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CHAPTER ONE
CONTENTS
EXECUTIVE SUMMARY 1-1
1.1 Introduction 1-1
1.2 Data Sources 1-2
1.3 Industry Profile 1-3
1.4 Economic Impact Analysis Methodology Overview and
Aggregate Compliance Cost Analysis 1-4
1.5 Production Loss Impacts and Other Impacts to
Platforms and Facilities 1-7
1.6 Firm-Level Economic Impacts on the Coastal Oil
and Gas Industry 1-7
1.7 Regional and National Employment Impacts and Total
Output Losses 1-9
1.8 Impacts on the Balance of Trade, Inflation, and Consumers 1-11
1.9 Impacts on New Sources 1-11
1.10 Alternative Baseline Scenario' . . 1-11
1.11 Regulatory Flexibility Analysis 1-18
CHAPTER TWO DATA SOURCES 2-1
CHAPTER THREE INDUSTRY PROFILE 3-1
3.1 Introduction 3-1
3.1.1 The Regulated Universe 3-2
3.1.2 v The Affected Operations 3-2
3.2 The Process of Oil and Gas Extraction and the Wastes Generated 3-7
3.2.1 Drilling Operations 3-7
3.2.2 Production Activities 3-11
3.2.3 Miscellaneous Wastes 3-12
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CONTENTS (continued)
Page
3.3 General Overview of the Coastal Subcategory Industry 3-15
3.3.1 Wells, Platforms, Treatment Facilities, and
Production in the Coastal Region 3-16
3.3.2 Oil and Gas Firms Operating in the Coastal
Subcategory 3-20
CHAPTER FOUR ECONOMIC IMPACT ANALYSIS METHODOLOGY OVERVIEW
AND AGGREGATE COMPLIANCE COST ANALYSIS 4-1
4.1 Overview of Methodologies 4-1
4.2 Cost Annualization Purpose and Method 4-4
4.3 Regulatory Options 4-6
4.3.1 Produced Water and TWC Wastes 4-9
4.3.2 Drilling Fluids and Drill Cuttings 4-10
4.33 Other Miscellaneous Wastes 4-11
4.4 Aggregate Compliance Costs 4-12
4.4.1 BAT Options 4-12
4.4.2 NSPS Options 4-18
4.4.3 Total Estimated Cost of the Coastal Guidelines 4-20
CHAPTER FIVE PRODUCTION LOSS IMPACTS AND OTHER IMPACTS TO
PLATFORMS AND FACILITIES 5-1
5.1 Description of the Economic Model for Cook Inlet, Alaska,
Operations and Major Pass Dischargers 5-1
5.1.1 Economic Model Overview 5-2
5.1.2 Model Parameters and Variables 5-5
5.13 Model Calculation Procedures 5-6
5.1.4 Interpretation of Model Results 5-13
5.1.5 Data Sources and Values for Common Parameters and
Project-Specific Variables 5-15
5.1.6 Calculation Procedures 5-21
11
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CONTENTS (continued)
Page
5.2 Production Loss Modeling Results 5-22
5.2.1 Produced Water/Treatment, Workover, and Completion
Wastes 5-23
5.2.2 Drilling Wastes 5-28
5.23 Combined Impacts (Cook Inlet and Major Pass) 5-29
CHAPTER SIX FIRM-LEVEL ECONOMIC IMPACTS ON THE
COASTAL OIL AND GAS INDUSTRY 6-1
6.1 Analytical Methodology 6-2
6.1.1 Baseline Methodology 6-2
6.1.2 Postcompliance Analysis 6-2
6.2 Sources of Data 6-3
6.3 Results of Firm-Level Analysis 6-4
6.3.1 Baseline Analysis 6-4
6.3.2 Postcompliance Analysis 6-4
CHAPTER SEVEN REGIONAL AND NATIONAL EMPLOYMENT
IMPACTS AND TOTAL OUTPUT LOSSES 7-1
7.1 National-Level Output and Employment Impacts 7-3
7.1.1 Introduction 7-3
7.1.2 Methodology for Estimating National-Level Output
and Employment Impacts 7-5
7.13 National-Level Output Reductions and
National-Level Employment Impacts 7-7
7.2 Regional Employment Impacts 7-13
7.2.1 Introduction 7-13
7.2.2 Methodology 7-14
7.23 Results—Regional Employment Impacts From BAT Options ... 7-18
111
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CONTENTS (continued)
CHAPTER EIGHT IMPACTS ON THE BALANCE OF TRADE, INFLATION,
AND CONSUMERS 8-1
8.1 Impacts on the Balance of Trade 8-1
8.2 Impacts on Inflation and Consumers 8-2
CHAPTER NINE IMPACTS ON NEW SOURCES 9-1
CHAPTER TEN ALTERNATIVE BASELINE SCENARIO 10-1
10.1 Introduction and Profile of Affected Operations Under the
Alternative Baseline Scenario 10-1
10.1.1 Louisiana Open Bay Dischargers—Wells, Treatment Facilities,
Production, and Firms 10-6
10.1.2 Texas Individual Permit Dischargers—Wells, Treatment
Facilities, Production, and Firms 10-7
10.1.3 Financial Profile of Louisiana Open Bay and Texas Individual
Permit Firms 10-7
10.2 Costs of Compliance Under the Alternative Regulatory Baseline 10-13
10.3 Production Loss Analysis in the Alternative Baseline Scenario 10-16
10.3.1 Description of the Economic Model for the Louisiana Open
Bay and Texas Individual Permit Operators 10-16
10.3.2 Produced Water/TWC 10-19
10.4 Firm-Level Impacts Under the Alternative Baseline Scenario 10-35
10.4.1 Analytical Methodology 10-36
10.4.2 Results of Firm-Level Analysis 10-40
10.5 National and Regional Employment Impacts and Total Output Losses .. 10-49
10.5.1 National-Level Output and Employment Impacts 10-49
10.5.2 Regional Employment Impacts 10-55
10.53 Community-Level Impacts 10-61
10.6 Other Impacts 10-64
IV
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CONTENTS (continued)
CHAPTER ELEVEN REGULATORY FLEXIBILITY ANALYSIS 11-1
11.1 Introduction 11-1
11.2 Initial Assessment 11-1
11.2.1 Is the Rule Subject to Notice-and-Comraent
Rulemaking Requirements? 11-2
11.2.2 Profile of Affected Entities 11-2
11.2.3 Will the Rule Affect Small Entities? 11-2
11.2.4 Will the Rule Have an Adverse Economic Impact
on Small Entities? 11-3
11.2.5 Analysis of Significant Impact 11-3
11.3 Regulatory Flexibility Analysis 11-3
11.3.1 Need for and Objectives of the Rule 11-4
11.3.2 Summary of Impacts on Small Businesses as a
Result of the Effluent Guidelines 11-5
11.3.3 Issues Addressed in Public Comments and EPA's Responses .. 11-11
11.3.4 Significant Alternatives to the Rule 11-13
APPENDIX A ECONOMIC ASSUMPTIONS USED IN THE PRODUCTION
LOSS MODEL A-l
A.1 Model Parameters A-l
A.1.1 Corporate Income Tax Rates A-l
A. 1.2 Severance Taxes A-2
A.1.3 Royalty Rates A-4
A.1.4 Depreciation A-5
A.1.5 Oil Depletion Allowance A-6
A.1.6 Inflation Rate A-9
A.1.7 Discount Rate A-10
APPENDIX B EPA ECONOMIC MODEL FOR COASTAL PETROLEUM
PRODUCTION IN COOK INLET, ALASKA, AND THE
MAJOR PASSES OF THE MISSISSIPPI RIVER B-l
B.I Introduction B-l
B.I.I Model Phases B-l
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CONTENTS (continued)
B.1.2 Economic Overview of the Model B-2
B.2 Step-by-Step Description of the Model B-3
B.2.1 Development Phase B-5
B.2.2 Production Phase B-6
B.2.3 Summary Statistics B-12
APPENDIX C LOUISIANA OPEN BAY AND TEXAS INDIVIDUAL
PERMIT PRODUCTION LOSS MODEL C-l
C.I Introduction C-l
C.1.1 Model Phases C-l
C.1.2 Overview of the Economic Model C-2
C2 Step-by-Step Description of the Model C-4
C.2.1 General Model Data C-4
C.2.2 Income Statement C-9
C.2.3 Summary Statistics C-ll
VI
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LIST OF TABLES AND FIGURES
Page
TABLES
Table 1-1 Total Annual Costs for All Selected BAT and NSPS Regulatory Options ... 1-5
Table 1-2 Impacts of Selected Options 1-8
Table 1-3 Impacts of Produced Water Options 1-13
Table 1-4 Impacts of Selected Options 1-15
Table 1-5 Impacts of Produced Water Options, Results of Sensitivity Analysis
Using Alternative Cost Allocation Assumptions 1-16
Table 1-6 Alternative Baseline Regional Job Losses 1-18
Table 3-1 Platforms, Operators, and Wells in Cook Inlet 3-19
Table 3-2 Summary of Key Financial Indicators in Publicly Held
Coastal Firms Affected by the Effluent Guidelines 3-24
Table 4-1 BAT Regulatory Options Considered in the Economic Impact Analysis .... 4-8
Table 4-2 Aggregate Annual Costs for BAT Options by Regulatory Option
and Affected Group 4-14
Table 4-3 Assumed Drilling Schedule Used for Annualizing Drilling Costs 4-16
Table 4-4 Cost Annualization of Drilling Costs for Zero-Discharge Option 4-17
Table 4-5 Aggregate Annual Costs for Selected BAT Regulatory Options 4-19
Table 4-6 Total Annual Costs for All Selected BAT and NSPS Regulatory Options .. 4-21
Table 5-1 Sources of Cook Inlet Common Parameter and Project-Specific
Variable Values for the Production Loss Model 5-7
Table 5-2 Sources of Major Pass Common Parameter and Project-Specific
Variable Values for the Production Loss Model 5-9
Table 5-3 Summary of Cook Inlet Platform Data and Inputs 5-20
Table 5-4 Impacts of Produced Water Options on Cook Inlet Platforms 5-24
Table 5-5 Impacts of Produced Water Options on Major Pass Facilities 5-27
Vll
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LIST OF TABLES AND FIGURES (continued)
Page
Table 5-6 Impacts of Drilling Waste Options on Cook Inlet Platforms 5-30
Table 5-7 Total Impacts of Produced Water Options 5-31
Table 5-8 Impacts of Selected Options 5-34
Table 7-1 National-Level Output Losses Associated With Postcompliance
Production Losses for the Current Regulatory Baseline Under
the Selected Options 7-8
Table 7-2 National-Level Output Losses Associated With Delayed Production for .... 7-8
the Current Regulatory Baseline Under the Selected Options
Table 7-3 National-Level Employment Losses Associated With Lost Output
(Type 2 Losses) for the Current Regulatory Baseline Under the
Selected Options 7-10
Table 7-4 National-Level Employment Losses Associated With Delayed
Production (Type 4 Losses) for the Current Regulatory Baseline
Under the Selected Options 7-10
Table 7-5 Summary of National Employment and Output Losses for the Current
Regulatory Baseline Under the Selected Options 7-12
Table 7-6 Summary of Regional Employment and Output Losses for the Current
Regulatory Baseline Under the Selected Options 7-21
Table 7-7 Summary of Regional Employment and Output Losses for the Cook Inlet
Platforms Under the Option #3 for Produced Water (Zero Discharge) ... 7-21
Table 10-1 Median Financial Statistics on Revenues and Costs 10-9
Table 10-1 Median Financial Statistics on Assets, Equity, and Working Capital 10-10
Table 10-3 Median Financial Statistics on Profitability and Ability To Borrow 10-12
Table 10-4 Total Annual Pollution Control Costs Under the Alternative Baseline
Scenario (BAT and NSPS Costs) 10-15
Table 10-5 Impacts of Produced Water Options on Louisiana Open Bay Dischargers
and Texas Individual Permit Applicants 10-20
Table 10-6 Impacts of Produced Water Options 10-24
vm
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'age
LIST OF TABLES AND FIGURES (continued)
Table 10-7 Impacts of Produced Water Options on Major Pass Facilities Under
the Alternative Baseline Assumptions 10-25
Table 10-8 Impacts of Produced Water Options on Alternative Baseline 10-26
Table 10-9 Impacts of Selected Options 10-29
Table 10-10 Impacts of Produced Water Options on Louisiana Open Bay Dischargers
and Texas Individual Permit Applicants, Results of Sensitivity Analysis
Using Alternative Cost Allocation Assumption 10-33
Table 10-11 Impacts of Produced Water Options, Results of Sensitivity Analysis Using
Alternative Cost Allocation Assumption 10-34
Table 10-12 Changes in Equity and Working Capital Associated With Zero
Discharge 10-41
Table 10-13 Range and Median Change in Equity and Working Capital Associated
With Zero Discharge 10-43
Table 10-14 Combined Change in Equity and Working Capital Among Small Firms .. 10-44
