION IN
THE GULF OF MEXICO
Offshore production in the Gulf of Mexico began in 1949 with a shallow well drilled in shallow
water. It took another 25 years until the first deepwater well (^ 1,000 ft. of water) was drilled in 1974.
Barriers to deepwater activity include technological difficulties of stabilizing a drilling rig in the open
ocean, high financial costs, and natural and manmade barriers to oil and gas activities in the deep waters.
These barriers have been offset in recent years by technological developments (e.g., 3-D seismic
data covering large areas of the deepwater Gulf and innovative structure designs) and economic incentives
(see Section 3.3.1). As a result, deepwater oil and gas activity in the Gulf of Mexico has dramatically
increased from 1992 to 1999. In fact, in late 1999, oil production from deepwater wells surpassed that
produced from shallow water wells for the first time in the history of oil production in the Gulf of Mexico.
MMS has been actively tracking these developments and proactively evaluating the potential
effects of exploration, drilling, and production activities in the deepwater Gulf. The profile presented here
draws heavily on the MMS report Deepwater Gulf of Mexico: America's Emerging Frontier (MMS,
2000a). MMS also performed an environmental assessment of deepwater operations and activities in
which it found a potentially significant localized impact to chemosynthetic communities (e.g., tube worms)
from the discharge of SBF and cuttings wetted with SBF under baseline conditions (MMS, 2000b). As a
result of this assessment, MMS developed a mitigation measure requiring deepwater wells to be at least
1,000 feet away from any potential high-density chemosynthetic community. On the other hand, MMS
noted that zero discharge of SBF cuttings could increase the use of oil-based fluids (a scenario modeled in
the cost analysis) with a concomitant increase in water quality problems currently being faced at some
commercial onshore disposal sites (MMS, 2000b).
The section begins with a discussion of the Outer Continental Shelf Deep Water Royalty Relief Act
(Section 3.3.1) because it is a major underlying factor in the dramatic increase in oil and gas activity in this
region. The subsequent sections follow the sequence in oil and gas development—leasing, drilling,
development, and reserves and production.
3-17
-------
3.3.1 Deep Water Royalty Relief Act
The Outer Continental Shelf Deep Water Royalty Relief Act (hereafter called the "Act") had a
large impact on deepwater activity in the Gulf (43 U.S.C. §1337). The Act provides economic incentives
to operators drilling in waters with a depth of more than 200 meters (656 feet). Federal royalty payments
are waived for deepwater leases acquired between November 28, 1995 and November 28, 2000. The
extent of the waiver is determined according to the depth of the water and the production volume (million
barrels of oil equivalent [MMBOE] drilled):
• For a field in 200 to 400 meters (656 to 1312 feet) of water, royalty payments are waived
for the first 17.5 MMBOE produced,
• For a field in 400 to 600 meters (1312 to 2624 feet) of water, royalty payments are waived
for the first 52.5 MMBOE produced, and
• For fields in greater than 800 meters (2,624 feet) of water, royalty relief is provided for up
to 87.5 MMBOE.
The Act also has provisions that allowed reductions in royalty payments for fields leased prior to 1995.
Throughout Section 3.3, tables with times series data have a dotted line between 1995 and 1996 to
highlight the increased activity resulting from the Act.
3.3.2 Leasing
Because of the significant economic incentives offered by the Act, companies became more
interested in the deepwater Gulf. One side effect of the Act was a dramatic increase in the acquisition of
3-D seismic data. Sound waves are transmitted to and through the ocean bottom and are reflected back
according to the geological layers in the earth. Recent advances in computer technology allow the detailed
analysis of these 3-dimensional "cubes" to identify likely oil and gas accumulations. This technology
reduces the risk in exploration and, therefore, the financial risk associated with exploration and production.
Table 3-6 shows the number of leases issued in the Gulf of Mexico per year from 1992 to 1999.
Although leasing activity had been on the rise since 1992, the Act accelerated leasing activity in deepwater
3-18
-------
from 1996 to 1999. The number of leases issued are divided into four water-depth categories. As can be
seen from the table, the largest increase in leases from 1995 to 1999 is in areas with water depths greater
than 800 meters, which is the category with the largest royalty relief.
Table 3-6
Number of Leases Issued in the Gulf of Mexico 1992 - 1999
:v.; Year; .
1992
1993
1994
1995
1996
1997
1998
1999
Total
Number of Leases in WaierDepiaiJCate^ries (meters>
, ; ._,, ' ., - ' ' - - '. , - . • . . ," --•,= -• ...- •',.'.••-',-:--•»:•*' . «.•-• • *-'..- • --....; ,,^< •••. .'•,-••- .' •• .\ , .-.-.. .., . . , - -•>-,, ,.- • ,-, ..
- ,• _ , .-. , • " • •:.-•; •• i •'"'••''-.-;
Less than 200m
176
261
466
509
620
525
265
165
2,987
20btb400m ;:
4
15
25
52
66
44
35
16
257
400to 800ni Jv
17
36
30
103
110
99
58
17
470
Morethan-SOOm;
7
24
39
171
712
1,110
771
135
2,969
Source: MMS, 2000a.
In 1992, industry held 5,600 active leases in the Gulf of which 27 percent were in deep water
(-1,500 leases). By 1999, industry held 7,600 active leases of which 48 percent are in deep water (-3,800
leases).6 That is, the deepwater region is showing nearly twice the growth in activity than the shallow
water region of the Gulf. The number of leases issued for fields in greater than 800 meters decreased from
1998 to 1999, possibly due to the lower oil prices during that period. It is important to note that there is a
6Lease statuses may change daily, so the current number of active leases is an approximation. The
total number of leases in Table 3-6 exceeds the number of active leases held in 1999 because of lease
expirations. Leases for blocks in less than 400 meters of water are 5 years in length, 8 years for blocks in
400 to 799 meters of water, and 10 years for blocks in 800 meters of water or deeper.
3-19
-------
considerable time lag between leasing, qualification, and production. Hence, the ultimate impact of the
Act will not be achieved for a few years.
Not only did the number of deepwater leases issued increase drastically from 1995 to 1998, the
financial investment also increased dramatically. The total amount of money bid for deepwater leases was
at an all time high in 1997—$500 million for fields 5,000 to 7,500 feet deep.
The ownership of leases in the deep waters of the Gulf of Mexico also has seen changes in the last
five years. Although deepwater leases were dominated by majors from 1992 through 1995, beginning in
1996, independents began to acquire significant deepwater lease holdings.7 In 1995, independents held 186
deepwater leases. By 1999, independents held 1,371 leases—a seven-fold increase in four years. Since
there may be substantial lag times between leasing and production, independents may show a surge in
production in future years.
3.3.3 Exploration and Development Drilling
3.3.3.1 Drilling Activity
There have been significant increases in exploration and development activities in the Gulf over the
past decade. Table 3-7 shows the number of deepwater exploration and development plans approved by
MMS between 1992 and 1999. There are two primary types of drilling operations in oil and gas
extraction—exploratory and developmental. While exploratory drilling is undertaken to determine potential
reserves, developmental drilling takes place for production purposes. In order to proceed with deepwater
drilling projects, operators first file a Plan of Exploration (POE) with MMS. After drilling exploratory
wells, the operators can then file a conceptual Deep Water Operations Plan (DWOP). Following this, a
Development Operations Coordination Document (DOCD) is filed. Developmental wells can then be
'Majors active in the Gulf include Arco, BP Amoco, Chevron, Exxon Mobil, Shell, and Texaco.
Mergers between some of these players also has affected lease ownership and the diversity of lease
ownings. For instance, the merger between BP Amoco and Arco had a significant impact on the dominance
of this combined corporation in this arena.
3-20
-------
drilled, but production cannot begin until a final DWOP is filed. As can be seen from the table, the number
of exploration plans increased steadily over the last eight years. The number of DOCDs and DWOPs
approved also has increased.
Table 3-7
Number of Deepwater Plans Approved by MMS in the Gulf of Mexico 1992 - 1999
',' Year • :,
1992
1993
1994
1995
1996
1997
1998
1999
Total
Number of Plans Approved by MMS "
'.. :'_Vr;- . , V'P;-/ ';: : • •'.
Plan of Exploration
24
21
33
34
62
85
124
143
526
Development Operations
Coordination Document
3
3
4
8
4
13
13
16
64
: Deep Water 4
Operations Plan
-
-
-
5
19
30
16
18
88
Source: MMS, 2000a.
Not only has the submission of deepwater drilling plans increased, but actual deepwater
exploratory and developmental drilling has seen increasing levels of activity between 1992 and 1998. The
number of exploratory wells drilled increased steadily from 1992 to 1998 and then slowed in 1999. In
1992, less than ten exploratory wells were drilled; whereas in 1998, more than a hundred wells were drilled.
The largest increase in exploratory well drilling was seen in the 1,500- to 5,000-foot depth category.
There were also significant increases in drilling of wells in water depths ranging from 5,000 to
7,500 feet. Similarly for developmental drilling, this activity also has increased between 1992 and 1997,
most dramatically in the 1,500- to 5,000-foot water depth range. In 1998 and 1999, developmental drilling
decreased slightly, however.
3-21
-------
In the offshore, well depth may be measured in several ways, two of which are true vertical depth
(the vertical distance, in feet, from the rig kelly bushing to the maximum depth of the well) and water depth.
As mentioned in the beginning of this section, offshore production began in 1947 with a shallow well
(<3,000 feet) in shallow water (-100 feet). The next year, the deepest offshore well had a true vertical
depth of 13,600 feet but little change in water depth. Maximum true vertical depth gradually doubled over
50 years (i.e., from 13,600 feet in 1949 to 27,000 in 1998). The change in maximum water depth drilled is
much more striking. It took nearly 30 years for the industry to drill in water deeper than 1,000 feet. (In
1974, the maximum water depth drilled was 1,024 feet). After that, change was quite rapid. Two years
later, in 1976, industry nearly doubled the water depth drilled record (1,986 feet). In 1984, industry
reached 3,534 feet. Three years later, in 1987, industry doubled its last milestone by drilling in water
depths exceeding 7,500 feet. The current record is only slightly deeper at 7,716 feet.
3.3.3.2 Drilling Rig Availability
Table 3-8 lists the average number of rigs drilling in the deepwater Gulf from 1992 to 2001. The
number of rigs increased nine-fold or 800 percent from 3 in 1992 to 27 in 1999. However, not all drilling
rigs can drill in all depths. MMS (2000a) estimates there are about 45 rigs in the Gulf capable of drilling
deepwater wells:
• 5 rigs can drill in water depths up to 1,499 feet
" 22 rigs have maximum depth capacities between 1,500 to 4,999 feet
« 14 rigs have maximum depth capacities between 5,000 to 7,499 feet, and
• 4 rigs have maximum depth capacities 7,500 feet or greater.
There are 470 active leases in water depths of 7,500 feet or greater and only 4 rigs capable of drilling at
these water depths. Approximately 15 ultra-deep rigs are under construction, but the Gulf region will need
to compete for their services with other areas of the world. Even though not all leases will be drilled, there
is the potential for some constraint on evaluation of deepwater leases due to rig availability (or lack
thereof).
3-22
-------
Table 3-8
Average Number of Rigs Drilling in the Deepwater Gulf of Mexico: 1992 - 2001
;yv,-:-;'''Yjear:"> .".-.:•,; -'vv
1992
1993
1994
1995
1996
1997
1998
1999
2000 (estimated)
2001 (estimated)
^^^eragelSumber^oifK^s; •;;
3
6
11
14
18
26
28
27
30
31
Source: MMS, 2000a.
3.3.4 Development
There are several types of deepwater development systems producing oil and gas in the Gulf of
Mexico. These are:
• Fixed platforms with water depth capacities of 1,200 to 1,500 feet
• Compliant towers used in water depths ranging from 1,000 to 3,000 feet
• Tension leg platforms for fields in 1,000 to 5,000 feet of water
• Spars and other floating systems used for water depths greater than 8,000 feet
• Subsea systems also used in greater than 8,000 feet of water
3-23
-------
Table 3-9 lists deepwater discoveries by prospect or field name, the operators, location, water depth,
discovery date, production start-up date, and the development system.
Subsea systems have played an important role in the increase of deepwater drilling and production.
These systems are submerged drilling facilities resting on the sea bottom. They are used in both shallow
and deep water and have fiowlines connecting to a "host" facility on the surface. Table 3-10 shows the
number of subsea completions for the shallow and deep water each year from 1992 to 1999. From 1996
through 1999, 83 subseabed installations were completed. The past four years, then, account for nearly
half of all subseabed completions (186) recorded by MMS.
Subseabed completions show a similar pattern to wells with a the recent rapid increase in
maximum water depth; Until 1987, no subseabed completion was in water deeper than 350 feet. In 1988,
the record depth jumped to 2,200 feet. From 1989 though 1996, maximum water depths for subseabed
completions increased to nearly 3,000 feet but jumped to a depth of 5,295 feet in 1997. The distance from
the subseabed completion to its host facility may be as long as 63 miles (Mensa to West Delta block 143)
but most are less than 15 miles long.
One type of deepwater development system not currently used in the.Gulf of Mexico is a floating,
storage, production, and off-loading system (FPSO). These systems are used in 1,000 to greater than
8,000 feet of water and include processing and storage facilities. At present, the MMS is assessing the
environmental impacts of introducing FPSO systems in the Gulf of Mexico.'
To support the increasing number of subsea systems in the Gulf of Mexico, the length and diameter
of pipelines taking the hydrocarbons to a service base have also been on the rise. The miles of pipeline
greater than 12 inches in diameter approved has risen from approximately 40 miles in 1996 to almost 300
miles in 1999.
3-24
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Table 3-10
Number of Subsea Completions in the Gulf of Mexico: 1992 - 1999
Year
1992
1993
1994
1995
1996
1997
1998
1999
Total
Number of Subsea Completions
Shallow Water
1
3
7
10
12
13
8
10
64
Deep Water
2
11
1
4
10
7
9
14
58
Source: MMS, 2000a.
Finally, increasing exploration and production of oil and gas from the deep waters means more
infrastructure has been put in place onshore to support these activities. Although service bases already
existed in southeast Louisiana, the increased deepwater activity has spread service bases to southwest
Louisiana and Texas.
3.3.5 Reserves
Deepwater discoveries are accounting for an increasing proportion of reserves. There are four
kinds of reserves in the oil and gas industry: proved reserves, unproved reserves, known resources, and
industry-announced discoveries. Proved reserves are those that are considered recoverable and are
currently producing. Unproved reserves are potentially recoverable reserves with no current or near-future
3-31
-------
production. Known resources are discovered sources with lower possibilities of production. Finally,
industry-announced discoveries are those made by operators but not evaluated by MMS.
The number of proved reserve additions from the shallow waters peaked in 1967 and has declined
every decade thereafter. In contrast, the number of deepwater proved reserves has increased significantly
since 1975. More importantly, the average size of a deepwater field is far greater than that of a shallow
water field. In the 1990s, an average deepwater field added proven and unproven reserves (47 MMBOE)
that were nine times the proved and unproved reserves of an average shallow water field (5 MMBOE). In
the most active depth range (1,500 to 7,499 feet), the field sizes average 60 MMBOE. This implies that
the deepwater regions hold the potential for many large fields.