Table 10-15 Results of Further Financial Analysis of Selected Coastal Region Oil and
Gas Production Operators 10-46
Table 10-16 National Output Losses Associated With Postcompliance Production
Losses for the Alternative Regulatory Baseline Under the Selected
Options 10-51
Table 10-17 National Output Losses Associated With Delayed Production for the
Alternative Regulatory Baseline Under the Selected Options 10-51
Table 10-18 National Output Losses Associated With Delayed Production for the
Alternative Regulatory Baseline Under the Selected Options 10-53
Table 10-19 National Employment Losses Associated With Delayed Production
(Type 4 Losses) for the Alternative Regulatory Baseline Under the
Selected Options 10-53
Table 10-20 Summary of National Employment and Output Losses for the
Alternative Regulatory Baseline Under the Selected Options 10-54
Table 10-21 Summary of Regional Employment and Output Losses for the Louisiana
Open Bay Dischargers Under the Selected Options 10-56
ix
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LIST OF TABLES AND FIGURES (continued)
Page
Table 10-22 Summary of Regional Employment and Output Losses for the Texas
Individual Permit Applicants Under the Selected Options 10-56
Table 10-23 Summary of Regional Employment and Output Losses for the Louisiana
Open Bay Dischargers and the Texas Individual Permit Applicants Under
the Selected Options 10-57
Table 10-24 Summary of Regional Employment and Output Losses for the Gulf of
Mexico Under the Selected Options 10-57
Table 10-25 Summary of Regional Employment and Output Losses for the Alternative
Regulatory Baseline Under the Selected Options 10-58
Table 10-26 Employment in Counties and Parishes Potentially Affected Under the
Alternative Baseline Assumptions 10-63
Table 11-1 Impact on Counties and Parishes Potentially Affected Under the
Alternative Baseline Assumptions 11-11
Table B-l Exogenous Variables Used in the Cook Inlet/Major Pass Production
Loss Model 3.4
Table B-2 Cost and Case Flow Uses in the Cook Inlet Production Loss Model B-14
Table C-l Exogenous Variables Used in the Gulf of Mexico Production Loss Model .. C-5
FIGURES
Figure 1-1 Overview of methodology for the economic impact analysis 1-6
Figure 3-1 Location of the Gulf of Mexico coastal region in Texas and Louisiana 3-3
Figure 4-1 Overview of methodology for the economic impact analysis 4-3
Figure 5-1 Overview of closure analysis methodology 5.4
Figure B-l Cook Inlet/Major Pass production loss model B-16
Figure C-l Oil:Water relationship over time (exponential decline) C-3
Figure C-2 Open Bay/Individual Permit production loss model C-13
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CHAPTER ONE
EXECUTIVE SUMMARY
1.1 INTRODUCTION
This final economic impact analysis (FEIA) examines compliance costs and economic
impacts resulting from the U.S. Environmental Protection Agency's (EPA's) Effluent Limitations
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point
Source Category (Coastal Guidelines) in compliance with Section 301 of the Clean Water Act
(CWA). The compliance costs of the final Coastal Guidelines arise from technologies to control
several wastestreams: produced water, which is a byproduct of oil production; drill cuttings,
which are pieces of rocks and gravel that come up with drilling fluids; drilling fluid and
associated effluents; and treatment, workover, and completion (TWC) wastes, which are
produced when wells are worked over to keep them productive. The FEIA estimates economic
impacts on both the project and firm level in terms of annualized compliance costs; oil and gas
production losses; and changes in equity, working capital, and other indicators of financial health.
In addition, the FEIA considers impacts on federal and state revenues, national-level output,
employment and associated impacts on affected communities, foreign trade, new sources, and
small entities.
The total annual compliance costs of the rule are $15.6 million for Best Available
Technology (BAT) economically achievable and $0.6 million for New Source Performance
Standards (NSPS), for a total cost of $16.2 million. Based on the analyses and results in this
FEIA, EPA concludes that effluent limits based on the following BAT technologies are
economically achievable: zero discharge of produced water and TWC wastes in the coastal
subcategory except for Cook Inlet; discharge limits based on improved gas flotation for produced
water in Cook Inlet; and discharge limits (based on offshore limits) for drilling wastes in Cook
Inlet. All other waste streams are current practice or are covered by CWA NPDES permits.
NSPS are current practice for all but TWC wastes for new and certain recompleted wells in the
Gulf of Mexico coastal area.
1-1
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The impacts evaluated in this FEIA take into account the requirements of EPA Region 6
Genferal Permits for the Coastal Oil and Gas Industry requiring zero discharge of produced water
adopted in 1995. Facilities covered by these Permits were not considered to be part of the
baseline during the proposal, but are for final rule promulgation. EPA also examines impacts on
an alternative baseline, under the assumption that, without the Coastal Guidelines, some
operators might receive individual permits allowing them to discharge despite the General
Permits. EPA considers this scenario unlikely, but nonetheless presents results of its alternative
baseline analysis in Chapter Ten of this FEIA. The remaining chapters of the FEIA describe the
different components of the economic analysis. Chapter Two describes data sources; Chapter
Three profiles the industry; Chapter Four describes compliance cost estimation, and results;
Chapter Five presents impacts on production; Chapter Six presents firm-level analysis; Chapter
Seven discusses impacts on employment; Chapter Eight summarizes impacts on inflation and
balance of trade; Chapter Nine presents an analysis of impacts on new sources; Chapter Ten
presents impacts under the assumption of an alternative baseline; and Chapter Eleven presents
the Regulatory Flexibility Analysis under the Regulatory Flexibility Act.
1.2 DATA SOURCES
Data sources for this FEIA include: costs for produced water disposal estimated by EPA
by permitted discharge facility or platform in Louisiana, Texas, and Alaska; data submittals by
firms discharging offshore produced water into major passes of the Mississippi River (Major Pass
dischargers) and Cook Inlet firms, and the Section 308 Survey of coastal operators, which is
described in more detail in the Economic Impact Analysis for the proposed Coastal Guidelines
(PEIA), and information of nonpublic sources such as the Securities and Exchange Commission
(SEC), the Bureau of Labor Statistics (BLS), the Bureau of Economic Analysis (BEA), and
Bureau of the Census.
1-2
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1.3 INDUSTRY PROFILE
The coastal oil and gas subcategory is unusual among industry sectors regulated under the
CWA because the vast majority of operations are already in compliance with Coastal Guidelines
requirements in this rule. For the proposal, EPA considered all coastal operations determined to
be discharging produced water and/or TWC wastes in the Louisiana/Texas portion of the Gulf of
Mexico by mid-1996 to be affected by the Coastal Guidelines. In early 1995, however, EPA
Region 6 promulgated General Permits for produced water, which cover all coastal operations in
the Gulf region except for offshore water discharged from a group of operators in the Major
Passes of the Mississippi. As a result, most of the Gulf operations affected by the Coastal
Guidelines at proposal are already subject to zero discharge requirements for produced water.
The rule affects only the Major Pass dischargers and a few operations discharging TWC wastes in
the Gulf of Mexico, and all operations in Cook Inlet, Alaska.
The Major Pass dischargers include eight produced water treatment/separation facilities
operating under six permits. Current total annual produced water discharge from these facilities
is 69.8 million barrels (bbls), with future projections of at least 104.7 million bbls annually.
Average daily produced water discharge ranges from 572 to 153,895 bbl per day (bpd).
Currently, these facilities service 350 wells, with lifetime production of 600 million total bbls of
oil equivalent (BOB).1 In the future, EPA expects these facilities will serve a much greater
number of wells, which would greatly expand their production of produced water.
Thirteen Cook Inlet platforms are currently operating with a total of 224 productive
wells, of which 197 are oil wells and 27 are gas wells. Estimated total annual production (1995)
is 13.7 million bbls of oil and 140,525 million Mcf (thousand cubic feet) of marketable gas. EPA
estimates total lifetime production to be 501.1 million BOE. Over a period of 7 years, producers
plan to drill 41 new wells and expect to perform 20 well recompletions.2 The platforms are
served by three land-based and five platform-based separation/treatment facilities. The three
is converted to an oil equivalent in this measure.
2See Chapter Two for definition of recompletions.
1-3
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land-based facilities treat and discharge about 98 percent of all produced water at a rate of about
130,000 bpd.
Firms affected by the Coastal Guidelines include three majors (large, vertically integrated
firms) in the Major Pass discharger group; three majors in the Cook Inlet group; and three
independents (smaller firms that are not vertically integrated) in the Major Pass discharger
group. All of the Major Pass dischargers and Cook Inlet firms that provided financial data are
corporations judged to be in adequate to good financial health.
1.4 ECONOMIC IMPACT ANALYSIS METHODOLOGY OVERVIEW AND AGGREGATE
COMPLIANCE COST ANALYSIS
The economic impact analysis estimates the following impacts:
• Compliance costs to industry.
• Production losses (in terms of quantities of oil and gas not produced compared to
a no-regulation [baseline] scenario).
• Lost economic lifetime (i.e., the loss of productive years associated with wells
shutting in earlier under the regulation than under a baseline scenario).
• Numbers of wells, production facilities, or platforms immediately ceasing
production as a result of the regulation (first-year shut-ins).
• Losses to operators (in terms of annualized compliance costs and losses in present
value of project net worth to the operator [NPV]),3 state governments, and the
federal government.
• Firm-level impacts (firm failure analysis).
• Employment impacts (losses and gains in employment).
• Balance of trade and inflation impacts.
• Impacts on new sources (barriers to entry).