The number of deepwater field discoveries also has been on the rise, especially from 1993 to 1997.
The number of producing fields on the other hand, has not increased that significantly. This can be partly
explained by the time lag between the discovery of a field and when actual production begins.
Table 3-11 displays the number of discoveries, including proved, unproved, known resources, and
industry-announced discoveries, that have occurred each year since 1975. The trend spells out an
increasing number of discoveries from 1992 to 1997. • When taking into consideration the additions of oil
and gas reserves contributed by deepwater discoveries, it is clear that, in the last decade or so, the
deepwater discoveries have added large amounts of reserves to the Gulf of Mexico and have the promise to
do so in the near future as well.
3.3.6 Production
Although there is a time lag between discovery and production, production from deepwater wells in
the Gulf of Mexico has been steadily and significantly increasing since 1985. Deepwater production in the
Gulf increased 321,000 barrels per day between 1994 and 1998.
Table 3-12 shows deepwater oil and gas production as a percentage of total production in the Gulf
as well as the year-to-year percentage increase in deepwater oil and gas production. Deepwater oil and gas
3-32
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Table 3-11
Number of Deepwater Discoveries Including Proved, Unproved, Known, and Industry Announced
Discoveries: 1975 -1999
'; •' Year "''
1 • • .' "''•;. " '' ""'
1975
1976
1977
1981
1983
1984
1985
1986
1987
1988
1989
Number of
: Discoveries
1
3
1
3
1
12
7
6
8
5
7
:• .."Year 'v' ',
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Number of ;
Discoveries;
4
4
1
4
5
7
7
9
11
3
Source: MMS, 2000a.
production has been forming a larger and larger percentage of total production in the Gulf through time.
The impact of the Deep Water Royalty Relief Act is apparent. In 1995, deepwater oil and gas formed 16
and 4 percent of production from the Gulf, respectively. In 1999, 45 percent of oil and 17 percent of gas
produced in me Gulf were from deepwater projects. Note also that the year-to-year percentage increase in
deepwater oil and gas activity also has been significantly increasing. At the end of 1999, deepwater oil
production increased 41 percent over 1998 levels. A milestone was reached in late 1999 when oil
production from the deep water exceeded that from the shallow water for the first time. Further, nine
deepwater projects began production in 1999 and several more plan to be in production by the year 2004.
3-33
-------
Table 3-12
Deepwater Production as a Percentage of Total Production: 1985 - 1999
Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Percent of Total GOM Production
Oil
6.0
5.3
5.2
4.3
3.6
4.4
7.7
12.2
11.9
13.2
16.0
19.5
26.3
35.8
45.4
Gas
0.8
0.9
1.0
0.8
0.7
0.6
1.2
1.9
2.5
3.3
3.8
5.4
7.4
11.1
16.8
Percentage Increase
Oil
-
-9.3
-10
-23
-22
21.3
88.4
62.9
-1.4
13.6
32
30.8
50.2
46.7
41.3
Gas
-
9
19.9
-13
-16
-4.3
91.5
49.3
37.4
'33
13.5
53.7
37.2
46.8
50.8
Source: MMS, 2000c.
After a late beginning, subsea completions now account for a substantial portion of deepwater
production. Subsea gas production began in 1993 while subsea oil production began in 1995. After six to
four years, subsea completions account for 40 percent of the deepwater gas production and 25 percent of
the deepwater oil production.
3-34
-------
One of the reasons for the success of deepwater operations is high well production rates.
Milestones include Bullwinkle in 1992 (5,000 BOPD), Auger in 1994 (10,000 BOPD), and Ursa in 1999
(36,520 BOPD). These are single-well production rates, not lease production rates. Many deepwater
fields produce at rates higher than ever seen before in the Gulf. For comparison, the Offshore EIA modeled
a typical shallow-water well with a peak production rate of 500 BOPD. What this means is that large,
deepwater operations will rapidly dominate Gulf production. Deepwater drilling occurs in the area of
highest interest for using synthetic drilling fluids. The cost or savings incurred under the rule are so small
compared to the total cost of drilling an offshore well that the effluent guidelines are likely to play little part
in whether to drill but will be a factor in which fluid to use.
3-35
-------
3.4 REFERENCES
DOE. 2000. Monthly Energy Review. Department of Energy. Energy Information Administration.
• Washington, DC. DOE/EIA-0035(2000/10). October, Tables 9.1 and 9.11.
EPA. 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. U.S. Environmental Protection Agency. Washington, DC. EPA-821-B-98-020.
February.
EPA. 1993. Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry, U.S. Environmental Protection Agency. Washington,
DC. EPA-821-R-93-001. January.
MMS. 2000a. Richie D. Baud, Robert H. Peterson, Carey Doyle, and G. Ed Richardson. Deepwater
Gulf of Mexico: America's Emerging Frontier. U.S. Department of the Interior. Minerals Management
Service. OCS Report MMS 2000-022. April.
MMS. 2000b. Gulf of Mexico Deep-water Operations and Activities: Environmental Assessment. U.S.
Department of the Interior. Minerals Management Service. OCS EIS/EA MMS 2000-001. May.
MMS. 2000c. Deepwater production summary by year. U.S. Department of the Interior. Minerals
Management Service, downloaded
10/10/2000.
MMS. 1999. Borehole. U.S. Department of the interior. Minerals Management Service.
. ASCII file, downloaded 9/1/99.
MMS. 1997. TIMS database. U.S. Department of the Interior. Minerals Management Service. MMS
97-0007.
PennWell. 1998. USA Oil Industry Directory. PennWell Directories; division of PennWell Publishing
Co. Tulsa, Oklahoma, 37th edition.
Regg, James. 1999. "Deepwater Production and Discoveries," MMS, August 4.
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 (see the Development Document for more details). Only wells
that are drilled with SBFs or those drilled with OBFs or WBFs that are assumed to convert to SBFs are
determined to have costs or realize savings under the regulation. These analyses focus on drill cuttings;
zero discharge of SBF not associated with cuttings is current practice and thus operators incur no cost to
meet the zero discharge requirement in the final rule.
4.1 REGULATORY OPTIONS
In the February 1999 Proposal, EPA discussed two primary options for SBFs associated with drill
cuttings, "SBF-cuttings":
• a controlled discharge option (based on two SBF-cuttings discharges from solids control
equipment), and
• a zero discharge option.
In the April 2000 NODA (65 FR 21560), EPA revised and added one new controlled discharge option for
SBF-cuttings.
Hence, EPA considered three primary options for the final rule for Best Available Treatment
Economically Achievable (BAT) for existing sources and New Source Performance Standards (NSPS) for
new sources ] :
'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
-------
• • controlled discharge of cuttings wetted with SBF, called "BAT 1" although it applies to
both BAT and NSPS discharges
• controlled discharge of cuttings wetted with SBF, called "BAT 2," although it applies to
both BAT and NSPS discharges and
• zero discharge, called "zero discharge."
There is also an implicit no-action option.
Both BAT and NSPS discharge options (BAT 1 and BAT 2) control the characteristics the stock
base fluid through limitations on:
" PAH content
• sediment toxicity
" biodegradation rate, and
« the current requirements of stock limitations on barite of mercury and cadmium.
Both discharge options control the characteristics and volumes of cuttings discharged through limitations
on:
• formation oil content
• maximum aqueous toxicity of discharged drilling waste
• the quantity of SBF base fluid reaching the water at the point of discharge.
Both discharge options retain the current prohibition on diesel oil discharge and control sheen formation at
the point of discharge under BPT and BCT limitations. EPA believes that all of these components are
essential for appropriate control of SBF-cuttings discharges.
When the used drilling fluid returns up the borehole, it passes through three to four cleaning phases
to remove the cuttings and recycle the drilling fluid. The first two phases are "shale shakers;" primary and
4-2
-------
secondary shale shakers differ according to the coarseness of the mesh through which the fluid passes. The
third phase is a "mud cleaner;" a high speed shale shaker or a centrifuge. The fourth phase is a "cuttings
dryer or squeeze press" to further reduce the amount of SBF adhering to the cuttings. The third and fourth
phases remove fine particles ("fines") from the drilling fluid. The BAT 1 engineering model assumes that
both the cuttings (phases 1 and 2) and fines (phases 3 and 4) are discharged, i.e., the discharge limits
should allow this practice. BAT 2 option differs from the BAT 1 option in that to meet discharge limits, it
is likely that only the cuttings would be discharged while the fines will be retained for zero discharge via
hauling to shore for land-based disposal. Hence, this option has a higher control requirement and, thus,
most likely requires operators to dispose of fines on land.
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 a long-term average of 10.2 % 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 selected option for the final rule, for both BAT and NSPS, is BAT Option 2.
4.2 TOTAL COMPLIANCE COSTS
As Table 4-1 shows, total compliance costs for the discharge options are actually cost savings due
to the value of the drilling fluids captured for recycling. For BAT, the aggregate annual cost savings are
$46.6 million and $46.5 million for discharge options 1 and 2, respectively. (BAT 2, the selected option,
has lower savings because of the need to haul the fines to shore for land disposal). For NSPS, the annual
cost savings is $2.5 million for discharge options 1 and 2.
hi contrast, industry incurs costs under the zero discharge option. These costs are estimated to be
$28.7 million per year under BAT and $0.4 million per year under NSPS for a total of $29.1 million per
year.
4-3
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SECTION FIVE
ECONOMIC IMPACTS OF THE PROPOSED RULEMAKING
EPA selected the BAT 2 discharge option for promulgation. Under this decision, the Final SBF
Guidelines will provide a cost savings to industry. This cost savings will be experienced directly by wells
currently (i.e., in the baseline) discharging cuttings contaminated with SBFs and other water non-
dispersible fluids, by wells currently land-disposing or injecting OBF cuttings in the baseline that convert to
SBF, and by WBF wells that convert to SBF due to greater drilling efficiencies (see Development
Document for details). Operations that continue to use WBFs would not be directly affected by the SBF
Guidelines. 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 generally 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.
For each regulatory option, EPA estimated the change in the cost of drilling wells, impacts on
operating a deepwater production unit (typically a platform), 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 selected BAT and NSPS
requirements. EPA looked at deepwater projects to respond to a comment that such projects were much
different form those investigated during EPA's offshore rulemaking. The results of the deepwater analyses
are summarized below in Section 5.1 (for existing sources) and Section 5.2 (for new sources). Impacts on
small firms are discussed in Section Six.
5-1
-------
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, wells using OBFs that convert to SBFs, and wells using WBFs that convert to SBFs.
Table 5-1 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 (including WBF wells).1 Costs and cost savings vary
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.
Under the selected option (BAT 2), all but one category of wells in the Gulf of Mexico show a cost
savings (Table 5-1). This results from a combination of factors—SBFs produce smaller volumes of
drilling waste than WBFs do, the increased cuttings treatment recovers more of the expensive SBF, or the
operator no longer needs to transport oil-based cuttings to shore for disposal. These savings range from
negligible to 25 percent of the cost of drilling an exploratory well in shallow water. In the aggregate, then,
industry realizes a cost savings under the selected option. The one well in Alaska (Cook Inlet) potentially
affected by the rule shows a cost of 3.6 percent of drilling costs.2
Only shallow water SBF wells show a cost increase because the additional recovery of SBF is not
sufficient to offset the cost of the equipment; shallow wells use less drilling fluid than deeper wells. The
increase, however, is three-tenths of one percent. A certain percentage of wells might incur a higher
'Table 5-1 shows per-well BAT costs which include retrofit costs for installation and downtime.
NSPS costs do not need retrofit costs and per-well NSPS costs are lower. To be conservative, EPA
examined the economic impacts on BAT and NSPS projects with per-well BAT costs.
2This cost would not actually be incurred since OBF drilling could continue at no additional cost.
5-2
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cost for SBFs that meet the stock limitations over SBFs that do not. EPA also examined this type of
increase by modeling a cost increase from $160/bbl for the SBF and a primary shale shaker to $300/bbl for
the SBF and a cuttings dryer3. For shallow water wells, the incremental cost was $48,000 for a
development well (compared to a $2.9 million total baseline drilling cost) and $61,000'for an exploratory
well (compared to a $4.9 million total baseline drilling cost).
In other words, the extremely conservative assumptions lead to no more than a 1.7 percent increase
in the total drilling cost. It is unlikely that such a small increase in total drilling cost would affect the
decision whether or not to drill. It would only make sense not to drill a well if the difference in estimated net
present values of a project with and without that well is less than the incremental cost of the more expensive
fluid for that well. This might happen when wells are drilled into marginal fields. To examine the highest
number of operations that might be affected by increased drilling fluid costs, EPA examined the number of
wells per year that have been drilled recently using SBFs in shallow water operations, i.e, where SBF
formulations might have to be changed to meet the BAT requirements (see Development Document). EPA
identified about 40 wells in this category, about 3 percent of all wells drilled annually in the Gulf of Mexico.
Thus, no more than 3 percent of Gulf wells would not be drilled. Because it is likely that any wells not
drilled would be in marginal fields, lost production would most likely be far less than 3 percent of Gulf
production. There is the social cost of the lost production as well (which does not affect the operator), but
that should be small relative to the total recoverable production in the Gulf, since it would affect a relatively
small number of wells and these are wells drilled into marginal fields.
Under rejected BAT 1 option, the results look very similar to those for BAT 2. The only difference
is for shallow exploratory WBF wells where the BAT 1 savings is about 1.5 percent less than the savings
for BAT 2.
Under the rejected zero discharge option, the results fall into two categories—wells without
incremental costs and wells with incremental costs. Wells drilled with oil-based fluids in the baseline would
have had to meet zero discharge under current requirements; hence, they incur no incremental costs. Wells
drilled with water-based fluids would not change to SBF; hence, they incur no incremental costs. Wells
drilled with SBF fluids incur the additional costs of zero discharge. These added costs range from about 1
to 3 percent of average drilling costs in the Gulf. Given the basic cost of drilling an offshore or coastal
3The cost analysis uses a weighted average of SBF fluid costs' (over $200/bbl).
5-4
-------
(Alaska) well, the incremental costs of the rule are highly unlikely to change an operator's decision whether
to drill a well. Once the operator has decided to drill a well, the regulation will be one of the factors in the
operator's decision of which fluid to use. . . . .. .
5.1.2 Impacts on Platforms and Production
As discussed in the NOD A, EPA has developed model projects based closely on a number of
existing projects currently operating in deepwater Gulf locations.4 Appendix B and the Summary of Data
To Be Used in Economic Modeling (Section HI.G of the Rulemaking Record) contain details on the
methodology, data, and assumptions on which the models are based and how the models were constructed.
EPA received no comments on the methodology and data presented in the NOD A. The only additional data
input not presented in the Summary of Data To Be Used in Economic Modeling is assumed drilling activity.
Drilling activity is estimated for existing and new projects based on the drilling required to approximate
original proved reserves in new projects without exceeding remaining proved reserves by a wide margin at
existing projects (See Appendix B).
These models are based on a cash flow approach. The projected revenues are compared to
operating costs at each year for each model project. Revenues are based on an assumed price of oil, current
and projected production of oil and gas, well production decline rates, and royalty rates. Operating costs are
based on an assumed cost per BOB produced. The model runs for 30 years or is assumed to shut in when
operating costs exceed revenues. That is, the economic models have differing lifetimes according to project
characteristics and each model may,have a shortened lifetime as a result of incremental pollution control
costs. The model then calculates the lifetime of the project, total production, and the net present value of the
operation (net income of the operation over the life of the project in terms of today's dollars), which includes
the net operating earnings, taxes, expenditures on drilling, other capital expenditures, etc. A positive net
present value means that the project is a good investment, m this case, the return is greater than the
discount rate, which represents the opportunity cost of capital. If the net present value is negative, it means
that money would have been better invested elsewhere. For existing projects, the model uses current
operations; all expenditures in prior years, such as exploration, delineation, and infrastructure development
4EP A presented findings for Alaska, California, and shallow Gulf of Mexico projects at proposal
based on findings in the Offshore rulemaking. Because current requirements for Alaska are zero discharge,
it would not make financial sense for a project to switch to SBF and incur the additional costs shown in
Table 5-1. EPA, therefore, did not re-analyze the Alaska model for promulgation.
5-5
-------
costs are considered sunk costs and are not addressed. For new projects, the model uses data and
assumptions about timing of the various phases of exploration, delineation and development, along with cost
assumptions about costs incurred during these phases to compute a full lifetime financial model of these
projects.
Each model is run twice—with and without the change due to pollution control. The models
support changes in both directions, i.e., costs or savings. This means that only the incremental cost (or cost
savings) of drilling under the three regulatory options is changed and then the postcompliance results are
compared to those calculated under baseline assumptions. If a model shows the net present value of a
project to be positive in the baseline, but would have a negative net present value under any of the options,
some or all of the wells would not be drilled. This difference between baseline and postcompliance would
generate production impacts.
The same approach is used for modeling both existing and new projects. Since the NOD A, two
projects used for modeling have shut in (Diamond and Cooper) and EPA has removed them from the
analysis (a total of 18 projects remain for modeling existing projects and 13 remain for modeling new
projects). See Summary of Data To Be Used in Economic Modeling, Section IH.G. of the NODA record
for additional information on the projects used for modeling impacts and the assumptions used to construct
each model new source project.
The results of the analysis of existing deepwater Gulf projects shows that the rule, regardless of
option chosen, does not affect the volumes of production or the lifetime of projects. Under all options, the
net present value of each of the existing projects is still positive postcompliance under all options
investigated. The rule, however, has an impact on the net present value of the projects (see Table 5-2
through 5-5), but the impact on net present value is nearly negligible for all size projects. Thus the rule will
have a very small impact on the rate of return for an'existing project, but will not change the fact that
continuing to invest in the project is a good investment (the net present value is still greater than $0
postcompliance). It also minimally affects the amount of federal taxes paid due to the tax shield on capital
and operating costs.
5-6
-------
Table 5-2
Impact of BAT Options on Small Deepwater COM Projects (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
19,874,315
--
—
Option
BAT I
19,874,315
0
0.0%
Option
BAT 2
19,874,315
0
0.0%
- Zero
Discharge
19,874,315
0
0.0%
Total projected lifetime production (BOE)
Change in total projected lifetime production (BOE)
Percentage change in discounted baseline production
31,702,089
—
—
31,702,089
0
0.0%
31,702,089
0
0.0%
31,702,089
0
0.0%
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
$73,453
—
•
$73,457
$4
0.0%
$73,456
$3
0.0%
$73,030
($423)
-0.6%
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
49
12.3
12.3
—
—
0
49
12.3
12.3
0
0
0
49
12.3
12.3
0
0
0
49
12.3
12.3
0
0
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes
($000)
Percentage change in federal income taxes
$37,894
—
—
$37,896
$2
0.0%
$37,896
$1
0.0%
$37,708
($186)
-0.5%
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$37,217
~
—
$37,217
$0
0.0%
$37,217
$0
0.0%
$37,217
$0
0.0%
Source: EPA, 2000. Deepwater Production Loss Model.
5-7
-------
Table 5-3
Impact of BAT Options on Medium Deepwater COM Projects (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
253,419,30
4
—
—
Option •;.'
BAT 1
253,419,30
4
0
0.0%
Option
BAT 2
253,419,30
4
0
0.0%
?;Zero:'' .;
Discharge
253,419,304
0
0.0%
Total projected lifetime production (BOE)
Change in total projected lifetime production (BOE),
Percentage change in discounted baseline production
362,731,56
6
—
—
362,731,56
6
0
0.0%
362,731,56
6
0
0.0%
362,731,566
0
0.0%
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
$989,997
—
--,
$990,044
$47
0.0%
$990,037
$40
0.0%
$984,989
($5,008)
-0.5%
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all
platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
89
11.1
11.1
—
—
0
89
11.1
11.1
0
0
0
89
11.1
11.1
0
0
0
89
11.1
11.1
0
0
Present value of federal income taxes collected
($000)
Change in present value of federal income taxes
($000)
Percentage change in federal income taxes
$526,735
—
—
$526,756
$21
0.0%
$526,753
$19
0.0%
$524,424
($2,311)
-0.4%
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$446,024
—
—
$446,024
$0
0.0%
$446,024
. $0
0.0%
$446,024
$0
0.0%
Source: EPA, 2000. Deepwater Production Loss Model.
5-8
-------
Table 5-4
Impact of BAT Options on Large Deepwater COM Projects (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
1,127,389,726
—
—
Option
BAT1
1,127,389,726
0
0.0%
Option
BAT 2
1,127,389,726
0
0.0%
Zero
Discharge
1,127,389,726
0
0.0%
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOB)
Percentage change in discounted baseline production
1,651,984,245
—
—
1,651,984,245
0
0.0%
1,651,984,245
0
0.0%
1,651,984,245
0
0.0%
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
$5,552,828
•
—
$5,553,014
$186
0.0%
$5,552,989
$160
0.0%
$5,532,852
($19,976)
-0.4%
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
• 120
15
15
—
—
0
120
15
15
0
0
0
120
15
15
0
0
0
120
15
15
0
0
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes
($000)
Percentage change in federal income taxes
$2,959,419
—
—
$2,959,502
$84
0.0%
$2,959,491
$72
0.0%
$2,950,429
($8,990)
-0.3%
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$1,900,407
—
—
$1,900,407
$0
0.0%
$1,900,407
$0
0.0%
$1,900,407
$0
0.0%
Source: EPA, 2000. Deepwater Production Loss Model.
5-9
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Table 5-5
Impact of BAT Options on All Deepwater COM Projects (1999$)
Type of Impact
Projected lifetime discounted production (FVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
1,400,683,345
-
—
Option
BAT1
1,400,683,345
0
0.0%
Option.
BAT 2 »
1,400,683,345
0
0.0%
Zero
Dischars
1, 400,683 j
1
0.
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOE)
Percentage change in discounted baseline production
2,046,417,900
—
—
2,046,417,900
0
0.0%
2,046,417,900
0
0.0%
2,046,417,|
0-1
1
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
$6,616,278
—
—
$6,616,514
$236
0.0%
$6,616,482
$204
0.0%
$6,590,1
($28,4|
-O.|
1
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all
platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
258
13
13
—
—
0
258
13
13
0
0
0
258
13
13
0
0
1
Present value of federal income taxes collected
(SOOO)
Change in present value of federal income taxes
(SOOO)
Percentage change in federal income taxes
$3,524,048
—
—
$3,524,155
$107
0.0%
$3,524,140
$92
0.0%
$3,512,;
($11,4
-0.
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$2,383,648
—
—
$2,383,648
$0
0.0%
$2,383,648
$0
0.0%
$2,383,6
0.(
Source: EPA, 2000. Deepwater Production Loss Model.
5-10
-------
Under the selected option (BAT 2), NPV increases negligibly (less than 0.1 percent) for all BAT
projects. The present value of Federal income taxes paid increases negligibly (less than 0.1 percent), as
well. EPA concludes that the selected option is economically achievable, since it results in a minor cost
savings.
Under the rejected BAT 1 option, the results are very similar to those for the selected option, a
negligible increase in NPV and Federal taxes paid. Under the rejected zero discharge option, small and
medium size projects show a decline of at most 0.6 percent in NPV over the life of the project. Large
projects show a 0.4 percent decline in NPV.
5.1.3 Impacts on Firms
Other than in Section 6, which discusses impacts on small businesses, EPA does not discuss
impacts on firms. Industry comments indicated that identifying impacts at the firm level are irrelevant and
that impacts of the rule should be determined at the oil and gas project level. EPA has estimated project
level impacts in Section 5.1.2 and Section 5.2 , and thus has not updated a firm level analysis, except as the
rule affects small business entities (See Section 6).
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 selected
discharge option because, in the aggregate, it results in cost savings. Changes in employment and output
are directly proportional to costs of compliance, that is, higher costs lead to lower employment and output.
Likewise, a 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
5-11 .
-------
discharge option, the industry incurs costs and not savings, thereby leading to small output losses 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, 1996). Input-output multipliers allow EPA to calculate the total
number 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 gain or loss, 13 jobs in the U.S. economy will be gained or 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 5-6 presents the results of the analysis of employment and output effects stemming from all
three options considered. As the table shows, the selected discharge option 2 is estimated to result in
employment gains of 636 full-time equivalents (1 FTE=2,080 hours and can be equated with one full-time
job) and gains of S95 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 378 FTEs and a loss of $56.5 million per year in output for the
U.S. economy as a whole (losses within the oil and gas industry would be less).
5For more information on input-output analysis in the oil and gas industry, see EPA, 1996.
5-12
-------
Table 5-6
Employment and Output Effects Associated With SBF Guidelines Options ($1999)
Option
Discharge Option 1
Discharge Option 2
Option 3 (Zero Discharge)
Cost Savings (+)
or Compliance Cost (-)
(S Millions)
$49.1
$48.9
-$29.1
.
Gains (+) or Loss C-)
in Employment*
+639 FTEs
+636 FTEs
-378FTEs
Total Gains (+) or
Loss (-) in Output**
f $ Millions)
+$95.4
+$95
-$56.5
Source: Section Four and BEA, 1996.
* 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.
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
all options. Even these gross changes in employment and output, however, are very small relative to total
U.S. employment (133 million persons) and gross domestic product ($8.8 trillion) in 1999 (CEA, 2000).
5.1.4.2 Secondary Impacts on Associated Industries
EPA qualitatively analyzed the secondary impacts on associated industries from the selected
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 and most
producers make more than one product. 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
5-13
-------
some instances under the selected 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 selected option, EPA estimates that waste
generated for disposal by landfill and injection would be reduced by several million pounds per year. Under
a zero discharge option, these firms would experience potential economic gains, because more waste would
be generated for land disposal or injection than is currently generated.
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 final
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 (see EPA, 1993 and 1996).
5.2 IMPACTS ON NEW SOURCES
The final NSPS option is the same discharge option selected 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
5-14
-------
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.
Industry provided assumptions on capital and operating costs for deepwater new sources (ERG,
2000). As a result of incorporating industry's recommended oil price of $15/bbl, most deepwater Gulf
NSPS projects show negative net present values (NPVs) before the regulation. EPA conducted a
sensitivity analysis using $20/bbl for oil and the NPVs for most large projects are positive although NPVs
for small and medium projects remain negative. Industry might still operate projects that show a negative
NPV in the baseline. One, industry might desire to expand infrastructure in the deepwater Gulf; these early
deepwater projects on which the NSPS analysis is modeled may actually be an investment in the future of
deepwater Gulf development. Second, a project may be undertaken, and only after it is developed is it
known that it is not providing a return on the initial investment. Despite this, once built, assuming the
project has positive earnings, the continued operation defrays the cost of the infrastructure, and the
operator continues to produce as long as earnings are positive. Model projects that are estimated to have
negative net present value in the baseline are assumed to operate anyway as long as they have positive
earnings, since any earnings will defray the costs of the infrastructure. These operations will continue to
drill as long as NPV under a drilling scenario is a smaller loss than the NPV under a no-drilling scenario.
The impact of the options on these projects is measured in terms of how much the options might change net
present value in absolute terms. Impacts on those projects with positive net present value in the baseline
are judged either as declines in net present value or, if the net present value becomes negative
postcompliance, as impacts on production, due to the fact that a project would not be undertaken if net
present value is negative postcompliance.
Table 5-7 through 5-10 show the results of the NSPS analysis. Under the selected option (BAT 2),
NPV increases negligibly (0.1 percent or less) for all NSPS projects. The present value of Federal income
taxes paid increases negligibly (about 0.1 percent), as well. EPA concludes that the selected option is
economically achievable, since it results in a minor cost savings.
5-15
-------
Table 5-7
Impact of NSPS Options on Small Deepwater COM Platforms (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
13,605,848
—
—
Option
BAT1
13,605,848
0
0.0%
Option
BAT 2
13,605,848
0
0.0%
Zero
Discharge
13,605,848
0
0.0%
"
Total projected lifetime production (BOE)
Change in total projected lifetime production (BOE)
Percentage change in discounted baseline production
31,702,089
—
—
31,702,089
0
0.0%
3.1,702,089
0
0.0%
31,702,089
0
0.0%
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
($137,367)
—
--
($137,251)
$115
0.0%
($137,262)
$105
0.0%
($140,852)
($3,486)
-2.5%
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
79
19.8
19.8
—
—
0
79
19.8
19.8
0
0
0
79
19.8
19.8
0
0
0
79
19.8
19.8
0
, 0
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes
($000)
Percentage change in federal income taxes
($10,521)
—
—
($10,505)
$16
0.2%
($10,507)
$15
0.1%
($11,120)
($599)
-5.7%
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$25,891
—
—
$25,891
$0
0.0%
$25,891
$0
0.0%
$25,891
$0
0.0%
Source: EPA, 2000. Deepwater Production Loss Model.
5-16
-------
Table 5-8
Impact of NSPS Options on Medium Deepwater COM Platforms (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
114,524,539
—
—
Option
BAT1
114,524,539
0
0.0%
Option
BAT 2
114,524,539
0
0.0%
Zero
Discharge
114,524,539
0
0.0%
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOB)
Percentage change in discounted baseline production
366,997,146
—
—
366,997,146
0
0.0%
366,997,146
0
0.0%
366,997,146
0
0.0%
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
($1,207,300)
~
—
($1,206,638)
$662
0.1%
($1,206,701)
$599
0.0%
($1,233,002)
($25,702)
-2.1%
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
109
18.2
18.2
—
—
0
109
18.2
18.2
0
0
0
109
18.2
18.2
0
0
0
109
18.2
18.2
0
0
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes
($000)
Percentage change in federal income taxes
$207,797
—
.
$207,825
$28
0.0%
$207,822
$25
0.0%
$205,506
($2,291)
-1.1%
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$215,098
—
—
$215,098
$0
0.0%
$215,098
$0
0.0%
$215,098
$0
0.0%
Source: EPA, 2000. Deepwater Production Loss Model.