3NPV is the total stream of a project's (e.g., platform's or facility's) cash inflows minus cash
outflows (operating costs, taxes, and investments) over a period of years (the facility's or
platform's lifetime) discounted back to present value.
1-4
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• Impacts on small businesses (an analysis of whether impacts on small businesses
are significant—the Regulatory Flexibility Analysis).
Figure 1-1 shows the types of analyses and how results of one analysis are used as inputs
to other analyses.
EPA estimates annualized compliance costs by spreading capital costs over 10 years using
a discount rate of 7 percent (in a similar manner to a mortgage). These annualized capital costs
are then added to annual operating and maintenance (O&M) costs to compute a total annual
compliance cost. The breakdown of capital and O&M costs is presented in EPA's Development
Document for this rule.
Table 1-1 presents the annualized compliance costs associated with three produced
water/TWC options and two drilling waste options. EPA's selected BAT options are Option #2
for produced water/TWC wastes (zero discharge for all coastal operations, except in Cook Inlet
where discharge limitations apply), and Option #1 for drilling waste in Cook Inlet (which is
equivalent to current practice). The NSPS option selected for both wastes is identical to those
selected for BAT in each region. Costs for the selected BAT options are $15.6 million and for
NSPS, $0.6 million, for a total of $16.2 million annually.
TABLE 1-1
TOTAL ANNUAL COSTS FOR ALL SELECTED BAT AND NSPS REGULATORY OPTIONS
($ million 1995)
Type of Waste Stream
Produced water/TWC fluids
Drilling waste
NSPS, produced water/TWC fluids
Total
Selected
Option
Number
Option #2
Option #1
Option #1
Aggregate
Annual
Cost Range
(Pre-tax)
$15.6
$0
$0.6
$16.2
1-5
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Production Loss
Model
Baseline versus
Postcompliance
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Loss of Net Present
Value of Project
Production Volume Loss
Federal Tax Revenue Loss
Severance Tax Loss
Loss of Economic Life
First Year Shut-in
Baseline Shut-in
Output
Postcompliance
Firm Failures
Small Entity
Impacts
Employment
Losses
Figure 1-1. Overview of methodology for the economic impact analysis.
o:\s\g\econ\eia2.ppt
1-6
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1.5 PRODUCTION LOSS IMPACTS AND OTHER IMPACTS TO PLATFORMS AND
FACILITIES
To estimate impacts on discharging Cook Inlet platforms and Major Pass facilities, EPA
uses a financial model that simulates the performance and measures the profitability of a
petroleum production project. EPA uses data on oil and gas production, expected decline rates,
costs of production, royalty rates, severance tax rates, etc., and creates a cash flow statement for
the facility or platform for each year of operation. The model makes the facility shut in in the
first year that operating costs exceed operating revenues. The model then reports total lifetime
production, NPV of project, total royalties, severance tax, and federal tax. EPA then inputs
(adds) the capital and operating costs estimated for compliance and reruns the model. The
differences between baseline values and post-compliance values are summarized and reported as
the impacts of the Coastal Guidelines (see the list in Section 1.4 for a more detailed description
of some of the outputs of this model).
Table 1-2 presents the impacts of the selected BAT options on Major Pass facilities and
Cook Inlet platforms. Under the selected options, no facilities or platforms would shut in. EPA
estimates total maximum impacts as follows: production losses of 5.8 million total BOE, or
0.5 percent of all production in Cook Inlet and the Major Passes or 0.2 percent of all production
from coastal oil and gas operations outside of California and North Slope, Alaska; total present
value losses of $98.5 million (1.9 percent of the total NPV, taxes, and royalties in Cook Inlet and
the Major Passes, or 0.7 percent of the total NPV, taxes, and royalties associated with total
coastal production outside of California and North Slope). The latter figure represents losses of
$63.7 million in project NPV, $6.1 million in present value severance and state income taxes,
$20.3 million in present value federal taxes, and $8.4 million in present value royalties. Disposal
of TWC wastes involves negligible additional impacts.
1.6 FIRM-LEVEL ECONOMIC IMPACTS ON THE COASTAL OIL AND GAS INDUSTRY
The firm-level analysis evaluates the effects of regulatory compliance on firms owning one
or more affected coastal oil and gas operations. The firm-level analysis identifies impacts not
1-7
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captured in the production loss analysis. For example, some companies might be too indebted to
undertake the investment in the required effluent control, even though the investment might
seem financially feasible at the facility or platform level.
EPA's firm-level analysis consists of three steps: a baseline analysis, a screening analysis
(which looks at whether annual compliance costs exceed 5 percent of equity and working capital),
and a detailed cash flow analysis. In the baseline, EPA considers all firms to be financially
healthy. In the screening analysis, annual pollution control costs for one or more firms exceed
the 5 percent benchmark for equity and working capital (independents only; majors are
unaffected). However, no firms fail a more detailed cash flow analysis. All firms show only
small declines in first-year and 10-year present value after-tax cash flow. Furthermore, after
more in-depth analysis of credit line availability and capital investment plans, EPA estimates that
all firms will be able to raise the necessary capital to meet zero discharge requirements. Thus
EPA expects no firm failures as a result of the Coastal Guidelines.
1.7 REGIONAL AND NATIONAL EMPLOYMENT IMPACTS AND TOTAL OUTPUT
LOSSES
The employment analysis includes both national- and regional-level analyses. The
national-level analysis addresses the Coastal Guidelines' effects on employment and economic
output throughout the United States. The regional-level analysis addresses the effects of
employment dislocations (layoffs) in the regions where the coastal industry is located, with
consideration of those regions where unemployment levels are high and employment is relatively
dependent on the coastal oil and gas industry. Employment losses and gains will occur in the
industry and throughout the economy in response to the reallocation of expenditures caused by
implementation of the Coastal Guidelines. Pollution control expenditures divert investment from
oil and gas production, which leads to direct employment losses and oil and gas production
losses. These losses are offset by gains in employment in the firms that produce, install, and
operate the pollution control equipment.
1-9
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Four types of changes may occur in employment and output (revenues) as a result of the
Coastal Guidelines. Where losses are not offset by gains elsewhere in the economy net or "dead
weight" losses occur. These four types of changes, discussed in detail in Chapter Seven, include:
Type 1 - Compliance Costs: Direct oil and gas employment losses due to
expenditures diverted to compliance.
Type 2 - Production Losses: Production losses at oil and gas operations that install
and operate pollution control equipment.
Type 3 - First-year Shut-ins: Employment and output losses at operations that shut
in in the first year and do not install pollution control equipment.
Type 4 - Delayed Investment: Employment and output losses resulting from
delayed investment, i.e., where the need for pollution control expenditures delays
investment in oil and gas exploration and development.
In general, Type 1 and Type 3 losses are not dead weight losses, but represent transfers
or gains to other segments of the economy. However, Type 3 losses may have significant impacts
at the regional level. EPA evaluates both direct and indirect employment and output effects at
both the national and regional levels, using multiplier analyses appropriate to each of those levels
(see Chapter Seven for a detailed description). Nationally, under the selected options, output
losses total $20.7 million per year based on direct industry revenue losses of $10.7 million per
year. EPA estimates the total annual job loss at 127 jobs per year. Regionally, EPA estimates
that employment losses will total 64 jobs annually (included in the national loss estimate) as a
result of the selected options. These losses will not have a significant community-level impact.
In Cook Inlet under Option #3 for produced water (zero discharge rejected by EPA), however,
employment losses would total 108 jobs annually, which would increase the unemployment rate
by 0.5 percent. EPA concludes that the impact to Kenai Peninsula Borough is significant under
this option because of the borough's higher unemployment (about 13 percent) and dependence
on the local oil and gas industry for jobs. The employment impacts contribute to EPA's finding
of economic unachievability of zero discharge in Cook Inlet.
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1.8 IMPACTS ON THE BALANCE OF TRADE, INFLATION, AND CONSUMERS
The coastal rule may cause a production loss of 5.8 million BOE (see Table 1-2) or 0.4
million BOE per year, which is 0.02 percent of U.S. domestic crude oil production. EPA
therefore finds that the change in the balance of trade attributable to the Coastal Guidelines is
not significant. Furthermore, since any change in U.S. coastal oil and gas production cannot
realistically influence the world price of oil or gas, companies affected by the Coastal Guidelines
will be unable to raise prices. Therefore, consumers will not face higher prices as a result of this
rulemaking.
1.9 IMPACTS ON NEW SOURCES
EPA has set the selected NSPS and pretreatment standards for new source (PSNS)
regulations equal to the selected BAT options for all waste streams with new source
requirements. Because new sources will face the same requirements as existing sources, most of
which are achieving zero discharge, new operations should face no significant barriers to entry.
Furthermore, since EPA has found the BAT requirements are economically achievable, NSPS
requirements should be economically achievable as well. EPA conducted a more detailed
analysis to determine if NSPS requirements could be a barrier to entry in Cook Inlet, and
determined they would not, as they represent at most 2.3 percent of platform construction costs
for an industry segment with a 20 to 25 percent targeted rate of return (see Chapter Nine).
1.10 ALTERNATIVE BASELINE SCENARIO
In response to concerns raised in comments on the proposal, this section considers two
additional groups of current dischargers and assesses the separate and combined impacts on
these groups together with Major Pass and Cook Inlet dischargers, using an alternative regulatory
baseline. The two groups, referred to here as the Louisiana Open Bay dischargers and Texas
Individual Permit applicants, will be subject to the requirements of the regional permits for
produced water. However, to analyze impacts under the alternative baseline, EPA assumes that
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in the absence of the Coastal Guidelines, the dischargers in these groups will apply for and
receive individual permits that allow them to continue to discharge produced water despite the
Louisiana state law prohibiting coastal produced water discharge beyond January 1997, and
despite the Region 6 General Permits currently applicable to these facilities. EPA believes this
alternative scenario to be unlikely.
The Louisiana Open Bay dischargers operate 82 outfalls under 37 permits and represent
22 firms, which have a lifetime production of 103 million total BOB and discharge 120.4 to 180.6
million bbls of produced water annually over the next 10 years. The Texas Individual Permit
applicant dischargers (40 firms) have 82 outfalls and have applied for 74 permits serving an
estimated 603 wells. Their oil and gas production is estimated at 79 million BOB, and their
produced water discharge is estimated at 24.9 to 37.4 million bbls of water annually over the next
10 years. On average, the Louisiana Open Bay dischargers' and Texas Individual Permit
applicants' financial indicators are in the acceptable range for financial health and are near the
median for comparable measures for the industry as a whole.
Under the assumptions of the alternative baseline, EPA estimates that the annual costs of
meeting zero discharge requirements will total $28.1 million for the Louisiana Open Bay
dischargers, and $6.1 million for the Texas Individual Permit Applicants. Total BAT costs under
the alternative baseline assumptions are $50.3 million BOB.4 These compliance costs are pretax
costs and include costs to install and operate pollution control equipment for baseline and first-
year shut-ins, costs which will not be incurred in reality. These costs therefore are an
overestimate of impacts on the Louisiana Open Bay dischargers and the Texas Individual Permit
applicants.