5-17
-------
Table 5-9
Impact of NSPS Options on Large Deepwater GOM Platforms (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
480,787,323
. —
—
Option
BAT1
480,787,323
0
0.0%
Option , ,
BAT 2
480,787,323
0
0.0%
Zero
Dischard
480,78?|
4
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOB)
Percentage change in discounted baseline production
1,418,373,281
—
—
1,418,373,281
0
0.0%
1,418,373,281
0
0.0%
1,418,373|
4
1
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
($697,434)
—
—
($696,900)
$535
0.1%
($696,956)
$478
0.1%
($727,1
($29,
~4
1
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
77
15
15
--
—
0
77
15
15
0
0
0
77
15
15
0
0
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes
(SOOO)
Percentage change in federal income taxes
$1,183,530
—
—
$1,183,565
$34
0.0%
$1,183,560
$30
0.0%
$1,179]
($3,
-Q
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$785,543
—
—
$785,543
$0
0.0%
$785,543
$0
0.0%
$785.
0
Source: EPA, 2000. Deepwater Production Loss Model.
5-18
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Table 5-10
Impact of NSPS Options on All Deepwater COM Platforms (1999$)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current
608,917,710
—
.
Option
BAT1
608,917,710
0
0.0%
Option
BAT 2
608,917,710
0
0.0%
Zero
Discharge
608,917,710
0
0.0%
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOE)
Percentage change in discounted baseline production
1,817,072,516
-
—
1,817,072,516
0
0.0%
1,817,072,516
0
0.0%
1,817,072,516
0
0.0%
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
. ($2,042,101)
—
—
($2,040,789)
$1,312
0.1%
($2,040,919)
$1,182
0.1%
($2,100,948)
($58,847)
-2.9%
Number of platforms ceasing production in first year
(postcompliance)
Total number of production years
Average production years per platform (all platforms)
Average production years per platform (nonclosing
platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing
platforms
0
265
18
18
—
—
0
265
18
18
0
0
0
265
18
18
0
0
0
265
18
18
0
0
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes
($000)
Percentage change in federal income taxes
$1,380,806
--
—
$1,380,885
$79
0.0%
$1,380,875
$69
0.0%
$1,374,376
($6,430)
-0.5%
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$1,026,532
—
—
$1,026,532
$0
0.0%
$1,026,532
$0
0.0%
$1,026,532
$0
0.0%
Source: EPA, 2000. Deepwater Production Loss Model.
5-19
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Under the rejected BAT 1, the results are very similar to those for the selected option, a negligible
increase in NPV and Federal taxes paid. Under the rejected zero discharge option, small and medium
projects show a decline of 2.5 and 2.1 percent respectively in NPV over the life of the project while large
projects show a 4.3 percent decline in NPV.
EPA has chosen the same option for NSPS as for BAT (discharge option 2). The selected option
results in a cost savings to industry. As a result, EPA finds the rule economically achievable for new
sources and concludes there will be no barriers to entry for new sources.
5-20
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5.3
REFERENCES
BEA. 1996. Bureau of Economic Analysis. Regional Economic Analysis Division. Regional
Input/Output Modeling Systems (RIMS II). Table A-2.4-Total Multipliers, by Industry Aggregation for
Output, Earnings, and Employment. Washington, DC.
CEA. 2000. Council of Economic Advisors. Economic Report of the President. U.S. Government
Printing Office. Washington, DC.
EPA, 2000. Deepwater Production Loss Model Runs.
EPA. 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. U.S. Environmental Protection Agency. Washington, DC. EPA-821-B-98-020.
February.
EPA. 1996. 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. Environmental
Protection Agency. Washington, DC. EPA-821-R-96-002. October.
EPA. 1993. Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry, U.S. Environmental Protection Agency. Washington,
DC. EPA-821-R-93-001. January.
ERG. 2000. Eastern Research Group, Inc. Summary of Data To Be Used in Economic Modeling.
Document written for synthetic drilling fluid effluent guideline rulemaking record. Section m.G. March.
13 pages.
5-21
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SECTION SIX
FINAL 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). Although the
Administrator 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 a final regulatory flexibility analysis (FRFA). Section
6.2 reviews the steps suggested in Agency guidance 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 rule by Section 603 of the RFA. Section 6.4 is a detailed
description of the small business economic analysis performed for the final rule.
6.2
REGULATORY FLEXIBILITY ANALYSIS COMPONENTS
Section 603 of the RFA requires that FRFA must contain the following:
State the need for and objectives of the rule.
Summarize the significant issues raised by public comments on the IRFA and the
Agency's assessment of those issues, and describe any changes in the rule resulting from
public comment.
Describe the steps the Agency has undertaken to minimize the significant economic impact
on small entities consistent with the stated objectives of the applicable statutes, including a
statement of the factual, policy, and legal reasons for selecting the alternative adopted in
the final rule and why each one of the other significant regulatory alternatives to the rule
considered by the Agency which affect the impact on small entities was rejected.
Describe/estimate the number of small entities to which the rule will apply or explain why
no such estimate is available.
6-1
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• Describe the projected reporting, recordkeeping, and other compliance requirements of the
rule, including an estimate of the classes of small entities that will be subject to the
requirements of the rule.
The following sections address these issues.
6.2.1 Need for and Objectives of the Rule
The rule is being promulgated 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.
6.2.2 Significant Issues Raised by Public Comments on the IRFA
No comments on the IRFA were received, either at proposal or in comments on EPA's Notice of
Data Availability.
6.2.3 Steps Taken By the Agency To Minimize Significant Economic Impact on Small
Entities
The small entities currently drilling in the deepwater regions of the Gulf of Mexico primarily
undertake exploratory drilling. The selection of the BAT 2 option minimizes economic impacts on small
entities because it provides cost savings for drilling most wells.
6-2
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6.2.4 Estimated Number of Small Entities To Which the Rule Will Apply
6.2.4.1 Small Business Definitions
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). When making classification determinations, SBA counts receipts or employees of the
entity and all of its domestic and foreign affiliates (13 CFR.121.103(a)(4))). SBA considers affiliations to
include:
• stock ownership or control of 50 percent or more of the voting stock or a block of stock
that affords control because it is large compared to other outstanding blocks of stock (13
CFR 121.103(c)).
• common management (13 CFR 121.103(e)).
• joint ventures (13 CFR 121.103(f)).
EPA interprets this information as follows:
Sites with foreign ownership are not small (regardless of the number of employees or
receipts at the domestic site).
The definition of small is set at the highest level in the corporate hierarchy and includes all
employees or receipts from all members of that hierarchy.
If any one of a joint venture's affiliates is large, the venture cannot be classified as small.
Effective October 2000, SBA switched the basis for the size standards from Standard Industrial
Classification (SIC) to North American Industrial Classification System (NAICS). Table 6-1 maps the
SIC and NAICS classifications for this industry.
6-3
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Table 6-1
SIC and NAICS Size Standards
Industry
Crude Petroleum and Natural Gas
Extraction
Drilling Oil and Gas Wells
Support Activities for Oil and Gas
Operations
Other Oil Field Exploration Services
Geophysical Mapping and Surveying
Services
Deep Sea Foreign Transportation of
Freight
SIC
1311
1381
1389
1382
1382
4412
NAICS
211111
213111
213112
213112
54136
483111
NAICS Standard
(Number of Employees
or Revenue in SMillions)
500
500
$5
$5
$4
500
6.2.4.2 Estimated Number of Small Business Entities
The small business definitions and the methodology were outlined in the April 2000 NODA and the
February 1999 Proposal Economic Analysis and have not changed. Briefly, EPA relied on Small Business
Administration's size standards to determine whether a firm is a small business. If EPA could not find
employment or revenue'data to confirm a firm's size, it was classified as "potentially" small. EPA
identified a total of 40 small and potentially small firms as of the end of 1999.
Table 6-2 presents the available financial data on all publicly traded small firms in the analysis,
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).1 The typical small firm
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 3-3 in Section Three).
'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
these ratios might overstate returns by roughly a third for certain small firms.
6-4
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Among all small firms identified (including those identified at proposal, the median assets (1999
data) for this group (among publicly held firms) is about $270 million, median equity is about $140
million, and median revenues are about 72 million. Due to a relatively hard year for the oil and gas
industry, the median net income is a loss of about $310,000. Median return on assets is -0.7 percent and
median return on equity is zero percent, with median net income to revenues (net profit margin) is about -
3.6 percent. Median employment is approximately 89 persons. In the oil and gas industry, financial health
varies as swiftly as oil prices. In 1999, the average domestic first purchase price was $15.56/bbl and the
wellhead price for gas was $2.08/Mcf. In the first seven months of 2000, oil prices averaged $25.50/bbl
and gas prices averaged $2.82/Mcf (DOE, 2000). The financial health of the oil firms should show a
corresponding increase.
6.3 SMALL BUSINESS ANALYSIS
EPA certifies that no small businesses incur significant economic impacts as a result of the selected
option. Only shallow water wells drilled with SBF in the baseline show a cost increase under the selected
option. EPA did not identify any small firms currently using SBFs in shallow water.
EPA used a sales test to determine the magnitude of impacts that might be incurred by small firms
that use SBFs under the rejected zero discharge option. As mentioned above, EPA did not identify any
small firms using SBFs in shallow water. Therefore, EPA has determined that the likeliest users of SBF in
shallow water locations would be large operators who use SBF in deep water operations. Thus small firms
with deep water operations would be the potentially affected firms. At proposal, EPA had identified only
one small business that was drilling in the deep water regions of the Gulf of Mexico. Using MMS drilling
data through 1999, however, EPA has identified one additional small firm drilling in the Gulf of Mexico in
water depths exceeding 1,000 feet. This small firm and the one identified at proposal are primarily drilling
exploratory wells and have averaged 2 to 4 wells, respectively, drilled in deepwater in 1998 and 1999. If
the zero discharge option had been selected, costs would have been estimated to be 5 percent to 8 percent of
revenues among these firms.
6-6
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6.4 REFERENCES
Beck, Robert J. and Laura Bell. "OGJ 200 Companies Posted Strong Financial Year in 1997." Oil and Gas
Journal.
DOE. 2000. Monthly Energy Review. Department of Energy. Energy Information Administration.
Washington, DC. DOE/EIA-0035(2000/10). October, Tables 9.1 and 9.11.
6-7
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SECTION SEVEN
COST-BENEFIT ANALYSIS
EPA chose to quantitatively and qualitatively compare the costs and benefits of the preferred
discharge option. The findings are presented in detail in EPA's Environmental Assessment Report.1 The
selected option, BAT 2, results in a savings to industry of $ 49 million, including both existing and new
operations. Not only does industry save money, but EPA also projects positive benefits:
Fewer SBF wells are needed to produce the same output from the same formations than
WBF wells because SBF fluids are more efficient and allow more directional drilling.
Less fluid is needed for SBF wells than for WBF wells because an SBF-borehole is
slightly over half the diameter of a WBF borehole. Therefore, less fluid is discharged
with lower impacts on the benthic community.
Energy requirements are lower because SBF wells are drilled faster and fewer trips are
needed to transport cuttings to shore for disposal. Overall, EPA estimates a savings of
nearly 200,817 BOE/yr (195,124 for BAT and 5,693 for NSPS).
Air emissions are lower because the drilling equipment including solids removal runs for
fewer days per well and fewer trips are needed to transport cuttings to shore for disposal.
EPA estimates a reduction of nearly 3,073 tons/yr for BAT sources and an increase of
145 tons/yr for NSPS sources for a net reduction of about 2,927 tons/yr.
The rejected BAT 1 option shows slightly larger reductions in energy and air emissions than the selected
option. The selected option does not permit the discharge of fine particles separated from the drilling
fluid, hence it involves more annular injection or transport to shore than BAT 1.
Under the rejected zero discharge option, approximately 187 million pounds would not be
discharged from existing sources and 10 million pounds would not be discharged from new sources.
'U.S. EPA, 2000. Environmental Assessment of Final 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. EPA-821-B-00-014.
7-1
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However, the reduction in pollutant loadings is offset by:
$29 million cost annually to industry.
An increase of 51 million pounds of WBF and WBF-cuttings being discharged to the U.S.
offshore waters because operations would switch from SBF to less efficient WBF
drilling.
Increased energy use equal to nearly 376,731 BOE/yr (358,664 for BAT and 18,067 for
NSPS).
Higher air emissions because the drilling equipment including solids removal runs for more
days per well and more trips are needed to transport cuttings to shore for disposal. EPA
estimates an increase of nearly 5,602 tons/yr for BAT sources and 528 tons/yr for NSPS
sources for a net increase of about 6,130 tons/yr.
An increase of 24 million Ibs of OBF-cuttings being injected onsite and 157 million Ibs of
OBF cuttings being hauled ashore for disposal.
7-2
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SECTION EIGHT
ENVIRONMENTAL JUSTICE ANALYSIS
Section 8 examines whether the rejected zero discharge option, BAT 3, may have a potential
environmental justice effect on minority and low-income populations surrounding onshore injection wells
and landfarming facilities. Appendix C explains the methodology and provides supporting documentation
for this analysis. Since the early 1970s, there has been concern that minority and low-income populations
experience higher-than-average exposure to environmental contaminants (Bryant, 1992; Bullard, 1992).
These populations may bear disproportionate environmental and human health impacts because disposal
facilities tend to be in areas with minority and economically disadvantaged populations.
Environmental justice ensures that no population will be subjected to disproportionate
environmental threats to public health. The U.S. EPA defines environmental justice as:
"The fair treatment and meaningful involvement of all people regardless of race, color,.
national origin, or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and policies. Fair treatment means that
no group of people, including racial, ethnic, or socioeconomic group should bear a
disproportionate share of the negative environmental consequences resulting from
industrial, municipal, and commercial operations or the execution of federal, state, local,
and tribal programs and policies." (http://es.epa.gov/oeca/main/ej/index.html)
Under federal mandate, no stages of policy, guidance, activity, and regulation development should
cause minority and low-income populations to experience significantly higher-than-average exposure rates
to toxic and hazardous contaminants. On February 11, 1994, the White House issued Executive Order
12898 on Federal Actions to address environmental justice in minority and low-income populations. The
order, Federal Actions to Address Environmental Justice in Minority Populations and Low-Income
Populations, is designed to focus federal agencies' attention on environmental and human health
conditions in minority and low-income communities. The order directs each federal agency "to make
achieving environmental justice part of its mission by identifying and addressing, as appropriate,
disproportionately high and adverse human health or environmental effects of its programs, policies, and
activities on minority populations and low-income populations" (Clinton, 1994).
8-1
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8.1 OVERVIEW OF THE ENVIRONMENTAL JUSTICE SCREENING ANALYSIS
The objective of this environmental justice screening analysis is to determine whether the zero
discharge option of the effluent guidelines may disproportionately affect minority and/or low-income
populations. The analysis identifies disposal facilities that accept SBFs and are surrounded by significantly
higher-than-average minority and/or low-income populations.
The Gulf of Mexico is associated with the only known current use of SBFs and discharge of SBF
cuttings (U.S. EPA, 1999). Disposal facilities that accept SBFs are within U.S. EPA Region 6, in Texas
and Louisiana (Veil, 1999). To meet the general directive of Executive Order 12898, Region 6 developed
an environmental justice methodology tailored to the states within its region (Johnston, 2000). This
methodology provides for a tier one screening analysis to evaluate whether sociodemographic data
indicate that a disposal facility should be identified as a potential environmental justice case. If the
percentage of minority and low-income people living within specified distances of a disposal facility are
significantly higher than the state average, the site would be considered a potential environmental justice
case. A tier one screening was performed for all disposal facilities accepting SBFs, and the methodology
and results are detailed in Appendix C.
A tier one screening is limited because it does not include a site-specific analysis of the
populations risk of exposure to contaminants. In a tier two analysis, potential environmental justice cases
would undergo further analysis to consider the fate and transport mechanism of the involved facilities'
contaminants and to determine if the populations would be subject to high and adverse environmental and
public health effects resulting from contaminants. Additionally, locations of other facilities near the
populations would be assessed to determine possible cumulative exposure to contaminants. The objective
of this environmental justice screening analysis is to identify potential environmental justice cases.
Because the selected option is not the option which might have possible environmental justice
concerns—zero discharge—a tier two analysis has not been conducted.
8-2
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8.2 IDENTIFICATION OF OIL AND GAS WASTE DISPOSAL SITES
Under the zero discharge option, SBFs arriving onshore would be disposed of by Newpark
Environmental Services and U.S. Liquids. Appendix C shows the locations of the marine transfer
facilities, process facilities, injection sites, and landfarming facilities owned by tfiese companies. With the
exception of the landfarming facilities, all the facilities are owned by Newpark Environmental Services.
The environmental justice screening analysis assumes that 80 percent of SBFs would be disposed of by
Newpark and 20 percent would be disposed of by U.S. Liquids (Newman, 2000).
8.3 SUMMARY OF METHODOLOGY
A detailed discussion of the environmental justice methodology is presented in Appendix C.
Briefly, to identify potential EJ sites, EPA used a screening tool developed by Region 6 (the location of the
sites in question). The methodology assesses the characteristics of neighborhoods located within a 1- and
50-square mile buffer zone around toxic or hazardous waste or facilities that emit toxic or hazardous
waste. A site is determined to be a potential environmental justice case if the buffer area has a
significantly higher minority and/or low-income populations thaii the state average. Buffer areas are
used because residences closer to the source are likely to have a higher risk of exposure.
The GIS application uses an index formula developed by Region 6 to mathematically compare the
percentage of the population groups within a buffer area to the state average percentages (U.S. EPA,
1996). The index evaluates the potential degree of vulnerability for the population exposed to the
facility. The index for this tier one screening analysis does not consider the degree of impact from
potential exposure and toxicity. A tier two risk screening analysis could determine the degree of impact
for sites identified as potential environmental justice cases.
8-3
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8.4 RESULTS
EPA conducted thirteen Region 6 environmental justice screening analyses to determine whether
the facilities are potential environmental justice cases. A GIS application used minority, population, and
low-income data to rank each facility and produce mapping and tabular outputs. Detailed results and
maps are provided in Appendix C.
Of the 13 disposal sites identified, five are estimated to be potential environmental justice sites.
Morgan City, Venice, Bateman Island, and Mermentau facilities are potential environmental justice cases
within the 1-square mile area. Port Fourchon and Venice facilities are potential environmental justice
cases within the 50-square mile area.
8-4
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8.5 REFERENCES
Bryant, B., and P. Mohai. 1992. Race and the Incidence of Environmental Hazards: a Time for
Discourse. Westview. Boulder, CO.
Bullard, R. 1992. In Our Backyards: Minority Communities Get Most of the Dumps. EPA Journal 18
(March/April): il-12.
Clinton, William Jefferson. 1994. Executive Order on Federal Actions to Address Environmental
Justice in Minority Populations and Low-income Populations. Executive Order 12898. Washington,
DC. 59 Federal Register 7629-7633. February 16.
Johnston, C.A. 2000. Update on Several Model Input Parameters for Offshore Injection and Land
Disposal (Injection and Landfarming) Operations for Zero Discharged SBF Wastes. Memorandum to
file, August 14, 2000.
Newman, A. 2000. Personal communication with Nerija Orentas, E.H. Pechan & Associates, July.
U.S. EPA. 1996. Environmental Justice Index Methodology. Region 6 Compliance Assurance and
Enforcement Division, Dallas, TX.
U.S. EPA. 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. EPA-821-B-98-020. Washington, DC. February.
Veil, J.A. 1999. Update on Onshore Disposal of Offshore Drilling Wastes. EPA Docket No. W-98-
26, III.D.13. Prepared for the U.S. EPA Engineering and Analysis Division and the U.S. Department of
Energy, Office of Fossil Energy, by Argonne National Laboratory, Washington, DC.
3-5
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APPENDIX A
DERIVATION OF WEIGHTED AVERAGE COST OF COMPLIANCE PER
WELL TYPE
EPA presented the number of wells and incremental cost of compliance or cost saving by well type,
water depth, and drilling fluid used in Section 5 (Table 5-1). These well counts and costs/cost savings are
derived from the Development Document (EPA, 2000), which provides well counts, the baseline cost of
drill cuttings disposed, the two discharge option costs and zero discharge option costs by region, assumed
baseline and post-compliance choice of drilling fluid, water depth, well type, and the assumed discharge or
disposal mode chosen by the operator (hauling to shore or injecting the waste). This appendix explains the
derivation of well counts and individual well costs found in Table 5-1 from data provided in the
Development Document.
A.1 DERIVATION OF WELL COUNTS
Tables A-l and A-2 reproduce the summary tables of the well counts and compliance costs for the
Gulf of Mexico and Alaska, respectively, provided in the Development Document. Well counts and costs
for California are not included because the regulation is estimated to have no impact on drilling in that
region. Well counts and costs in Table A-l and Table A-2 are broken down according to drilling fluid,
water depth, well type, and discharge/disposal mode.
The number of wells switching the type of drilling fluid used from a baseline to a post-compliance
scenario and the discharge/disposal mode under the various regulatory options are calculated from Tables
A-l and A-2. The well counts under the various options are estimated for water depth (deep or shallow),
well type (developmental or exploratory), and disposal mode (discharge, haul, or inject). For discharge
options 1 and 2, the difference between the number of wells using OBFs and WBFs and the number of
wells drilled using OBFs and WBFs in the baseline is the number of wells switching from OBF or WBF to
SBF for each group of wells. For the zero discharge option, the difference between the number of wells
drilled using SBF under zero discharge and the number of wells using SBFs in the baseline is the number of
wells switching from SBF to OBF or WBF for each group of wells. Further, the number of SBF wells
A-l
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changing discharge/disposal modes under the zero discharge option is also calculated. Table A-3 shows the
well count for each well group under the two discharge options and the zero discharge option for the Gulf
of Mexico and Alaska. *. .
Table A-3
Number of Wells Switching Drilling Fluids and Disposal Modes in Each Well Group
Well Group
Number of Wells
GULF OF MEXICO - DISCHARGE OPTIONS 1 AND 2
Development Wells - Deep Water
WBF discharge to SBF discharge
1
Development Wells - Shallow Water
OBF 80% haul to SBF discharge
OBF 20% iniect to SBF discharge
WBF discharge to SBF discharge
14
3
21
Exploratory Wells - Deep Water
WBF discharge to SBF discharge
1
Exploratory Wells - Shallow Water
OBF 80% haul to SBF discharge
OBF 20% iniect to SBF discharge
WBF discharge to SBF discharge
TOTAL
8
2
13
63
GULF OF MEXICO - ZERO DISCHARGE OPTION
Development Wells - Deep Water
SBF discharge to SBF 100% haul
SBF discharge to OBF 100% haul
SBF discharge to WBF discharge
3
8
5
Development Wells - Shallow Water
SBF discharge to OBF 80% haul
SBF discharge to OBF 20% iniect
68
18
Exploratory Wells - Deep Water
SBF discharge to SBF 100% haul
SBF discharge to OBF 100% haul
SBF discharge to WBF discharge
8
25
15
Exploratory Wells - Shallow Water
SBF discharge to OBF 80% haul
SBF discharge to OBF 20% inject
TOTAL
41
10
201
ALASKA - DISCHARGE OPTIONS 1 AND 2
Development Well - Shallow Water
OBF 100% iniect to SBF 100% iniect
1
Source: Development Document (EPA, 2000).
A-4
-------
As mentioned in Section 3, EPA worked with industry to estimate the percentage of wells drilled
with each type of fluid (WBF, OBF, or SBF) prior to the regulation, as well as the percentage of WBF or
OBF wells that would switch to SBF after the regulation. EPA estimates that almost 18 percent—or 201
wells—are drilled currently with SBFs and 6 percent—or 67 wells—are drilled with OBFs. The remaining
857 wells that are estimated to be drilled annually in the Gulf of Mexico are assumed to be drilled
exclusively using WBFs.
Under the discharge options, 27 OBF wells and 54 WBF wells would switch to using SBFs.
However, due to the increased drilling efficiency of SBF wells, a fewer number of SBF wells are needed to
replace WBF wells. This ratio of WBF to SBF efficiency is 3:2. In other words, 54 WBF wells convert to
36 SBF wells under the discharge options (i.e., 54:36 = 3:2 WBF:SBF efficiency). Under the zero
discharge option, the number of wells that switch from SBF to OBF and WBF is 190. The remaining 11
wells continue to use SBFs but change the discharge/disposal mode. (See Development Document for more
details.)
A.2 DERIVATION OF INCREMENTAL COSTS OR COST SAVINGS
Table A-4 shows incremental compliance costs per well according to the well groupings, i.e. based
on drilling fluid, water depth, well type, and discharge/disposal mode. These costs are also derived from
Table A-l and Table A-2. The incremental cost is calculated by subtracting the baseline cost per well from
the cost per well under the options BAT 1 through BAT 3 (zero discharge option) for each group of wells
according to the switch in use of drilling fluid and disposal mode. For WBF wells, per-well discharge costs
are calculated from aggregated WBF discharge costs. Table A-5 shows the derivation of WBF per-well
discharge costs. For each type of well, according to water depth, the sum of total rig time costs and total
costs of the discharged WBFs are divided by the total number of WBF wells affected by the regulation to
get per-well WBF discharge costs.
A-5
-------
Table A-4
Incremental Compliance Costs or Cost Savings According to Well Groups
Well Group
Number of Wells •
Option 1
Option 2
GULF OF MEXICO - DISCHARGE OPTIONS 1 AND 2
Development Wells -Deep Water
SBF discharge to SBF discharge
WBF discharge to SBF discharge
16
1
($2,785)
($820,278)
($2,404)
($819,897)
Development Wells - Shallow Water
SBF discharge to SBF discharge
OBF 80% haul to SBF discharge
OBF 20% inject to SBF discharge
WBF discharge to SBF discharge
86
14
3
21
$7,514
($25,409)
$1,858
($523,914)
$7,266
($25,657)
$1,610
($524,162)
Exploratory Wells - Deep Water
SBF discharge to SBF discharge
WBF discharge to SBF discharge
48
1
($30,626)
($1,822,587)
($28,007)
($1,819,968)
Exploratory Wells - Shallow Water
SBF discharge to SBF discharge
OBF 80% haul to SBF discharge
OBF 20% iniect to SBF discharge
WBF discharge to SBF discharge
51
8
2
13
($4,510)
($78,039)
($16,486)
($1,120,327)
($3,481)
($77,010)
($15,457)
($1,119,298)
GULF OF MEXICO - ZERO DISCHARGE OPTION
Development Wells - Deep Water
SBF discharge to SBF 100% haul
SBF discharge to OBF 100% haul
SBF discharge to WBF discharge
3
8
5
Zero Discharge Option
$119,391
$48,847
$817,493
Development Wells - Shallow Water
SBF discharge to OBF 80% haul
SBF discharge to OBF 20% inject
68
18
$32,923
$5,656
Exploratory Wells - Deep Water
SBF discharge to SBF 100% haul
SBF discharge to OBF 100% haul
SBF discharge to WBF discharge
8
25
15
$314,257
$146,129
$1,791,961
Exploratory Wells - Shallow Water
SBF discharge to OBF 80% haul
SBF discharge to OBF 20% inject
41
10
$73,529
$11,976
ALASKA - DISCHARGE OPTIONS 1 AND 2
Development Well - Shallow Water
OBF 100% iniect to SBF 100% iniect
1
Option 1
$99.968
Option 2
$99.968
Source: Development Document (EPA, 2000)
A-6
-------
Table A-5
Per Well Discharge Costs for WBF Wells
Well Type
Deep Water Development
Shallow Water Development
Deep Water Exploratory
Shallow Water Exploratory
Number*
1
2
32
19
Total Rig
Time costs
$640,000
$13,280,000
$2,800,000
$16,560,000
Total Cost of
Discharged WBF
$295,065
$6,215,040
$1,307,250
$7,735,185
Per Well Discharge
Cost
$935,065
$609,220
$2,053,625
$1,278,694
Source: Development Document (EPA, 2000).
* The number of wells refers to the number of WBF wells projected to switch to SBF under the two
discharge options. However, the actual number of wells that switch is lower because of the increased
drilling efficiency of SBF wells, as reflected in Table A-3.
In order to get total per-well costs per well type and fluid used, the discharge/disposal mode
categories are combined by totaling all costs for a region, type of well, baseline type of fluid, and water
depth. For example, to determine costs to development wells currently using OBF in shallow water under
Option 2, the 14 wells that are currently estimated to haul OBF and that would switch to SBF discharge are
assigned the Option 2 cost savings of $25,657, and the three wells that currently inject OBF that would
switch to SBF discharge are assigned a cost of $1,610 in Table A- 4. The weighted average cost per well
in this group is then calculated by dividing the total cost for the group by the total number of wells in the
group (17). In the example, the weighted average cost to switch a shallow water development well from
OBF to SBF is [(14 x -25,657 + 3 x 1,610) + 17], or -20,845. The results of these calculations are
reflected in Table 5-1, where incremental compliance costs for the Gulf of Mexico and Alaska are provided
according to well type, water depth, and fluid used.
A-7
-------
-------
APPENDIX B
ECONOMIC MODEL FOR OIL AND GAS PRODUCTION
IN THE DEEPWATER GULF OF MEXICO
B.I DESCRIPTION OF THE ECONOMIC MODEL
The Deepwater Gulf Model simulates the costs and petroleum production dynamics expected at
the platform or project level in the development and operation of a deepwater Gulf oil and gas project.
Data to define a project and its petroleum reservoir are entered into the model. Then, through a series of
internal algorithms, the model calculates the economic and engineering characteristics of the project.
The model is structured to be flexible. It is capable of modeling projects that are dynamic, with
development occurring over a multiyear drilling period, under a specific, assumed, drilling plan.
Furthermore, inputs for a wide variety of variables that define the development and production project can
be user-specified. These inputs include, in addition to drilling schedule, operating costs, initial petroleum
production, production decline rates, tax rate schedules, and wellhead prices.
The model calculates cost and production performance for each year of the projects' estimated
lifetimes. Additional outputs from the model include total production volume, project revenues, and both
present value and nondiscounted summary statistics. Annual values and summary statistics are used to
evaluate both the project and the effects of pollution control options.