Under the alternative baseline assumptions, the Coastal rule causes 94 wells, including 47
wells each in the Louisiana Open Bay and Texas Individual Permit categories (see Table 1-3) to
shut in in the first year post-compliance. Production losses total 12.8 million BOB, or 7.0
percent of baseline production for the Louisiana Open Bay dischargers and Texas Individual
*The alternative baseline analysis results include impacts resulting from the increased costs to
Major Pass dischargers of zero discharge of produced water from coastal wells.
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TABLE 1-3
IMPACTS OF PRODUCED WATER OPTIONS (1995 $)
(LOUISIANA OPEN BAY DISCHARGERS AND TEXAS INDIVIDUAL PERMIT APPLICANTS COMBINED)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Total Louisiana and Texas
Baseline
Current Practice
127,857,719
Options #1, #2, & #3
Zero Discharge
120,316,566
7,541,153
5.9%
\- •" v % * .* ^ ' *"•
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOE)
Percentage change in total baseline production
181,614,357
168,845,817
12,768.541
7.0%
*
Present value of project net worth (NPV) ($000)
Change in NPV (SOOO)
Percentage change in NPV
$861,599
$734,921
$126,678
14.7%
- * , -
Productive wells in analysis
Baseline closures
Postcompliance closures
1,206
404
__
1,206
94
*\
Total production lifetime (years)
Change in total production lifetime
Percentage change
11,657
7,045
4,612
39.6%
-. •,, •>
Average lifetime (years, among wells not shutting-in in 1st year)
Change in average lifetime (among wells not shutting-in in 1st year)
Percentage change
15
10
5
31.5%
» ..
Present value of severance and state income taxes collected (SOOO)
Change in present value of severance and state income taxes ($000)
Percentage change in severance and state income taxes
$211,954
$192,178
$19,776
9.3%
''' , " '? , '
Present value of federal income taxes collected (SOOO)
Change in present value of federal income taxes (SOOO)
Percentage change in federal income taxes
S3 18,887
$282,139
$36,747
11.5%
' ~ -' "' , =- ''-^ _J',L ' , ', " :
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$293,744
$268,599
$25,145
8.6%
Note: Results are weighted using well survey weights and adjustment factors noted in the text
Source: Louisiana Open Bay Dischargers and Texas Individual Permit Applicants Production Loss Model Runs
(CBI data; in rulemaking record).
1-13
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Permit applicants. Present value losses in project net worth total $126.7 million (14.7 percent of
baseline). These losses include the producers' post-tax share of compliance costs. Other losses
include: lost federal income taxes of $36.7 million (11.5 percent), lost state and severance taxes
of $19.8 million (9.3 percent), and lost royalties of $25.1 million (8.6 percent). The total present
value impacts of the selected options on Louisiana Open Bay dischargers and Texas Individual
Permit Applicants under the alternative baseline are estimated to be $208.3 million.
Table 1-4 combines the results of Table 1-3 (Louisiana Open Bays and Texas Individual
Permit Applicants) with the impacts on Major Pass and Cook Inlet dischargers, the selected
options are associated with 94 wells, but no platforms, shutting in relative to the alternative
baseline. Losses under the alternative baseline represent a very small portion of production,
revenues, taxes, and royalties for all coastal oil and gas operations in the Gulf of Mexico and
Cook Inlet (excluding California and North Slope, Alaska). Under the selected options, lifetime
production losses for the alternative baseline groups amount to 0.6 percent of total coastal
production. NPV losses represent 4.4 percent of total coastal NPV outside of California and
North Slope, Alaska. Other losses, as percentages of all coastal oil and gas operations, are 1.1
percent of severance and state income taxes, 2.5 percent of federal income taxes, and 0.6 percent
of royalties.
EPA performed a sensitivity analysis of the results on the Louisiana Open Bay
dischargers and Texas Individual Permit applicants using the facility as the unit of analysis.5 In
this analysis, EPA assumed that operators maximize NPV at the facility level. Because many of
the marginal wells in EPA's analysis are served by facilities handling very large amounts of
production, EPA allocated production costs at marginal wells, and in some cases, compliance
costs, on the basis of their share of the facility's production rather than on the average cost per
well or proportional to their produced water volumes. This approach approximates the facility-
level analyses undertaken for Major Pass and Cook Inlet dischargers. As Table 1-5 shows (in
comparison to Table 1-3), losses increase in absolute value, but the percentages of losses
decrease, due to the greater amount of baseline production predicted using these alternative
5In this facility-level analysis, wells that are baseline shut ins in the well-level analysis stay
open, but shut in earlier than they would without the rule, causing a greater loss of production.
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TABLE 1-5
IMPACTS OF PRODUCED WATER OPTIONS, RESULTS OF SENSITIVITY ANALYSIS
USING ALTERNATIVE COST ALLOCATION ASSUMPTION (1995 $)
(LOUISIANA OPEN BAY DISCHARGERS AND TEXAS INDIVIDUAL PERMIT APPLICANTS COMBINED)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Total Louisiana and Texas
Baseline
Current Practice
157,886,618
Options #1, #2, & #3
Zero Discharge
149,988,589
7,898,030
5.0%
::rn?r::;;:^;;::||:::E:;::::^ ^^ , t^ ^ ^ ? < \«,\ r ^ * * ? ,
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOE)
Percentage change in total baseline production
224.114,100
210,315,549
13,798.551
6.2%
:::».:n:!i:;::iin:!;i:;i::i:::::::n:!?:;S::> A^j " * " x i i- , 1 > , ( : > ' ,
Present value of project net worth (NPV) ($000)
Change in NPV(SOOO)
Percentage change in NPV
$1,042,509
$897,965
$144,544
13.9%
j;:!.;»!!;r;j!h!!£J!8!H!KHii!!HJ^^
Productive wells in analysis
Baseline closures
Postcompliance closures
1,206
8
_
1,206
*«.
16
i:.,;u,'s.:;n:f;rsrc:;;tt::;1;:jtiK:Hs ' r.^ lf f
Total production lifetime (years)
Change in total production lifetime
Percentage change
16,017
10,474
5,542
34.6%
i f , ! ' !>
' * > > f/
Average lifetime (years, among wells not shutting-in in 1st year)
Change in average lifetime (among wells not shutting-in in 1st year)
Percentage change
13
9
5
33.8%
i> j- > v j s ~~ ^
Present value of severance and state income taxes collected ($000)
Change in present value of severance and state income taxes ($000)
Percentage change in severance and state income taxes
$236,911
S216.922
$19,989
8.4%
. - >< >\ •- ' ' - 7
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes ($000)
Percentage change in federal income taxes
$387,548
$346,017
$41,531
10.7%
iifSitin^flHiiiJlps1 !*; \>*<\; '<
Present value of royalties collected ($000)
Change in present value of royalties ($000)
'ercentaee change in royalties
$358,230
$332,472
$25,758
7.2%
Note: Results are weighted using well survey weights and adjustment factors noted in the text
Source: Sensitivity Analysis of Alternative Cost Allocation Assumption for Louisiana Open Bay Dischargers and Texas In
and Texas Individual Permit Applicants.
1-16
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assumptions. EPA continues to use the results of the more conservative well-level analysis,
however, to predict employment impacts.
The results of EPA's firm failure screening analysis (see Section 1.6) shows that 9 firms
might experience changes of more than 5 percent in both working capital and equity. Upon
further, more detailed, analysis, EPA identified two firms as possible firm failures (all others
were baseline failures, or were found not to sustain substantial impacts). The two failing firms
either have a very small stake in the wells they operate or have no stake and are operators only.
It is possible therefore that little, if any, of the increased costs for operating pollution control
equipment would be borne by these firms.
EPA concludes that, under zero discharge and the assumptions of the alternative
baseline, a range of 0 to 2 firms might experience firm failure, out of a total of 27 discharging
firms examined in this analysis. To account for the number of firms not captured in this analysis,
EPA estimates that these 2 firms represent 4 firms in the full universe, yielding a total of 0 to 4
potentially failing firms, which represent 0 to 6.6 percent of all Louisiana Open Bay and Texas
Individual Permit operators (61 firms, both large and small), but less than 1 percent of all
regulated firms in the Gulf coastal area (417 firms).
EPA estimates national output losses associated with Louisiana Open Bay dischargers
and Texas Individual Permit applicants to be $40.6 million. Adding these to Major Pass and
Cook Inlet impacts, EPA estimates that total output under the alternative regulatory baseline is
reduced by $61.4 million. In addition, EPA estimates that 377 jobs6 will be lost annually at the
national level, which include the regional job losses of 120-139 jobs associated with Louisiana
Open Bay dischargers and 54-57 jobs associated with Texas Individual Permit applicants (see
Table 1-6).
''Totalling regional job losses will not equal job losses at the national level. Some of the
national level losses occur outside the affected regions.
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TABLE 1-6
ALTERNATIVE BASELINE REGIONAL JOB LOSSES
Louisiana Open Bay Dischargers
Texas Individual Permit Applicants
Total Louisiana Open Bay and Texas
Individual Permit
Major Pass Dischargers
Total Gulf
Job Losses
120-139
54-57
174-196
53
227-249
Regionally, EPA estimates that 174 to 196 jobs are lost annually associated with
Louisiana Open Bay dischargers and Texas Individual Permit applicants. Combined with Major
Pass losses, up to 249 jobs will be lost per year in the Gulf coastal area. Community-level
impacts on the counties, parishes, and boroughs of concern are not significant as the
unemployment rates in these areas change by a minuscule percentage.
EPA estimates that the Coastal Guidelines will have no significant effect on trade or
inflation under the alternative baseline, for the same reasons that there were no impacts under
the current regulatory baseline. The impacts from NSPS requirements are the same as those
discussed in Section 1.9 for the current regulatory baseline. Section 1.11 presents the summary
of the regulatory flexibility analysis for both baselines.
1.11 REGULATORY FLEXIBILITY ANALYSIS
The RFA as amended by the Small Business Regulatory Enforcement Fairness Act
(SBREFA) of 1996, requires the federal government to consider the impacts of proposed
regulations on small entities during the rulemaking process. The Administrator has certified that
the rule does not have a significant economic impact on a substantial number of small entities.
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The Agency has nonetheless prepared a regulatory flexibility analysis equivalent to that required
under the Regulatory Flexibility Act.
EPA has determined that under the current regulatory baseline, three small firms will
incur compliance costs. None of these firms are likely to fail. Under the alternative baseline
assumptions, four small firms are estimated to fail, which is 1 percent of the total 371 regulated
small firms in the Gulf of Mexico (86 percent of the coastal industry). The Agency concludes
that the rule does not disproportionately affect small firms. EPA also determined that impacts
on small local counties and parishes (through losses in royalties), which ranged from $0.12 to
$1.3 per person or 0.002 to 0.012 percent, were insignificant.
The analyses contained within this EIA, particularly those discussed in the alternative
baseline analysis (Chapter Ten) address issues raised in public comments relating to regulatory
flexibility.
EPA determined that less restrictive alternatives to the rule in the Gulf of Mexico would
not be acceptable because alternatives allowing discharge would not provide a level playing field
among dischargers and nondischargers, nor would it meet the objectives of the Clean Water Act.