B.I.I Model Phases
The project life of a deepwater Gulf operation producing oil and/or gas is divided into five phases:
1) from lease bid to the start of exploration, 2) from the start of exploration to the start of delineation, 3)
from the start of delineation to the start of development, 4) from the start of development to the start of
production, and 5) production.
B-l
-------
For NSPS options, EPA evaluates operations at the beginning of phase 1-lease bid through all 5
phases. For BAT options, EPA evaluates operations that have completed the first four phases and are in
the fifth phase. In some cases in the BAT option analysis, there may be some overlap between
development (the fourth phase) and production (i.e., some wells may be drilled while production continues
at other wells associated with the operation). The model is able to add wells to a project, consistent with
drilling plan assumptions.
The projects modeled are assumed to operate as long as they generate positive operating cash
flow for up to 30 years (further projections add little additional to present value calculations). Algorithms
within the model evaluate project economics annually, and the project is shut down when operating cash
flow goes negative.
B.1.2 Economic Overview of the Model
The economic characteristics of the model phases are quite different. Phases one through four
generate cash outflows; no revenues are earned during those periods. Since all the projects in the BAT
analysis are already operating, costs incurred during the first four phases are treated as sunk costs, except
in the case of costs for ongoing development (i.e., drilling of new wells while production from other wells
continues). Sunk costs are not incorporated into the project evaluation for the BAT model. The fifth
phase, production, typically generates net cash inflows. During this phase, the project continues to
operate as long as operating cash inflows exceed nondiscretionary cash expenses.
The model deals with a number of basic cash flows (or resource transfers) in the development
and production phases. The basic cash flows are as follows:
Leasing Phase:
Exploration Phase
Lease bid-cost of acquiring rights to explore and develop a tract of land
G&G costs-geological and geophysical expenses incurred prior to drilling
Exploration well costs-cost of drilling an exploration well
B-2
-------
Incremental drilling costs-additional cost of drilling due to new
regulations concerning drilling waste
Delineation Phase Delineation well costs-costs of drilling a delineation well
Incremental drilling costs-additional costs of drilling due to regulations
concerning drilling waste
Development Phase: Development well costs-cost of drilling a development well
Cost of building and installing a petroleum production platform
Infrastructure costs-costs of production equipment installed on the
platform
Incremental drilling costs-additional costs of drilling due to regulatory
requirements concerning drilling wastes
Production Phase:
Revenues from oil and gas production—production levels multiplied by
assumed wellhead price.
O&M costs—costs of operating and maintaining the well.
The inputs for these items are provided in Summary of Data to be Used in Economic Modeling
(Section ffl.G of the Rulemaking Record) hereafter called the Summary of Data report, with the
exception of incremental costs, which are shown in Table 5-1 for deep water development and
exploratory wells currently using SBFs, and the assumed drilling schedule presented in Table B-l.
B.2 STEP BY STEP DESCRIPTION OF THE BAT/NSPS MODELS
This section presents a sequential overview of how the model operates. Due to the way the
model was constructed (the BAT phases are presented first, then the NSPS phases), the first part of the
model starts with the production phase and ends with the shut down of the project either after 30 years of
production or when the project becomes unprofitable. Figure B-l presented at the end of this appendix
presents the inputs, calculations, and outputs for a sample oil and gas platform to illustrate the model's
algorithms.
B-3
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The following discussion is based on the computer printout in Figure B-l. Identification numbers
for specific lines are given in the left-hand margin. Table B-2 provides a list of user-specified inputs. The
values for these inputs are provided primarily in the Summary of Data report. All dollar values (e.g., costs
and revenues are expressed in thousands of 1999 dollars).
Line 1 identifies the operation and the pollution control option being analyzed.
Line 2 is the real discount rate, i.e., the cost of capital. This value is used throughout the model
to discount future cash inflows, cash outflows, and production so that they can be summarized in present
value terms. The rate used is 7 percent, as OMB guidance suggests (OMB, 1992).
Line 3 is the inflation rate. This parameter is used to reduce the value of the deductions for
depreciation and cost-basis depletion in future years. The rate used is 3 percent.
Lines 4 and 5 contain information relevant to the calculation of project taxes. The flag in Line 4
indicates whether the operation modeled is an integrated (major) or independent company. Majors must
calculate depletion on a cost basis, while independents may choose to do so on either a cost or a
percentage basis.
Major and independent operators also differ with respect to the treatment of capital investments
in calculating taxable income. Independents may expense 100 percent of their "intangible drilling costs
(IDCs), while majors may expense only 70 percent. The expensing of these costs reduces taxable
income in the year in which they are expensed and may provide a significant tax shelter.
It is assumed that the taxpayer (oil company) elects to expense IDCs in the year in which they
are incurred. IDCs are estimated, on average, to represent 60 percent of the costs of production wells and
their infrastructure [citation]. Hence, independents may expense 60 percent of total production well
drilling costs (1.00 x 0.60), and majors may expense 42 percent (0.70 x 0.60). The percentage of drilling
costs that are eligible for expensing is given in Line 5.
B-5
-------
Table B-2
Exogenous Variables Provided to EPA Economic Model
Parameter
Lease cost
Geological and geophysical expense
Real discount rate
Inflation rate
Years between lease sale and exploration
Percent of cost considered expensible intangible drilling costs
Drilling mud cost increment
Federal corporate tax rate
Drilling cost per exploratory well
Platforms per successful exploratory well
Years between start of exploration and delineation
Number of delineation wells drilled
Cost per delineation well
Total platform cost
Years between delineation and development
Number of development wells drilled
Number of development wells drilled per year
Drilling cost per development well
Annual pollution control capital costs
Oil and gas production decline rate
Cost escalator
Royalty rate
Depreciation schedule
Years between development and production
Years at peak production
Oil - peak production rate (bbl/day)
Gas - peak production rate (MMCF/day)
Number of producing wells
Drilling schedule
Wellhead price per barrel - oil
Wellhead price per Mcf - gas
Total operating costs (other than produced water)
Annual pollution control equipment operating cost (produced water)
B-6
-------
Lines 6-32 relate to the production phase in both the BAT and NSPS models. In the production
phase of the project, a variety of financial and engineering variables interact to form the project's
economic history. Oil, gas, and water production figures from 1998 are given in Lines 6, 7, and 8. Line
9 provides the production decline rate for oil and gas. The model uses this rate to create an exponential •
function for production decline so that a constant proportion of the remaining reserves is produced each
year. For every barrel produced in the initial year of.operation in this sample project, 0.92 barrel is
produced in the second year, (0.92)2 or 0.846 barrel in the third year, etc. See Coastal EIA (USEPA,
1996) for more information on the assumption.
The model is capable of handling cost escalation (see Line 10). In this analysis, EPA is
considering costs in real terms, and thus no escalation is assumed.
The royalty rates paid to the lessor of the land (in this case the federal government) are provided
in Lines 11 and 12. Federal and state corporate tax rates are listed in Lines 13 and 14. Lines 15 and
16 provide the number of years over which depreciation occurs and the depreciation schedule for
capitalized oil and gas equipment State severance taxes are not applicable so Lines 17 and 18 are zero.
Basic information describing the production phase of the project is listed in lines 19 through 32.
Line 19 is not used in this model Line 20 is not used here, but this information is input later in the NSPS
portion of the model. The number of years that a well produces at its peak rate is given in Line 21. The
per well peak production rates for oil and gas are given in Lines 22 and 23, respectively. These rates
apply to wells drilled and brought on line in the model years. Once these wells cease producing at peak
rates, production volumes decline annually according to the decline rate in Line 9. The assumed future
drilling plans are summarized in Line 24. Line 25 is not used (a drilling schedule, shown in Table B-2 is
used; information on how many wells drilled in which years are picked up by the model later in the
spreadsheet).
The wellhead prices for oil and gas are entered on Lines 26 and 27. These values are in 1999
dollars.
B-7
-------
Line 28 indicates the number of days per year that a platform or project produces. EPA
assumes all projects in the model operate continuously.
Annual operating costs are entered on Line 29, Line 30 is not used, since the regulatory options
for the SBF rule do not affect operating costs, these lines are zero both in baseline and postregulatory
scenarios. Line 31 is the regulatory option costs per well drilled in any year. Line 32 is not used.
B.2.2.1 Production Volume Calculations
The next several lines in the model calculate the annual production volumes for oil and gas, based
on the initial production rates given in Lines 6 and 7, the decline rate in Line 9, and the assumed future
drilling plans. Line 33 contains the number of producing wells brought into service each year. Line 34,
the total barrels of oil produced per day, is the sum of current production (from 1998, declined at the
appropriate rate and production from new wells brought into service each year). MMcf of gas per day,
Line 40, is calculated in the same manner. The annual oil and gas production numbers in Lines 36 and
41 are the estimated daily production numbers multiplied by the number of days of production per year
(Line 35).
In general production from a group of wells going into service in the same year is calculated as
follows:
Annual Production = Number of Wells x Barrels per Day per Well x Decline Rate(a) x Number of Days
Where a = year of production - number of years at peak production.
For projects with new wells going into production in different years, the equation is expanded in 'the
following manner:
Daily Production Year 2 = 3 wells x (for example) 1,000 bopd = 3,000 bopd
Daily Production Year 3 = (3 x 1,000 x 0.92)
B-8
-------
If additional wells were drilled in Year 4,
Year 4 = (3 x 1,000 xO.922) + (3 x 1,000) = [run calc.]
and so forth.
The price per barrel is repeated in Line 37 for convenience in cross-checking the gross revenues
from oil production (Line 43). Lines 42 and 44 list the wellhead price per Mcf of gas and gross
revenues from gas production.
B.2,2,2Income Statement
Lines 43 through 75 comprise an income and cash flow statement that is repeated annually for a
30-year project lifetime (these lines are repeated for years 11-20 and years 21-30, which are not
reproduced. Since most projects become uneconomical during this 30-year time-frame, line 66 checks for
negative net cash flow. When cash flow is negative, EPA assumes the project shuts down and actual
production, revenues, and cash flows are reset to zero in lines 67 through 73. Lines 43 and 44 list
revenues from oil and gas productions. Total gross revenues for the year are given in line 45. Royalty
payments (lines 46 and 47; see lines 11 and 12 for royalty rates) are calculated on the basis of gross
revenues. Lines 48 and 49 are not used, since no severance is paid in the deepwater Gulf.
Net revenues, line 50, are calculated as:
Net Revenues = Total Gross Revenues - Royalty Payments
Thus, for year 1 of production in the example in Figure B-l (year 13 of the project):
Net Revenues = $121,102 - $3,241 - $11,897
= $105,965
B-9
-------
Operating costs are given in lines 51 and 52. Line 51 lists the operating costs estimated for the
platform or facility itself. Incremental operating costs for compliance with pollution control regulations
appear in line 52. The latter figure reflects incremental costs due to drilling waste requirements.
Operating earnings (line 53) are defined as net revenues (line 50) minus operating costs (line 51)
minus pollution control operating costs (line 52). For year 2 for the project:
Operating Earnings = Net Revenues - Operating Costs - Pollution Control Operating Costs
= $105,965 - $19,599 - 0 = $86,406
Lines 54 and 55 divide capital costs into two categories for use in calculating the project's
taxable income. Line 54 contains the capital costs that can be expensed (in this case, IDCs, or costs for
drilling new and recompleted wells multiplied by the percentage in line 5). EPA assumes that oil and gas
companies expense the maximum allowable portion of their capital costs. Line 55 contains the capital
costs that must be capitalized, including pollution control capital costs and nonexpensible development
drilling costs.
The adjusted depreciation allowance in line 58 is calculated on the basis of the capitalized costs
in line 55 and the accelerated depreciation schedule in line 16. Because the model's values are given in
constant dollars, this figure must then be adjusted for inflation, using the rate in line 3. This adjusted value
is taken as a deduction against the taxable income associated with the project.
In the following year, the adjusted depreciation allowance contains the second-year effects from
the capital costs for the previous year and any first-year effects from the capital costs for the second year
of the well's life.
Line 57, earnings before interest, taxes and oil depletion allowance (ODA), is derived by
subtracting expensed capital costs and depreciation and amortization from operating earnings
B-10
-------
The adjusted depletion allowance {line 58) is a means of treating annual oil and gas production as
a wasting asset for tax purposes. For major producers, the depletion allowance is calculated on a cost
basis, while for independents, it is calculated on a percentage basis.
Earnings before interest and taxes (EBIT, line 57) is defined as earnings before interest and
ODA (line 76) minus the adjusted oil depletion allowance (line 58). The figure on line 57 forms the basis
for calculating federal and state income taxes in lines 60 and 61. Taxes are based on the rates .given in
lines 13 and 14. Earnings before interest and after taxes are given in line 62.
Project cash flows from operations, line 63, are determined by adding costs expensed for tax
purposes, depreciation, and depletion back into earnings after taxes.
Whether or not the project continues to operate is determined on the basis of operating earnings
(line 55). If (net revenues - total operating costs - pollution control operating costs) is less than 0, the
project is assumed to shut down. Under such circumstances, net cash flow from operations (line 63) will
also be 0. The model prints a "1" in line 66 for years in which the project operates and a "0" for years in
which the project does not operate.
In the event that the project is shut down, certain variables must be recalculated to reflect that oil
an gas are no longer being produced and sold. Lines 67 through 75 restate production volumes,
revenues, and cash flow in the event of a shutdown (i.e., production and revenues are set to zero after the
project shuts down). The model allows a negative tax to be calculated in the shutdown year and continues
to calculate depreciation after shutdown because it is assumed that the project is part of a larger, ongoing
company and that such deductions can be used to adjust taxable income from the company's other
operations.
Additional lines, not marked with line numbers repeat lines 33 to 75 are used to take production
cash flows out to 30 years of production. This completes the BAT portion of the model.
B-ll
-------
B.2.3 Earlier Phases (NSPS Model Only)
The next numbered lines apply only to the NSPS model. Lines 76 through 84 are inputs to the
NSPS model. The least cost, Line 76, is a user-specified input, the value of which is based on the lease
bid of the relevant platform used in the model (see summary)
Line 77 represents the costs of geological and geophysical (G&G) investigation of the site as a
percentage of lease cost. The value shown in line 77 is based on information from the Summary of Data
report. The total leasehold cost, Line 78, is the sum of the lease bid and G&G expenses. The total
leasehold costs is a cash outflow in Year 0 of the project; the value on line 3 is therefore the present value
of the leasehold cost The leasehold cost forms the basis for the depletion allowance as calculated on a
cost basis for major integrated producers.
Lines 79 through 81 present data calculated by the model using the drilling schedule in Table B-
2, but are not used for any calculations. Line 82 takes timing assumption inputs and places the time
between lease sale and start of production here. This value is taken from data presented in the Summary
of Data report. Lines 83 and 84 are not used in this model.