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CHAPTER TWO
DATA SOURCES
In 1995, EPA proposed Effluent Limitations Guidelines and Standards for the Coastal
Subcategory ("Coastal Guidelines") of the oil and gas industry that were projected to affect
several hundred operations in coastal Louisiana, Texas, and Alaska. Since that time, however,
EPA Region 6, which includes Louisiana and Texas, has issued a General Permit covering
produced water and produced sand and requiring zero discharge of these wastes. As a result, the
analytical baseline for regulatory analysis has changed substantially since 1995. The General
Permit (along with another General Permit for drilling wastes, also in effect) covers nearly all
wastestreams and nearly all operations in the Gulf coastal region that were considered affected in
the 1995 proposal. The Gulf of Mexico operations that remain unregulated by the General
Permit are now limited to a small group that discharge offshore produced water into the major
passes of the Mississippi and Atchafalaya Rivers in Louisiana (Major Pass dischargers). Cook
Inlet, Alaska, also remains a region where discharge of produced water and drilling wastes is still
occurring and thus where additional requirements could have an economic impact.
During proposal development, EPA relied on the Section 308 Survey of coastal
operations and firms, which was performed to gather information on the coastal oil and gas
industry in Texas, Louisiana, and Alaska. EPA is still relying on some of this survey information,
but survey results have been supplemented with more recent information from industry and other
sources. Specifics of the Section 308 Survey are discussed in detail in the proposal EIA
(PEIA).1 The PEIA also describes the mapping effort undertaken by EPA to identify the wells
and operators to be surveyed, the stratification method, numbers of wells in the Survey universe,
and how estimates were made for one group of wells that were not captured by the Survey (those
completed prior to 1980). Extrapolation to the "pre-1980" wells is discussed in more detail in
^.S. EPA. 1995. Economic Impact Analysis for Proposed Effluent Limitations Guidelines
and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category.
EPA/821/R-95/012. Washington, D.C. February.
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Chapter Ten of the current (final) EIA (FEIA), as well. EPA has written this chapter in
response to comments on the PEIA from the U.S. Department of Energy (DOE) and the Texas
Railroad Commission (RRC).2 Additional information on statistical extrapolations from the
Section 308 Survey can be found in two SAIC reports.3-4
In addition to the Section 308 Survey, EPA relies on a number of other information
sources, both primary and secondary. Secondary sources include U.S. Department of Energy
(DOE) data on 1995 U.S. production, Bureau of Census data on regional employment, Bureau
of Economic Analysis (BEA) data on regional input-output multipliers (which show how money
flows through the economy), and Oil and Gas Journal (OGJ) compilations of the OGJ 200
(which provides financial data on the largest 200 publicly held oil and gas firms in the United
States and associated statistics on financial indicators that can be used to judge the financial
health of individual firms). Primary sources of information, other than the Survey, include the
potentially affected firms and operations in the Gulf and Cook Inlet that provided EPA with
industry and firm-level data.
When EPA determined that a subset of oil and gas operators in the Gulf of Mexico
might not be covered under the Region 6 General Permit, the Agency undertook an effort to
identify potential operators who are:
• Currently discharging.
• Not under a Louisiana Department of Environmental Quality compliance
schedule.
• Not subject to Region 6 General Permit requirements because they discharge
offshore produced water.
2Chapter Ten presents the results of analyses of an alternative regulatory baseline. The
operations analyzed in this alternative baseline analysis are a large portion of those covered in
the Section 308 Survey.
3SAIC. 1994. Draft Report: Estimation Procedures for the Coastal Oil and Gas
Questionnaire. April 12.
4SAIC. 1995. Final Report: Statistical Analysis of the Coastal Oil and Gas Questionnaire.
January 31.
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• Not otherwise planning to cease discharging.
The Agency identified six firms that met these qualifications. These firms voluntarily
submitted substantial amounts of data, both as part of comments on the proposal and in
response to EPA's further solicitation.5 This information (including production volumes, costs of
production, drilling plans, price of product, royalty rates, severance rates, decline rate, and
discount rate) was key to accurately estimating the costs and economic impacts of the Coastal
Guidelines on these operations and serves as the basis for many of the cost and impact estimates
discussed in subsequent sections of this FEIA.
5Major Pass Discharges Data Submittals (CBI data; in rulemakmg record).
2-3
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CHAPTER THREE
INDUSTRY PROFILE
3.1 INTRODUCTION
The Coastal Guidelines establish effluent limitations and standards for produced water;
drilling fluids and drill cuttings (drilling wastes); treatment, workover, and completion (TWC)
wastes; produced sand; sanitary and domestic waste; and deck drainage. The Coastal Guidelines
may result in costs for three wastestreams (produced water, drilling wastes, and TWC), but will
not result in costs for the remaining wastestreams. More significantly, the Coastal Guidelines
will affect only a small portion of the overall U.S. oil and gas industry.
The coastal oil and gas industry subcategory is unusual because the vast majority of
operations are already in compliance with Coastal Guidelines requirements (see discussion below
in Section 3.1.2). To reflect this fact, EPA has separated coastal operations into two distinct
groups:
• The regulated universe. This universe consists of all coastal operations, the vast
majority of which are already in compliance with Coastal Guidelines requirements.
• The affected universe. This universe includes only those operations that are not
or will not be in compliance with the Coastal Guidelines by the time they are
promulgated.
Section 3.1.1 briefly discusses the regulated universe. This group is described in greater
detail in the PEIA. Section 3.1.2 then provides an in-depth discussion of EPA's identification of
the affected universe.
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3.1.1 The Regulated Universe
The coastal subcategoiy of the oil and gas industry is defined in 40 CFR Part 405, which
states that "coastal" is any facility over "(1) any body of water landward of the territorial seas as
defined in 40 CFR Part 125.1(gg) [subsequently revised], or (2) any wetlands adjacent to such
waters." According to this definition, any well located in or on a water of the United States
landward of the inner boundary of the territorial seas is a coastal subcategory well. In addition,
any location in Texas or Louisiana between the Chapman Line (a series of longitudes and
latitudes in Southern Louisiana and East Texas) and the inner boundary of the territorial seas is
defined as "coastal."1 Figure 3-1 illustrates the areas in Texas and Louisiana between the inner
boundary of the territorial seas and the Chapman Line.
Most of the activity in the coastal subcategory is concentrated in and around the Gulf of
Mexico (i.e., the coasts of Alabama, Florida, Louisiana, and Texas); Long Beach, California; and
Cook Inlet and the North Slope of Alaska. EPA also investigated industry activity in Mississippi
and the Mid-Atlantic region (i.e., along the coasts of Maryland and Virginia). The vast majority
of operations in these areas will not be affected by the Coastal Guidelines because, while they
will be regulated by the Guidelines, they already meet zero discharge requirements. Therefore,
most of these operations will incur no costs for complying with the Guidelines. The operations
that will be affected are identified below.
3.1.2 The Affected Operations
EPA's initial investigations, conducted before the Coastal Guidelines were proposed in
1995, indicated that operations in areas beyond Gulf coastal Louisiana and Texas and Cook Inlet,
Alaska, would not be significantly affected by the guidelines because they currently meet the
Coastal Guidelines requirements. EPA's investigations at that time included assessments of
current industry activities and practices in all coastal regions, as well as a review of state
1The Chapman Line is defined by points of latitude and longitude within the states of Texas
and Louisiana that are explicitly enumerated in the rule.
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3-3
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regulations concerning the discharge of wastes from oil and gas operations. EPA concluded that
coastal subcategory operations in some regions would not be affected by the Guidelines, based
on the following findings:
• Coastal Alabama. As of 1993, about 15 wells were thought to be operating in this
area. As of May 25,1994, the discharge of drilling fluids and cuttings was
prohibited. Also, a state law requires that produced fluids be injected.2-3
• Coastal Florida. In 1994, about 41 producing wells in this area were considered
coastal operations and approximately two additional wells were being drilled each
year. Nonetheless, all operators inject their produced water; reuse their drilling
fluids, inject them annularly, or leave them in a dry wellbore; and either dispose
of cuttings in reserve pits or haul them off site to a landfill.4
• Coastal Mississippi. None of the wells operating in Mississippi meet the
definition of coastal operations, and all well operators are required by state law to
inject their produced water.3 No new wells are slated to be drilled in the coastal
region for the foreseeable future.6
• Long Beach, California. Oil and gas production in this area is restricted to four
manmade islands in San Pedro Bay.7 As of 1993, 586 wells were operated in this
area, and six to seven new wells were being drilled each year. All produced water
is injected, primarily for waterflooding (see Section 3.2), and no drilling fluids or
cuttings are being discharged.
2Murphy, Matt, ERG, Memorandum to Allison Wiedeman, U.S. EPA, dated June 1,1993,
entitled "Well Status Updates for Alabama, Florida, and Mississippi."
3Wiedeman, Allison, U.S. EPA, Memorandum to file, dated September 6,1994, entitled
"Coastal Oil and Gas Activity in California, Alabama, Mississippi, and Florida."
4Ibid.
sMurphy, Matt, ERG, Memorandum to Allison Wiedeman, U.S. EPA, dated June 1,1993,
entitled "Well Status Updates for Alabama, Florida, and Mississippi."
6Murphy, Matt, ERG, Memorandum to Allison Wiedeman, U.S. EPA, dated June 1,1993,
entitled "Well Status Updates for Alabama, Florida, and Mississippi."
7Ibid.
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North Slope, Alaska. About 2,085 producing wells are operating on Alaska's
North Slope, and about 106 additional wells are drilled annually. No drilling or
production waste is discharged in this area.8
The Mid-Atlantic. Currently this area is not the site of any oil and gas
production. Moreover, no such activity is likely to be initiated within the next 15
years. Should any activity commence, operators would be unlikely to be allowed
to discharge wastes, according to state officials.9
These areas are not discussed in detail in this FEIA. Furthermore, only a subset of the
coastal oil and gas operations in Louisiana and Texas might be affected by the final Coastal
Guidelines.
For the proposal, EPA considered all coastal operations in the Louisiana/Texas portion of
the Gulf of Mexico that were then determined to be discharging produced water to be affected
by the Coastal Guidelines (see the PEIA). In early 1995, however, EPA Region 6 promulgated a
General Permit for produced water,10 which joined the General Permit for drilling waste
disposal" from coastal operations already in effect. These two General Permits cover nearly all
coastal operations and nearly all wastes in the Gulf coastal region, except for TWC wastes.
Thus, most of the Gulf operations considered affected for the proposal have become subject to
zero discharge. At the same time, EPA Region 6 issued Administrative Orders allowing until
January 1997 to continue zero discharge of produced water. Thus, for purposes of assessing the
economic impacts of this rule, under the current regulatory baseline, these facilities are
considered to be meeting zero discharge.
8U.S. EPA. 1994. 'Trip Report to Cook Inlet, Alaska, and North Slope Oil and Gas
Facilities, August 25-29,1993." August 31.
'Murphy, Matt, ERG, Memorandum to Allison Wiedeman, U.S. EPA, dated July 1,1994,
entitled "Coastal Oil and Gas Activity in the Atlantic Region."
1060 Federal Register 2387 (January 9, 1995). Final NPDES General Permits for Produced
Water and Produced Sand Discharges From the Oil and Gas Extraction Point Source Category
to Coastal Waters in Louisiana (LAG290000) and Texas (TXG290000).
"58 Federal Register 49126 (September 21,1993). Final NPDES General Permits for the
Coastal Waters of Louisiana (LAG330000) and Texas (TXG330000).
3-5
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This profile and Chapters Four through Nine therefore discuss only one group of
operations in the Gulf of Mexico region, i.e., operations discharging offshore water to the major
deltaic passes of the Mississippi River and Atchafalaya River (Major Pass dischargers12). Only
Coastal Guidelines requirements for TWC wastes will potentially affect some operations in the
broader Gulf coastal group.13 For a profile of this broader group of coastal operations, see the
PEIA.
The Major Pass dischargers are only partially represented in the Section 308 Survey.
Moreover, although a small fraction of the oil and gas production and therefore produced water
in this group is from coastal wells, most is from offshore operations. The group is thus
distinguished from all other coastal operations in that its produced water discharges are primarily
from offshore operations. These operations discharge offshore produced water (commingled in
some cases with coastal produced water) to the coastal region and are not covered by the
General Permit for produced water nor by any other NPDES permit. The Section 308 Survey
did not account for the offshore production and surveyed very few of the Major Pass dischargers.
Therefore, as noted in Chapter Two, EPA has relied primarily on voluntary data submissions
from these operators to define and profile the Major Pass discharging operations.
In addition to the Major Pass dischargers, this profile also discusses the group of
dischargers located in Cook Inlet, near Anchorage, Alaska, and the Kenai peninsula. EPA
Region 10 has issued a notice of a draft General Permit for drilling and production wastes in this
UEPA found no operations discharging offshore water to the Atchafalaya River (see EPA's
Development Document for this Rulemaking: U.S. EPA. Development Document for Final
Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category. September 1996).
"Chapter Ten of this FEIA presents an additional profile and economic impact analysis of a
subset of the Louisiana and Texas coastal operations. EPA includes this chapter to address
comments from the Texas Railroad Commission and DOE. To respond to these comments,
EPA has performed an impact analysis using an alternative regulatory baseline in which certain
operations in Texas and Louisiana, principally those in open bays, are assumed to be eligible for
individual permits, which would allow them to continue to discharge in the absence of the
Coastal Guidelines. Although EPA considers it likely that many of these operations would
achieve zero discharge even without the Coastal Guidelines in place, it has undertaken a
conservative impact analysis of this alternative baseline.
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region,14 but, since no final permit has been promulgated, these operations also are considered
potentially affected by the Coastal Guidelines.
The following sections profile each of the groups of regulatory concern. The profile
covers wells, treatment facilities, and firms operating in the Gulf and Cook Inlet, broken down by
group of concern: Major Pass dischargers and Cook Inlet operations. Section 3.2 presents a
brief description of the process of oil and gas extraction, including how wells are drilled, how oil
and gas is produced, and what wastes are generated during these processes. Section 3.3 presents
a general overview of the industry in the two key regions, discussing the characteristics of the
wells, facilities, and/or platforms among Major Pass and Cook Inlet discharging operations and
describing the types and nature of the firms owning and operating coastal oil and gas production
wells and facilities in the key coastal regions.
3.2 THE PROCESS OF OIL AND GAS EXTRACTION AND THE WASTES GENERATED
Two activities in the oil and gas extraction process generate the major portion of wastes
in this industry: drilling activities and production activities. This section presents a summary of
these activities and related wastes, including miscellaneous wastes, which are small volume wastes
associated indirectly with drilling or production operations. The major source for the
information in this discussion is EPA's Development Document15 for this rulemaking.
3.2.1 Drilling Operations
The drilling operations of particular concern in this analysis are those performed in Cook
Inlet, Alaska. Currently all other drilling activities in the coastal subcategory do not discharge
1460 Federal Register 48796 (September 20,1995). Alaskan Outer Continental Shelf; Draft
National Pollutant Discharge Elimination System General Permit.
15U.S. EPA. 1996. Development Document for Final Effluent Limitations Guidelines and
Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category.
Washington, D.C. September.
3-7
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drilling fluids and cuttings, because of either state or federal requirements or operator
preference.
The two types of drilling operations conducted as part of the oil and gas extraction
process are exploratory and developmental. Exploratory operations involve drilling wells to
determine potential hydrocarbon (oil and gas) reserves. Once a hydrocarbon reserve has been
discovered and delineated, development wells are drilled for production. Although the rigs used
for each type of drilling can differ, the drilling process is generally the same.
In the initial phases of exploration, shallow wells usually are drilled to discover the
presence of oil and gas reservoirs. Subsequently, deeper wells are drilled to establish the extent
of a reservoir. Exploration activities are usually of short duration, involve a small number of
wells, and are conducted from mobile drilling rigs.
In Cook Inlet, exploratory drilling is typically conducted from jackup rigs, which are
barge-mounted rigs with extendable legs that are retracted during transport. At the drill site, the
legs are extended to the floor of the waterbody, gradually lifting the barge hull above the water.
Some exploratory drilling has been performed in recent years in Cook Inlet as part of ARCO's
Sunfish Field exploration.16
Development drilling is conducted to begin extraction of recently discovered reserves of
hydrocarbons; it is also conducted to increase production or to replace nonproducing wells on
existing production sites. Since development wells tend to be smaller in diameter than
exploratory wells, less waste is generated.
Two commonly used types of drilling rigs for development drilling are the platform rig
and the mobile drilling unit. In Cook Inlet, once exploratory drilling has confirmed that an
extractable quantity of hydrocarbons exists, the producer constructs a platform at that site for
drilling and production operations. Development wells are often drilled from these platforms.
""Cook Inlet Maintaining Oil Flow in Spite of Budget Restrictions," Oil and Gas Journal
(OGJ), June 20,1994, pp. 21-23.
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Also, the producer frequently conducts directional drilling from a fixed location such as a
platform to access different parts of a geological formation. This type of drilling involves drilling
the top part of the well straight down and then directing the wellbore to the desired location.
The last platform constructed in Cook Inlet was built in the mid-1980s,17 and even with the
exploratory drilling that took place in the Sunfish Field a few years ago, EPA anticipates no
additional platform construction.18
The type of drilling used in Cook Inlet is rotary drilling. This method uses a rotating
drill bit attached to the end of a drill pipe, referred to as the "drill string." With this method,
the walls of the hole tend to cave in as the wellbore deepens; thus, periodically the drill string
must be lifted out so that a casing, which is a tube-shaped liner, can be placed in the hole.
Cement then is pumped into the space between the casing and the hole wall to secure the casing.
Each new portion of casing must be smaller in diameter than the previous portion to allow for
installation. The process of drilling and adding sections of casing continues until final well depth
is reached.
Rotary drilling relies on circulating drilling fluid to move drill cuttings (bits of rock) away
from the bit and out of the borehole. The drilling fluid, or mud, is a mixture of water, special
clays, and certain minerals and chemicals that is pumped "downhole" through the drill string and
ejected through the nozzles in the drill bit at high speeds and pressure. The jets of drilling fluid
lift the cuttings from the bottom of the hole and away from the bit so that the cuttings do not
interfere with the effectiveness of the drill bit. The drilling fluid circulates and rises to the
surface through the space between the drill string and the casing, called the annulus. At the
surface, the cuttings, along with silt, sand, and any gases, are removed from the drilling fluid
before the drilling fluid is returned downhole to the bit. The cuttings, silt, and sand are
separated from the drilling fluid by a solids separation process typically involving shale shakers,
desilters, desanders, and centrifuges (each removing sequentially smaller waste particles from the
"Marathon/Unocal. 1994. "Zero Discharge Analysis: Cook Inlet, Alaska." Marathon Oil
Company and Unocal Corporation. March.
18Wiedeman, Allison, U.S. EPA, Personal communication with Jim Short, ARCO, dated
May 9,1994, regarding ARCO's future drilling activity in Cook Inlet—status of ARCO's Sunfish
operations in Cook Inlet, Alaska.
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drilling fluid). Some of the drilling fluid remains with the cuttings after solids separation. w>2°
In Cook Inlet, if the cuttings, silt, sand, and residual drilling fluid do not contain free oil or other
regulated contaminants, they are discharged into the inlet.
Drilling fluid can become contaminated, and thus constitute a waste, during several
different stages of the drilling process. Drilling fluid also can become waste if it cannot be
adjusted to provide the appropriate lubrication (lubricity) for drilling at different formation
pressures (which vary at different depths). When a drilling fluid no longer meets the
requirements for lubricity, density, viscosity, or gel strength, for example, a "mud changeover"
must be performed. The drilling fluid system replaced can become a waste at this stage if it is
not recycled or reused later in the drilling process.
Similarly, if drilling fluid solids cannot be controlled efficiently, dilution with fresh drilling
fluids might be necessary to reduce the solids content of the circulating drilling fluid system, in
which case the displaced drilling fluid can become a waste. The more recently developed solids
control systems are much more efficient than those used in the past; thus, this type of waste
drilling fluid is now less of a problem.
Most drilling fluid systems are water based. Although oil-based systems are less common
than they once were, some use of oil (or synthetic) additives is still necessary under special
circumstances, such as when performing directional drilling or when freeing a stuck pipe. Thus,
some portion of the drilling fluids used in Cook Inlet might not meet a more stringent toxicity
limit due to the occasional use of specialized fluids.
19Ray, J.P. 1979. "Offshore Discharges of Drill Cuttings." Outer Continental Shelf Frontier
Technology. Proceedings of a Symposium. National Academy of Sciences. December 6.
(Offshore Rulemaking Record, Vol. 18.)
20Meek, R.P., and J.P. Ray. 1980. "Induced Sedimentation, Accumulation, and Transport
Resulting from Exploratory Drilling Discharges of Drilling Fluids and Cuttings on the Southern
California Outer Continental Shelf." Symposium—Research on Environmental Fate and Effects
of Drilling Fluids and Cuttings. Sponsored by API, Lake Buena Vista, Florida. January.
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The most significant waste streams in Cook Inlet, in terms of volume and particular
constituents associated with drilling activities, are drilling fluids and drill cuttings. Drill cuttings
are generated throughout the drilling project, although higher quantities of cuttings are
generated when drilling the first few thousand feet of the well because the borehole is the widest
during this stage. In contrast, the largest quantities of excess drilling fluids are generated as the
project approaches final well depth. Most waste fluid is generated at completion of well drilling
because the entire drilling fluid system must be removed from the hole and the tanks used to
hold the drilling fluid must be emptied. Some constituents of the drilling fluid can be recovered
after completion of the drilling, either at the rig or by the supplier of the drilling fluid. When
drilling is continuous, which can be the case on the multi-well Cook Inlet platforms, drilling fluid
can be reused to drill the next well in a series.
A much smaller waste stream associated with the drilling process is drainage from deck
platforms during drilling, which can occur during rainstorms. In Cook Inlet, deck drainage is
combined with produced water.21
3.2.2 Production Activities
When the drilling process is completed (in either the Gulf or Cook Inlet), successful wells
begin to produce reservoir fluids, which consist of oil, natural gas liquids or condensate, and salt
water (sometimes dry gas also is produced). The salt water contains dissolved and suspended
solids, hydrocarbons, and metals and might contain small amounts of radionuclides. Portions of
the salt water also can include enhanced oil recovery (EOR) fluids, which are gases or liquids
injected downhole to produce additional reservoir pressure. As hydrocarbons are produced, the
natural pressure in the reservoir decreases and additional pressure must be added to the
reservoir to continue production of the fluids. When a liquid is used, the process is called
waterflooding.