Lines 85 through 94 calculate the exploration costs for the project. The exploratory well costs
for the project. Line 85 presents the numbers of years between lease sale and start of exploration. This
timing assumption was derived in the Summary of Data report. Line 86 is the baseline cost of drilling an
exploratory well, which was provided as discussed in the Summary of Data report. Line 87 is the option
cost of the rule estimated for an exploratory well. Line 88 is not used (set to one). Line 89 is the
number of exploratory wells drilled. One exploratory well per find is assumed. All other exploratory
wells as determined in the Summary of Data report are assumed delineation wells. Delineation wells are
assumed to incur the same costs (baseline" and option) as exploratory wells. Line 90 adds lines 86 and 87
for a total exploratory well cost. Line 91 assumes in this model that all exploration wells at this project
are successful (alternative assumptions are not used in this model). Line 92 is not used. Lines 93 and
94 split the expensed and capitalized portions on the basis of line 5 (percent costs expensed), which varies
depending on whether the project is owned by a major or an independent.
B-12
-------
Once the various exploration costs and cash flows have been calculated, they are put in present
value terms as of the lease year. For all Gulf of Mexico deepwater projects, exploration costs are incurred
in Year 0 plus number of years between lease sale and start of exploration. In this case, exploration
expenses start in Year 1.
If an exploration well discovers petroleum, delineation wells may be drilled to confirm the size and
extent of the reservoir. In this project, one year is assumed to pass between the start of exploration and
the start of delineation (Line 95; Summary of Data report provides timing assumptions). In this model
four delineation wells (based on data obtained as presented in the Summary of Data report) are drilled,
Line 96, each costing the same as an exploratory well (Line 97). Line 98 is the regulatory option cost
for exploratory wells. One platform is assumed per project (for simplicity) in Line 99, although costs of
additional subsea wells or platforms are included, if applicable.
The delineation costs (Line 100) assume the number of delineation wells are evenly divided over
the number of years between delineation and development; in this case 4 wells have been divided over 4
years. Lines 101 and 102 split out the expensed and capitalized portion of these costs in each year.
Once the various delineation costs and cash flows have been calculated, they are put in present
value terms of the half year.
During the development phase, the infrastructure required to extract oil reserves from a site is
constructed. Development drilling is also conducted to increase production or to replace nonproducing
wells on existing sites. Line 103 shows the number of years between delineation and construction (based
on data presented in the Summary of Data report). The costs of constructing platforms, including the
costs of production equipment, are entered on Line 104. Line 105, pollution control capital costs, are
entered to account for regulatory option costs for any wells drilled during the construction phase (pollution
control costs are pulled in on line 52 for any wells drilled during the production phase). EPA assumes
these incremental costs are incurred in year one, which could slightly overstate the present value of these
costs. Note that in the baseline, this line will be zero.
B-13
-------
Since the-development phase of an oil and gas project may overlap with the production phase, the
model is designed to incorporate the annual costs of development and increases in production from new
wells into estimates of total annual expenses and revenues. These costs and revenues are accounted.for
in the production portion of the model described earlier. The drilling cost for a development well depends
on the type of well (subsea or platform-based or sidetrack) (see the Summary of Data report). The
number of wells drilled during the construction phase is shown in Line 106. Line 107 presents the
number of sidetracks drilled, since these are associated with lower costs (see Summary of Data report).
Line 108 is not used in this model. Drilling costs per development well or sidetrack are shown in Lines
109 and 110.
Lines 111 through 122 calculate the costs incurred each year from the drilling of production
wells and the construction of production equipment. The number of years over which construction occurs
is provided by the timing assumption in Line 20. In this case the timing assumption is 2 years (with the
costs incurred beginning in the second year), thus the costs are spread over one year, as shown. [Lines
111 and 112 repeat the information from lines 109 and 110.] Line 113 adds in the option cost for any
wells drilled after completion of the construction phase. Line 114 starts the clock for when production
begins, after the construction phase ends. Line 115 brings in the numbers of wells drilled in any year
after construction, given the drilling schedule. Line 116 is not used. The total drilling costs in each are
given in line 117. Line 118 splits the capital costs of the platform (line 106) over the total years of
construction. Line 119 splits the regulatory option costs in line 105 over three years (any additional
regulatory option costs associated with wells drilled after construction are accounted for in the year in
which they occur in the production phases in lines 54 and 55). Line 120 totals all capital expenditure.
Lines 121 and 122 split these expenditures into those which can be expensed and those which must be
capitalized on the basis of line 5.
Expensed development costs, Line 120, are the product of total drilling costs (Line 117) and the
percent of drilling costs eligible for expensing (Line 5). All costs not eligible for expensing are capitalized
and are treated as depreciable assets for tax purposes. Note, in particular, that any capital costs of
pollution control are not eligible for expensing as per tax code requirements. Capitalized development
costs appear in Line 122.
B-14
-------
All costs prior to production are written to an annual cash flow table, which is used in the
calculation of net present value. This table also takes in to account depreciation and depletion allowances
and calculates a tax shield. Capital expenditures that occur after the beginning of production are visible in
the production phase cash flow in lines 54-65.
B-15
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APPENDIX C
ENVIRONMENTAL JUSTICE ANALYSIS
Appendix C investigates whether the zero discharge option, BAT 3, may have a potential
environmental justice effect on minority and low-income populations surrounding onshore injection wells
and landfarming facilities. Since the early 1970s, there has been concern that minority and low-income
populations experience higher-than-average exposure to environmental contaminants (Bryant, 1992;
Bullard, 1992). These populations may bear disproportionate environmental and human health impacts
because disposal facilities tend to be in areas with minority and economically disadvantaged populations.
C.I WHAT IS ENVIRONMENTAL JUSTICE?
Environmental justice (EJ) ensures that no population will be subjected to disproportionate
environmental threats to public health. The U.S. EPA defines environmental justice as:
"The fair treatment and meaningful involvement of all people regardless of race, color, national
origin, or income with respect to the development, implementation, and enforcement of
environmental laws, regulations, and policies. Fair treatment means that no group of people,
including racial, ethnic, or socioeconomic group should bear a disproportionate share of the
negative environmental consequences resulting from industrial, municipal, and commercial
operations or the execution of federal, state, local, and tribal programs and policies."
(http://es.epa.gov/oeca/main/ei/index.htrnl')
Under federal mandate, no stages of policy, guidance, activity, and regulation development should
cause minority and low-income populations to experience significantly higher-than-average exposure rates
to toxic and hazardous contaminants. On February 11, 1994, the White House issued Executive Order
12898 on Federal Actions to address environmental justice in minority and low-income populations
(Clinton, 1994). The order, Federal Actions to Address EnvironmentalJustice in Minority Populations
and Low-Income Populations, is designed to focus federal agencies attention on environmental and human
health conditions in minority and low-income communities. The order directs each federal agency "to make
achieving environmental justice part of its mission by identifying and addressing, as appropriate,
C-l
-------
disproportionately high and adverse human health or environmental effects of its programs, policies, and
activities on minority populations and low-income populations" (Clinton, 1994).
C.2 OVERVIEW OF THE ENVIRONMENTAL JUSTICE SCREENING ANALYSIS
The objective of this environmental justice screening analysis is to determine whether the zero
discharge option of the effluent guidelines may disproportionately affect minority and/or low-income
populations. The analysis will identify those disposal facilities that accept SBFs and are surrounded by
significantly higher-than-average minority and/or low-income populations.
The Gulf of Mexico is associated with the only known current use of SBFs and discharge of SBF
cuttings (U.S. EPA, 2000). Disposal facilities that accept SBFs are within U,S. EPA Region 6, in Texas
and Louisiana (Veil, 1999). To meet the general directive of Executive Order 12898, Region 6 developed
an environmental justice methodology tailored to the states within its region (Johnston, 2000). This
methodology provides for a tier one screening analysis to evaluate whether sociodemographic data indicate
that a disposal facility should be identified as a potential environmental justice case. If the percentage of
minority and low-income people living within specified distances of a disposal facility are significantly
higher than the state average, the site would be considered a potential environmental justice case. A tier one
screening was performed for all disposal facilities accepting SBFs. Disposal facilities are described in
Section C.3, methodology in Section C.4, and results in Section C.5.
A tier one screening is limited in that it does not include a site-specific analysis of the populations
risk of exposure to contaminants. In a tier two analysis, potential environmental justice cases would
undergo further analysis to consider the fate and transport mechanism of the involved facilities'
contaminants and to determine if the populations would be subject to high and adverse environmental and
public health effects resulting from contaminants. Additionally, locations of other facilities near the
populations would be assessed to determine possible cumulative exposure to contaminants. The objective
of this environmental justice screening analysis is to identify potential environmental justice cases.
However, because the zero discharge option is not the option selected for promulgation, a tier two analysis
has not been conducted.
C-2
-------
C.3 STUDY AREA: FACILITIES, LOCATIONS, AND DISPOSAL OF SBFs
Under the zero discharge option, SBFs arriving onshore would be disposed of by Newpark
Environmental Services and U.S. Liquids. The disposal facilities owned by these two companies are
described by Argonne National Laboratory, via communication with the Louisiana Department of Natural
Resources, in the document Update on Onshore Disposal of Offshore Drilling Wastes (Veil, 1999).
Wastes disposed of by Newpark Environmental Services would be transported by boat to one of
the company's marine transfer facilities in Louisiana at Venice, Port Fourchon, Morgan City, Intracoastal
City, Ingleside, and Cameron. The wastes would then be loaded into barges and hauled to Port Arthur,
Texas where they would be processed and loaded into tank trucks. The trucks would then transfer the
wastes to an underground injection disposal site in Fannet, Texas, or nearby at its Big Hill facility. The Big
Hill facility also serves as a process station. According to Newpark officials, the Fannet site has up to one
billion barrels of waste reserve disposal capacity (Veil, 1999).
U.S. Liquids operates landfarming facilities in Louisiana at Mermentau, Elm Grove, Bourg, and
Bateman Island. U.S. Liquids treats the waste by land spreading and land treatment. U.S. Liquids receives
almost none of the offshore wastes brought to shore because it only receives waste that Newpark
Environmental Services elects not to take. U.S. Liquids no longer owns the marine transfer stations now
operated by Newpark Environmental Services. Figure C-l and Table C-l show the locations of the marine
transfer facilities, process facilities, injection sites, and landfarming facilities. With the exception of the
landfarming facilities, all the facilities are owned by Newpark Environmental Services.
Under the zero discharge option using Best Available Treatment Economically Achievable (BAT)
for existing sources and New Source Performance Standards (NSPS) for new sources, SBFs would be
brought to shore and disposed of in injection wells and landfarming facilities (U.S. EPA, 2000). For
shallow water wells, 80 percent of SBFs would be disposed of onshore and 20 percent through offshore
onsite injection. For deep water wells, all SBFs would be disposed of onshore (Johnston, 2000).
C-3
-------
Figure C-l
SBF Waste Disposal Faculties
B;« u:u PortArthur
Big Mill yf Intracoastal City
Fanwat** <&-—*-^. ^^-, , Bateman Is I
« Transfer Station (6)
J. Landfarming (4J
+ Processing and Injection Facility (1)
• Processing Facility (1)
* Injection Facility (1)
Source: Map prepared by Eastern Research Group, Inc., July 2000, using 1990 Census TIGER/Line files to accurately locate
facilities. Locational information to create the map obtained from: (1) Newpark Environmental Services, July 2000; (2)
Cameron Chamber of Commerce, July 2000; (3) Greater LaFourche Port Commission
fhttp://www.geocities.com/BourbonStreet/Delta/1287/portmap.htmn. July 2000; and (4) U.S. Liquids
flrttp://www.usliquids.com/no\v_division.htmQ, July 2000.
C-4
-------
Table C-l
SBF Waste Disposal Facilities Owned by
Newpark Environmental Services and TJ.S. Liquids
Newpark Environmental
Services
Big Hill
Cameron
Fannet
Ingleside
Intracoastal City
Morgan City
Port Arthur
Port Fourchon
Venice
•;.• -' •. • ',-• . ••• •-••• '•• .-•.:
U£. Liquids ', •..::••..;-. v.:;:
Bateman Island
Bourg
Elm Grove
Mermentau
Address
26400 Wilber Road, Winnie, TX, 77665
26462 Wilber Road, Winnie, TX, 77665
434 Davis Road, Cameron, LA, 70631
15173 Wilber Road, Hampshire, TX, 77622
2725 Garrett Road, Ingleside, TX, 78362
12334 Offshore Road, Abbeville, LA, 70510
101 Second Street, Morgan City, LA, 70381
8300 Pleasure Islet Road, Port Arthur, TX, 77641
145 17th Street, Port Fourchon, LA, 70357
181 Anselmi, Port Fourchon, LA, 70357
213 Coast Guard Road, Venice, LA 70091
-1, V •.':,"•,",''. -•.:>.•; -'*".'--.--.•••'-'.-:.- '--.-•: :'-', -' ':" ',-.-., '. /£ :'.",',; „"'" ;,:: .„ -.' '\.
.Address/ ;,.;•... , ,,.. -.•//,. ^,;;;. : v;;>-;j •;;-;-;;.;;; ::%
on Intracoastal Waterway, Morgan City, LA,
771 Bourg-Larose Highway, Bourg, LA, 70343
2714 Atkins Clark Road, Elm Grove, LA, 71051
11031 Campbell Wells Road, Jennings, LA,
Type of Facility
injection
processing and
injection
transfer
injection
transfer
transfer
transfer
processing
transfer
transfer
transfer
' Ty^of Fiacilffy^;: ';^;
land waste disposal
land waste disposal
land waste disposal
land waste disposal
Source: Addresses obtained from (1) Newpark Environmental Services, July 2000; (2) U.S. Liquids
(http://www.usliquids.com/now division.html'), July 2000; and (3) Louisiana Office of Conservation, list of permitted
commercial treatment and disposal facilities (http://www.dnr.state.la.us/cons/conserin/commfac.ssi'), July 2000.
C-5
-------
Table C-2 below outlines the amount of SBFs that would be disposed of onshore for shallow water
development wells (SWDs), shallow water exploratory wells (SWEs), deep water development wells
(DWDs), and deep water exploratory wells (DWEs). Shallow wells are in water less than 1,000 feet deep,
while deep wells are in water more than 1,000 feet deep.
Table C-2
Total Amount of SBF Waste Land-Disposed (in Pounds)*
Source
Existing Sources**
New Sources***
Total
SWD
. ' SWEv; .
-..;a)wip-,.^
2,852,661
2,852,661
5,705,322
v,,,,i)WE'.. •.;,::
16,913,557
16,913,557
Total
19,766,218
2,852,661
22,618,879
Source: U.S. EPA.2000.
*For Option BAT 3 (zero discharge option), no waste is disposed of by on-site injection.
**Pounds per year based on 3 DWD wells, and 8 DWE wells.
***Pounds per year based on 3 DWD wells.
As shown in Table C-2, the total amount of SBFs disposed of onshore for all existing sources is
19,766,218 pounds per year. The total amount of SBFs disposed of onshore for all new sources is
2,852,661 pounds per year. The total amount disposed of onshore for both new and existing sources is
22,618,879 pounds per year. No SBFs would be disposed of through subsurface on-site water injection.
The environmental justice screening analysis assumes that 80 percent of SBFs would be disposed
of by Newpark and 20 percent would be disposed of by U.S. Liquids (Newman, 2000a). Therefore, for
both new and existing sources, approximately 18,095,103 pounds of SBFs would be disposed of onshore
by Newpark and 4,523,776 pounds of SBFs would be disposed of onshore by U.S. Liquids.
C-6
-------
Assuming the SBFs would be distributed proportionally among the Newpark facilities, 3,231,268
pounds of SBFs would pass through each transfer facility. The waste would then be distributed among its
process facilities; Big Hill and Port Arthur would each receive 11,309,439 pounds of SBFs. The waste
would then be injected into wells, with Big Hill and Fannet each receiving 11,309,439 pounds of SBFs.
Assuming that the remaining SBFs would be distributed proportionally among each U.S. Liquid
landfarming facility, each facility would receive 2,827,359 pounds of SBFs.
C.4 DESCRIPTION OF REGION 6 ENVIRONMENTAL JUSTICE METHODOLOGY
Region 6 developed a screening tool that can evaluate facility locations for potential environmental
justice issues. The region developed the tool according to the requirements as laid out in Executive Order
12898. The methodology assesses the characteristics of neighborhoods located within 1- and 50- square-
mile buffers around toxic or hazardous waste or facilities that emit toxic or hazardous waste. A site is
identified as a potential environmental justice case if a buffer area has significantly higher minority and/or
low-income populations than the state average. The methodology is detailed in the Region 6 Environmental
Justice Index Methodology (U.S. EPA, 1996). Figure C-2 outlines the screening methodology.
Region 6 created an automated Geographic Information Systems (GIS) application that analyzes
the sociodemographic make-up of 1- and 50- square-mile buffer areas surrounding a facility, and then
compares the characteristics of the area to those of the state as a whole. Buffer areas are used because
residences closer to the source are likely to have a higher risk of exposure. More specifically, the GIS
application is used to visualize the spatial distribution of sociodemographic indicators, to produce tables
summarizing sociodemographic parameters in the vicinity of the facility, and to rank a site for its potential
as an environmental justice case.
C.4.1 What Data Are Used?
Before the environmental justice screening analysis can be performed, sociodemographic
information for the potentially affected must be obtained. 1990 U.S. Census data for population, minority,
C-7
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and household income are read from the Census Summary Tape File (STF) 3-A and joined with census
geographic boundaries in the GIS application.
The minority data are obtained at the census block level and are the total of the non-White
population and the White Hispanic-Origin population. Data on low-income or economically stressed
households are obtained at the block group level for households with incomes of less than $15,000 per year.
Each of these categories of data are obtained for census blocks and block groups within both the 1- square
mile and 50- square-mile buffer areas around the facility.
C.4.2 How are Sites Evaluated?
The GIS application combines the minority population in each census block and the economically
stressed households population in each block group for the 1- and 50- square-mile buffer areas. The total
minority percentage would be calculated by taking the total minority population in the buffer area and
dividing by the total population in that area, and then multiplying by 100.
The GIS application uses an EJ Index formula developed by Region 6 to mathematically compare
the percentage of the population groups within a buffer area to the state average percentages. The index
• determines the potential degree of vulnerability for the populations exposed to the facility. The index for
this tier one screening analysis does not consider the degree of impact from potential chemical exposure
and toxicity. A tier two risk screening analysis for those sites identified as potential environmental justice
cases could be used to determine the degree of impact. Detailed information on the E J Index and its relation
to the region's Human Health Risk Index (HRI) formula can be found in the document Environmental
Justice Index Methodology (U.S. EPA, 1996).
The GIS application calculates EJ Indexes by finding the percentage for each population group
within the buffer areas, ranking the percentage based on scaling criteria, and then multiplying the rankings.
The EJ formulas listed below assume that the total population of a buffer area is affected by environmental
justice factors.
C-9
-------
EJ Index (population) = [Population Ranking (ranges from 0 to 4)]
EJ Index (minority) = [Minority Ranking (ranges from 1 to 5)]
EJ Index (economic) = [Economic Ranking (ranges from 1 to 5)]
EJ Index (overall) = Population Ranking x (Minority Ranking x Economic Ranking)
According to the formulas above, population density, percent of minority population, and percent
of economically stressed households are first ranked individually and then as a whole to determine whether
there may be a disproportionate environmental burden. Individually, the percent of minority population and
percent of economically stressed household factors can receive a rank of 1 to 5. Population density can
receive a rank of 0 to 4. To calculate the overall EJ score, the application multiplies the individual scores
together. A site thus receives an overall ranking between 0 and 100.
Generally, a subfactor ranking ^ 3 or an overall EJ index ^ 12 may warrant identification as a
potential EJ case (Newman, 2000b). When the factors are evaluated independently, they often provide
greater insight into potential environmental justice concerns. For example, the 1- mile buffer area may
rank percent of minority population as 1 and percent of economically stressed households as 3. This site
may warrant a potential environmental justice case based solely on the area's percentage of economically .
stressed households.
C.4.3 What Are the Specific Ranking Criteria?
To calculate a buffer area's population ranking, the GIS application calculates the area's
population density, then compares that value to an average population density. Table C-3a shows how
population rank is derived. The population density ranges were determined by examining natural breaks in
the 1992 census population data for cities in the states located within Region 6.
The scaling criteria for percent of minority population and percent of economically stressed
households are state-specific. To calculate these rankings, the application calculates the percent of
minority population and percent of economically stressed households for the buffer areas and men
compares these values to the state average percentages. The state average percentages for these population
groups, based on state 1990 census data, are shown in Table C-3b.
C-10
-------
Table C-3a
Ranges of Population Density Ranges
Population bensity;(per square mile)
0
> 0 and < 200
> 200 and < 1,000
> 1,000 and < 5,000
> 5,000
'"_•: ' • '.'. v; ;ScaImg:sc6jre-:;;:>.,^^ '...:'1
0
1
2
3
4
Table C-3b
State Averages
State
Louisiana
Texas
Percent Minority
34.2
39.4
Percent Economically
Stressed
36.3
27.6
Table C-3c shows the relationship between minority and economic stressed household percentages,
the state average percentage, and the ranking criteria. For example, if the number of minority members
within the 1- square-mile buffer area in Texas is 65 and the total population within the 1- square-mile area
is 100, the percent of minority population would be 65. The percent of minority population for the area
would receive a ranking of 3 because the relationship percentage is between 1.33 and 1.66 times the Texas
state minority average of 39.4 percent.
C-ll
-------
Table C-3c
Ranking of Environmental Justice Indicators
Criterion
Percentage of residents in the risk group is less than or equal to the state average
percentage.
Percentage of residents in the risk group is greater than the state average percentage, but
less than or equal to 1.33 times the state average percentage.
Percentage of residents in the risk group is greater than 1.33 times the state average
percentage, but less than or equal to 1.66 times the state average percentage.
Percentage of residents in the risk group is greater than 1.66 times the state average
percentage, but less than or equal to 1.99 times the state average percentage.
Percentage of residents in the risk group is greater than or equal to 2 times the state •
average percentage.
Ranking
1
2
3
4
5
C.4.4 What are the Final Outputs?
For each site, the EJ screening analysis produces three final map outputs: "Minority Status,"
"Economic Status," and "Potential Environmental Justice Index." The "Minority Status" and "Economic
Status" maps display the spatial distribution of sociodemographic indicators. The census blocks or census
block groups within the 1- and 50- square-mile buffer areas are color-coded according to ranges that depict
different levels of degree of vulnerability. As such, census blocks and block groups that have minority or
low-income populations between > 1.33 and < 1.66 times the state percentage are colored orange and have
a ranking of 3. A table summarizes sociodemographic parameters in the vicinity of the facility location
including the percent of minority population, percent of economically stressed households, and population
density for both buffer areas. The table also shows a rank for each variable and an overall EJ index.
The "Potential Environmental Justice Index" map displays the spatial distribution of the criteria
ranked by census block. Each census block within the 1- and 50- square-mile buffer areas is color-coded
according to the overall EJ Index for that census block. A census block that receives a minority ranking of
3, economic ranking of 4, and a population ranking of 2 would have an overall ranking of 24. A census
C-12
-------
block with an overall ranking of 24 would be color-coded yellow. A table summarizes the same
information found on the table for the "Minority Status" and "Economic Status" maps.
C.4.5 What Assumptions Are Made in the Screening Analysis?
The Region 6 environmental justice screening analysis relies on the following assumptions: area
proportion analysis technique, buffer distance, geographical scale, EJ Index rankings, and the EJ formula.
Each of these assumptions are discussed below.
The area-proportion technique assumes that a population is evenly distributed throughout a census
block or block group. However, because population is rarely evenly distributed across an area, using the
area-proportion technique results in some amount of error. For example, suppose the boundary of a 1-
square-mile buffer area crosses through a census block and cuts it in half. Using the area-proportion
technique, the environmental justice screening analysis assumes that 50 percent of the population lives
outside the buffer area and 50 percent lives inside the buffer area. If a block with 2,000 residents is cut in
half, a population of 1,000 is used in the analysis. If all of the population in a census block resides outside
the buffer area, then the area-proportion estimate is high and populations would be erroneously included.
Conversely, if all of the population in a census block lives inside the buffer polygon, the area-proportion
estimate is low. In general, the size of the error generated by the area-proportion technique depends on the
number and size of the census blocks and block groups.
The choice of buffer distance is an important variable for determining whether potential inequities
exist. The appropriate interval distance to use (e.g., 0.5 miles, 1 mile, 2 miles, 4 miles, etc.) and the basis
for that selection influences the analysis. Inequities may not exist at a 0.5-mile distance but may exist at a
4-mile distance. Region 6 uses a 1- square-mile buffer area (0.56-mile radius) and 50- square-mile buffer
area (4- mile radius).
Geographic or spatial scales (e.g., census blocks, block groups) are important to consider in the
analysis because inequities may exist at one scale but disappear at another. In less densely populated areas
where census tracts and block groups are large, the data may not provide meaningful information.
C-13
-------
Additionally, block groups or census blocks adjacent to the buffer areas may contain potentially affected
populations that are not captured in the screening analysis.'
Rankings are influenced by the population size. Higher population areas require higher rankings.
If the minority and economic status rankings are both 5 but the site has low population density (a ranking
of 1), the highest possible EJ Index is only 25 (on a scale of 0 to 100.) Additionally, an unpopulated area
will rank as zero but may be owned by minority and/or low-income groups. Statistically, most overall EJ
Indexes will fall between 0 and 50. Cases in which the overall ranking can be greater than 50 are
summarized in Table C-4.
The EJ formula assumes that the total population of the buffer areas is affected by EJ factors. In
other words, potential source impacts are assumed to be equally distributed and all residents are assumed to
be potentially affected.
Table C-4
Environmental Justice (EJ) Indexes Greater than Fifty
Population
Ranking
3 '
4
3
4
4
Minority
Ranking
4
4
5
4
5
Economic
Ranking
5
4
5
5
5
Overall
Ranking
60
64
75
80
100
C-14
-------
C.5 RESULTS
EPA conducted thirteen Region 6 environmental justice screening analyses to determine whether
the facilities are potential EJ cases. The GIS application used minority, population, and low-income data
to rank each facility and produce mapping and tabular outputs. Section C.7 of this Appendix contains
three maps titled "Minority Status," "Economic Status," and "Potential Environmental Justice Index" for
each facility. Each map displays a color-coded vulnerability map as well as information on the population
ranking, minority ranking, economic ranking, and overall EJ index for each facility. Section C.4 of this
appendix explains in more detail how to interpret these outputs.
Tables C-5a and C-5b provide information on whether a facility is a potential environmental justice
case. The ranking and index information presented are taken from the mapping outputs provided in
Section C.7. According to Tables C-5a and C-5b, five out of thirteen disposal site are potential
environmental justice sites. Morgan City, Venice, Bateman Island, and Mermentau facilities are potential
environmental justice cases within the 1- square mile area. Port Fourchon and Venice facilities are potential
environmental justice cases within the 50- square mile area.
C-15
-------
Table C-5a
EJ Status Within 1- Square Mile Radius of Facility
Company
Sfewpark
Environmental
Services
J.S. Liquids
Facility Name
Big Hill
Cameron
Fannet
Ingleside
Ihtracoastal City
Morgan City
Port Arthur
Port Fourchon
Venice
Bateman Island
Bourg
Elm Grove
Mermentau
Population
Ranking
1
1
1
1
1
3
0
1
1
2
1
1
1
Minority
Status
1
1
1
1
1
3
1
1
1
5
1
1
4
"Economic
^Status
1
1
1
1
1
3
1
1
5
4
1
1
2
Environmental
/
Justice Index
1
1
1
1
1
27
0
1
. 5
40
1
1
8
^Potential
JE j Case
no
no
no
no
no
yes
no
no
yes
yes
no
no
ves
Table C-5b
EJ Status Within 50- Square Mile Radius of Facility
Company
tfewpark
Environmental
Services
J.S. Liquids
• Facility Name
Big Hill
Cameron
Fannet
Ingleside
Intracoastal City
Morgan City
Port Arthur
Port Fourchon
Venice
Bateman Island
Bourg
Elm Grove
Mermentau
Population
Ranking
1
1
1
1
1
2
2
1
1
2
1
1
1
Minority
Status
1
1
1
1
1
1
1
1
1
1
1
1
2
Economic
~ Status,
1
1
1
2
1
1
2
3
3
1
1
1
2
Environmental
Justice Index
1
1
1
2
1
2
4
3
3
2
1
1
4
Potential
E J-Case -
no
no
no
no
no
no
no
yes
yes
no
no
no
no
C-16
-------
C.6 REFERENCES
Bryant, B., and P. Mohai. 1992. Race and the Incidence of Environmental Hazards: A Time for Discourse.
Westview, Boulder, CO.
Bullard, R. 1992. In Our Backyards: Minority Communities Get Most of the Dumps. EPA Journal 18
(March/April): 11-12.
Clinton, William Jefferson. 1994. Executive Order on Federal Actions to Address EnvironmentalJustice in
Minority Populations and Love-Income Populations. Executive Order 12898. Washington, DC. 59 Federal
Register 7629-7633. February 16.
Johnston, C.A. 2000. Update on Several Model Input Parameters for Offshore Injection and Land Disposal
(Injection and Landfarming) Operations for Zero Discharged SBF Wastes. Memorandum to file, August 14,
2000.
Newman, A. 2000a. Personal communication with Nerija Orentas, E.H. Pechan & Associates, July.
Newman, A. 2000b. Personal communication with Gerald Carney, U.S. EPA Region 6, August.
Veil, J.A. 1999. Update on Onshore Disposal of Offshore Drilling Wastes. EPA Docket No. W-98-26,
III.D.13. Prepared for the U.S. EPA Engineering and Analysis Division and the U.S. Department of Energy,
Office of Fossil Energy, by Argonne National Laboratory, Washington, DC.
EPA. 1996. EnvironmentalJustice Index Methodology. Region 6 Compliance Assurance and Enforcement
Division, Dallas, TX.
EPA. 2000. Development Document for Final 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. Washington, DC. EPA-821-B-00-013. December.
C-17
-------
C.7 SUPPLEMENTAL MAPS
C-18
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