21SAIC. 1994. Oil and Gas Exploration and Production Handling Methods in Coastal
Alaska.
3-11
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EOR processes are divided into three general classes: thermal, chemical, and miscible
displacement. In the thermal process, steam generally is used to aid in removing hydrocarbons
from the geological formation. Chemical EOR processes use surfactants, polymers, and/or
caustics for washing oil from the formation and driving or displacing oil into the wellbore. In
miscible displacement, kerosene or gas, and then water, are used first to dissolve and then to
drive oil from the formation. Typically EOR fluids are a part of the produced water stream.
As they surface, the gas and oil (including EOR fluids) are separated for further
processing and sale. Typically, a series of vessels is used for the separation process. The major
waste streams associated with this process are produced water and, to a much lesser extent,
produced sand, which is, in part, made up of fine particles that are entrained with the oil and
produced water. Section 3.3.1 presents more details on the equipment and processes used to
separate and treat produced water in both the Gulf and Cook Inlet.
3.2.3 Miscellaneous Wastes
Other wastes besides the drilling and produced water wastes discussed above also can be
generated during the productive life of a well. Produced sand and deck drainage associated with
drilling are discussed above. Small volumes of production deck drainage and domestic and
sanitary wastes might also be generated, although deck drainage is generated only if a platform is
present, and sanitary and domestic wastes are generated only if toilet or washup facilities are on
site. The most common miscellaneous wastes are known as treatment, workover, and completion
(TWC) wastes. This section focuses on the processes that generate these wastes.
Treatment. Well treatment is the process of stimulating a producing well to improve oil
or gas productivity. Two basic methods of well treatment include hydraulic fracturing and acid
treatment. Hydraulic fracturing is typically used on sandstone, and acid treatment is generally
performed on formations of limestone or dolomite.22 Hydraulic fracturing, in which a fluid is
^Walk, Haydel and Associates. Undated. Industrial Process Profiles to Support PMN
Review: Oil Field Chemicals. Prepared for U.S. EPA. Received by EPA June 24,1983.
(Offshore Rulemaking Record, Vol. 26.)
3-12
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pumped into the formation under high pressure, relies on inert materials known as proppants
(e.g., sand, walnut shells, aluminum spheres, glass beads) that remain in the formation to prop
the channels open after the fluid and pressure have been removed.23'24 This method of well
treatment is rarely used in the Gulf of Mexico.
Acid stimulation involves injecting acid solutions into the geological formation. The two
types of acid treatment used are acid fracturing and matrix acidizing. In acid fracturing, the acid
solution is injected under high pressure. The acid solution both dissolves the formation rock and
fractures it. Matrix acidizing uses low pressures to avoid fracturing. Other chemical treatments
sometimes used include treatment with organic solvents, such as xylene or toluene, to remove
paraffins or asphalts that block the wellbore.
Not all residuals from these well treatments become wastes. Many are recycled to be
used in other well treatment fluids. Nonetheless, some become part of the produced water
stream and are subsequently discharged (such as in Cook Inlet) or injected with produced water,
and some are disposed of separately from produced water.
Workover. Waste fluids can also be generated when a well undergoes a workover to
improve or restore productivity, repair or replace downhole equipment, evaluate the rock
formation, or abandon a well. Workovers are generally performed every 3 to 5 years.25'26
Responses to EPA's Section 308 Survey indicate, however, that workovers in the Gulf of Mexico
^Walk, Haydel and Associates. Undated. Industrial Process Profiles to Support PMN
Review: Oil Field Chemicals. Prepared for U.S. EPA. Received by EPA June 24, 1983.
(Offshore Rulemaking Record, Vol. 26.)
24U.S. EPA. 1987. Report to Congress: Management of Wastes from the Exploration,
Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy, Vol. 1.
EPA/530/SW-88/003. December. (Offshore Rulemaking Record, Vol. 119.)
"American Petroleum Institute (API). 1988. Exploration and Production Industry
Associated Wastes Report. Washington, D.C. May.
26American Petroleum Institute (API). 1991. Detailed Comments on EPA Supporting
Documents for Well Treatment and Workover/Completion Fluids. Attachment to API
comments on the March 13 proposal. May 13. (Offshore Rulemaking Record, Vol. 146.)
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occur once per year on average (Section 308 Survey). Workovers generate some of the same
wastes as those generated during well treatment and completion operations because some of the
operations are the same (e.g., stimulation, reperforation, casing repair, replacement of subsurface
equipment).27-28-29
Completion. Completion operations include the setting and cementing of the production
casing, packing the well, and installing the production tubing. All completion methods consist of
four steps: wellbore flush, production tubing installation, casing perforation, and wellhead
installation.
During the initial wellbore flush, a slug of fluids is injected into the casing. These
cleaning or preflush fluids can be circulated and filtered many times to remove solids from the
well and to minimize potential damage to the geological formation.30 Once the well has been
cleaned, a second completion fluid (i.e., a "weighting fluid") is injected. This fluid maintains
sufficient pressure to prevent the formation fluids from migrating into the hole before well
completion is finished.
Next, production tubing is installed inside the casing using a packer which is placed at or
near the end of the tubing. The packer consists of pipe, gripping elements, and sealing elements.
When the tubing is in place, the packer traps completion fluids between the casing and the
production tubing. These "packer fluids" provide long-term protection against corrosion.
"Walk, Haydel and Associates. Undated. Industrial Process Profiles to Support PMN
Review: Oil Field Chemicals. Prepared for U.S. EPA. Received by EPA June 24,1983.
(Offshore Rulemaking Record, Vol. 26.)
^Acosta, D. 1981. "Special Completion Fluids Outperform Drilling Muds." Oil and Gas
Journal. March 2. (Offshore Rulemaking Record, Vol. 25.)
"American Petroleum Institute (API). 1988. Exploration and Production Industry
Associated Wastes Report. Washington, D.C. May.
30Wiedeman, Allison, Project Officer, U.S. EPA, Memorandum to Marv Rubin, Branch
Chief, U.S. EPA, dated January 22,1992, entitled "Supplementary Information to the 1991
Rulemaking on Treatment/Workover/Completion Fluids."
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Typically packer fluids are mixtures of a polymer viscosifier, a corrosion inhibitor, and a high-
concentration salt solution,31 and can be removed during workover operations.32
Following installation, the production tubing is perforated to allow hydrocarbons to flow
from the reservoir into the wellbore. For this step, a special gun is used to fire bullets or charges
that penetrate the casing and cement. Alternatively, a small perforated pipe can be hung from
the bottom of the casing.33-34
The final step calls for installation of the "Christmas tree," a device that controls the flow
of hydrocarbons from the well. When the valves of the Christmas tree are initially opened, the
completion fluids remaining in the tubing are removed before fluid from the formation begins to
flow.
33 GENERAL OVERVIEW OF THE COASTAL SUBCATEGORY INDUSTRY
Wells, platforms, produced water treatment/separation facilities, and firms are used as
units of analysis in this FEIA. Unlike wells in the offshore subcategory or in Cook Inlet, few
Gulf of Mexico region wells are located on multi-well platforms. Furthermore, the multi-well
31Gray, G.R., H. Darley, and W. Rogers. 1980. Composition and Properties of Oil Well
Drilling Fluids. January.
32Arctic Laboratories Limited et al. 1983. Offshore Oil and Gas Production Waste
Characteristics, Treatment Methods, Biological Effects, and Their Applications to Canadian
Regions. Prepared for Environmental Protection Services. April. (Offshore Rulemaking
Record, Vol. 110.)
33Baker, R. 1985. A Primer of Offshore Operations. Second edition. Petroleum Extensive
Service, University of Texas at Austin.
MRadian Corporation. 1977. Industrial Process Profiles for Environmental Use. Chapter 2:
Oil and Gas Production Industry. EPA/600/2-77/023b. February. (Offshore Rulemaking
Record, Vol. 18.)
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platforms operating in the Gulf coastal area appear to have fewer than four wells on them.35
EPA selected wells in certain Gulf of Mexico operations as principal units of analysis for
determining production loss and economic life (see Chapter Ten). In some cases, however,
where large central treatment facilities or multi-well platforms are the rule, the platform or
treatment facility becomes the primary unit of analysis. EPA therefore uses well-based
parameters (and variables) to model the economic viability of Gulf oil and gas production
activities associated with the alternative analytical baseline (see Chapter Ten), but the platform is
the unit of analysis for Cook Inlet and the treatment/separation facility is the unit of analysis for
the Major Pass dischargers (see Chapter Five for key parameters and variables for Major Pass
discharging facilities and Cook Inlet platforms). The following section discusses wells, platforms,
and treatment/separation facilities; firms are discussed later in Section 3.3.2.
3.3.1 Wells, Platforms, Treatment Facilities, and Production in the Coastal Region
Major Pass Dischargers
Major Pass dischargers are characterized primarily by their treatment facilities (discussed
below). Although information obtained on numbers of wells per facility was not complete for all
operators, EPA estimates that, at a minimum, the Major Pass facilities service 350 wells (see
EPA's Development Document). The Agency further estimates that lifetime production
associated with these wells (using the production loss model described in Chapter Five) totals
435 million barrels of oil equivalent in present value terms (PVBOE), or 600 million total BOB
(undiscounted).3* Note that these baseline production figures include production expected from
planned drilling in this region of the Gulf over the next 5 years. Based on discussions with the
Major Pass discharging operators, EPA expects the Major Pass discharging operations to make
"Kaplan, Maureen, ERG, Memorandum to Neil Patel, U.S. EPA, dated February 11,1994,
entitled, "Stand-alone Projects: ERG Multi-Well Structures and Single-Well Structures in the
308 Survey Data."
MSee Chapter Five, Table 5-5. Source: Major Pass Dischargers Production Loss Model
Runs. (Confidential business information [CBI] contained in rulemaking record only.)
3-16
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substantial additions to production through drilling new wells over the next 5 years, in some cases
doubling total production each year.37
Unlike other industries, wastewater generation in the oil and gas production industry is
not proportionate to the quantity of materials processed. Produced water can constitute from 2
to 98 percent of the fluid production at a given facility (see EPA's Development Document;
information in this subsection is summarized from this document unless otherwise noted). In
general, the proportion of hydrocarbons to produced water tends to be high during the initial
production phase and to decrease as hydrocarbons are depleted. Thus, any regulation affecting
the cost of produced water disposal will tend to affect the older, more marginal fields more than
the newer developmental projects.
Currently, typical produced water treatment facilities in the Gulf of Mexico are designed
to meet best practicable technology (BPT) requirements, which restrict the oil and grease
concentrations of produced water to a maximum of 72 milligrams per liter (mg/L) for any one
day and to a 30-day average of 48 mg/L. Technologies and practices used to achieve this level of
control include:
• Equalization (surge tank, skimmer tank)
• Chemical addition (feed pumps)
• Oil and/or solids removal
• Gravity separators
• Flotation
• Filters
• Plate coalescers
• Filtration prior to injection
• Subsurface disposal (injection)
"Major Pass Dischargers Data Submittals (CBI data; in rulemaking record).
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The typical Gulf Coast discharging facility uses gravity separators, which are tanks large
enough to store oil and water mixtures for a sufficient length of time to allow the mixture to
separate. Chemicals might be added to hasten or augment the separation process. At separation
facilities where produced water is injected, the produced water is typically filtered prior to
injection. Although used in the Gulf, gas flotation is not used widely enough in coastal
operations to be considered a typical BPT process. Many coastal operations, however, use
subsurface injection, as the number of nondischarging facilities in the Gulf Coastal region reflects
(see PEIA).
The Major Pass discharging operations include eight facilities (identified as outfalls)
operating under six permits. One facility is shared by two firms that are owned by a third parent
company. One of these subsidiaries also operates another facility. One other firm operates
three facilities, and the rest operate one facility each. Current total annual produced water
discharge from these facilities is 69.8 million barrels (bbls), with future projections of 104.7
million bbls annually; average daily discharge ranges from 572 to 153,895 barrels per day (bpd).
The largest facility is currently using an improved gas flotation unit, which reduces the oil and
grease to a 42 mg/L daily maximum, and a 29 mg/L monthly average; the rest are using
technologies similar to those discussed above.
Cook Inkt Operations
Fifteen platforms are located in Cook Inlet, Alaska. However, two of these platforms are
currently shut in (Spark and Spur—both owned by Unocal). Thus, 13 Cook Inlet platforms are
operating with a total of 224 productive wells (see EPA's Development Document). Table 3-1
lists the platforms, the number of wells on each platform, and the owner/operator of each
platform. As shown, there are 197 oil wells and 27 gas wells in Cook Inlet. Based on the daily
production figures shown, estimated total annual production (1995) is 13.7 million bbls of oil and
140,525 million Mcf of marketable gas (see EPA's Development Document). EiPA estimates
total lifetime production (using the production loss model under baseline assumptions—see
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TABLE 3-1
PLATFORMS, OPERATORS, AND WELLS IN COOK INLET
Platform
King Salmon
Monopod
Grayling
Granite Point
Dillon
Bruce
Anna
Baker
Dolly Varden
Spark
Steelhead
Spurr*
SWEPI "A"
SWEPI "C"
Tyonek "A"
Operator
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Shell
Western
Shell
Western
Phillips
No. of
Active
oil
Wells
19
22
23
11
10
13
23
14
24
0*
4
0*
17
17
0
No. of
Active
Gas
Wells
1
0
1
0
0
0
0
2
1
0*
9
0*
0
0
13
Oil
Production
(bpd)
3,864
1,981
5,207
6,086
841
865
3,117
1,301
4,983
0
4,184
0
3,200
1,800
0
Gas
Production
(Mcf)
Plat, use
Plat, use
Plat, use
Plat, use
0
Plat, use
Plat, use
Plat, use
Plat, use
0
165,000
0
Plat, use
Plat, use
220,000
Discharge
Location
Trading Bay
Trading Bay
Trading Bay
Granite
Point
Platform
Platform
Platform
Platform
Trading Bay
Platform
Trading Bay
Granite
Point
E. Foreland
E. Foreland
Platform
*Spark and Spurr are considered completely nonactive in this EIA.
Source: U.S. EPA. 1996. Development Document for Final Effluent Limitations Guidelines and
Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category.
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Chapter Five) to be 311 million PVBOE, or 501.1 million BOB (undiscounted).38 Over a
period of 7 years, producers plan to drill 41 new wells and expect to perform 20 recompletions
(see Chapter Four for a detailed drilling schedule by platform).39
A potential area of development in Cook Inlet is the Sunfish Field, which is located in
North Upper Cook Inlet. At this time, the Sunfish Field has not been brought into production,
and as noted earlier, no new platforms are planned.40
Three land-based and five platform-based separation/treatment facilities operate in Cook
Inlet. The three land-based facilities (the largest of which is the Trading Bay facility) treat and
discharge about 98 percent of all produced water at a rate of about 130,000 bpd (see EPA's
Development Document). One platform and one land-based facility currently use gas flotation
(in addition to skim tanks, a type of gravity separator). Most other facilities use skim tanks only,
or a combination of skim tanks and corrugated separators (see EPA's Development Document).
3.3.2 OH and Gas Firms Operating in the Coastal Subcategory
The expenditures required to comply with the Coastal Guidelines for the coastal oil and
gas industry will be financed by coastal firms and their investors. Coastal oil and gas producers
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 coastal
producers consists of independents engaged primarily in exploration, development, and
MCook Inlet Production Loss Model Runs (CBI data in rulemaking record).
3!>Marathon/Unocal, 1994. "Zero Discharge Analysis: Cook Inlet, Alaska." Marathon Oil
Company and Unocal Corporation. March.
<°Wiedeman, Allison, U.S. EPA, Personal communication with Jim Short, ARCO, dated
May 9,1994, regarding ARCO's future drilling activity in Cook Inlet—status of ARCO's Sunfish
operations in Cook Inlet, Alaska.
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production of oil and gas and not typically involved in downstream activities. Some independents
are strictly producers of oil and gas, while others maintain some service operations, such as
contract drilling and well servicing. The major integrated oil companies are generally larger than
the independents. As a group, the majors typically produce more oil and gas, earn significantly
more revenue and income, and have considerably more assets and greater financial resources
than the 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 all are standard corporations (i.e., the corporation pays
income taxes).
Independents can vary greatly by size and corporate structure. Larger independents tend
to be standard corporations (i.e., they pay corporate taxes); smaller firms might also pay
corporate taxes, but they can also be organized as S corporations,41 limited partnerships, sole
proprietorships, etc., whose owners, not the firms, pay taxes.
The firms that EPA estimates will be affected by the Coastal Guidelines include three
majors in the Major Pass discharger group (reduced to two in a financial sense, since two of the
three are Chevron subsidiaries), three majors in the Cook Inlet group, and three independents
(one publicly held) in the Major Pass discharger group. All the Major Pass dischargers and
Cook Inlet firms that provided financial data are standard corporations.
The oil and gas industry as a whole has been through a number of changes in the 1990s.
Since the early 1990s, which were hard years in the U.S. oil and gas industry,42 the industry has
experienced a major upturn. By 1993, net income of the 300 largest firms rose 75.5 percent from
the previous year,43 although some of this apparent improvement can be attributed to
41S corporations are corporations that have elected to be taxed at the shareholder level rather
than the corporate level under Subchapter S of the Internal Revenue Code.
"""Financial Operating Results Sag for OGJ 300 Companies," Oil and Gas Journal (OGJ),
Vol. 90, No. 39, September 28,1992, p. 49.
43"Total Earnings Rose, Revenues Fell in 1993 for OGJ 300 companies," Oil and Gas Journal
(OGJ), September 5,1994, pp. 49-59.
3-21
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accounting changes. More recently, in 1995, conditions improved further, and OGJ indicated
that demand is expected to grow between 1997 and 1999.44 Additionally, prices have risen
substantially in 1996, bolstering an active and relatively healthy industry. OGJ paraphrases
Arthur Anderson: "The U.S. oil and gas industry is in its best shape in more than 15 years and is
poised for a period of sustained growth."45 The affected firms will very likely follow this
projected trend. Despite the recent improvements, mergers, acquisitions, consolidations, and
liquidations have been common; the Oil and Gas Journal OGJ 400 was cut to 300 firms in
1991,44 and further cut to 200 in 1996.47 These consolidations, however, have tended to
eliminate the weaker firms, leaving those surviving firms an increasingly healthy group.
The following sections profile Major Pass dischargers and Cook Inlet operators. Two
operations in the Major Pass discharger group are not profiled since they are not publicly owned
and in-depth profiles of these firms could create confidentiality problems.
EPA conducted several analyses to determine the financial status of the Major Pass and
Cook Inlet firms. The Agency investigated financial ratios using benchmarks from the OGJ
200,48'49 which provides 1995 financial data. A brief definition of the measures of financial
health used to characterize the firms are as follows:
Total Assets. The sum of all liquid (cash-type) and nonliquid (e.g., real estate)
assets of the company.
""Strong Demand Growth Seen for Oil and Gas in 1997-1999," Oil and Gas Journal (OGJ),
Vol. 94, No. 17, April 22,1996, p. 45-59.
^"Newsletter," Oil and Gas Journal (OGJ), Vol. 94, No. 36, September 2, 1996, p. 2.
""OGJ 300: Smaller List, Bigger Financial Totals," Oil and Gas Journal (OGJ), Vol. 89, No.
39, September 30,1991, pp. 49-56.
47The number of publicly held firms dropped to 281 in 1995. "Consolidation Shrinks List of
U.S. Companies," Oil and Gas Journal (OGJ), Vol. 94, No. 36, September 2,1996, pp. 45-54.
^"Consolidation Shrinks List of U.S. Companies," Oil and Gas Journal (OGJ), Vol. 94, No.
36, September 2,1996, pp. 45-54.
49"OJG 200," Oil and Gas Journal (OGJ), Vol. 94, No. 36, September 2, 1996, pp. 56-74.
3-22
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• Equity. Total assets minus total liabilities, or the firm's net worth.
• Profitability.
— Return on Assets (ROA): Net income over total assets. The median for
the OGJ 200 was 3.9 percent in 1995.
— Return on Equity (ROE): Net income over equity or net worth. The
median for the OGJ 200 was 10.7 percent in 1995.
— Profit Margin: Net income over sales (revenues). The median for the
OGJ 200 was 3.6 percent.
Benchmarks are useful in showing how healthy a firm or a subset of an industry is in
comparison to the industry as a whole. In general, if the firm or segment is at the median or
above, it can be considered relatively healthy. A firm somewhat below the median would be
considered weak but in potentially acceptable financial health, while a firm below the lowest
quartile (only a quarter of firms in the industry have a measure that low or lower) can be
considered in poor financial health. In the case of the OGJ 200, all lowest quartile profitability
measures are negative, so any positive returns are better than the lowest quartile among this
group. If, however, the financial health of the entire industry is poor relative to all industries,
even better-performing firms might be considered in poor financial health.
Table 3-2 presents summary financial data on all publicly held firms in the affected
coastal regions. As Table 3-2 shows, the majors tend to have the greatest assets and equity. The
only independent shown here, Flores & Rucks, shows as good or better returns (for example, a
50 percent return on equity) and profit margins despite being smaller than the majors. All the
firms shown in this table are considered to be operating profitably and to be in adequate to good
financial health. Most firms show returns at or above the median for the OGJ 200; none have
negative returns, which would tend to indicate poor financial health. Those below the median
are generally only slightly below. This table also presents the capital and exploration spending by
the firms in 1995. These figures provide some sense of the level of capital that might be
available annually to these firms. A portion of this capital could be diverted to capital
expenditures on pollution control equipment.
3-23
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Among the two nonpublic firms, one declined to provide EPA with financial information
but indicated that achieving zero discharge would not cause a significant problem for the firm.
EPA does not consider the remaining nonpublic firm to be in poor financial health. More detail
is not provided to protect confidentiality but is included in the CBI record for this rulemaking.50
50Major Pass Dischargers Data Submittals (CBI data; in the rulemaking record).
3-25
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CHAPTER FOUR
ECONOMIC IMPACT ANALYSIS METHODOLOGY OVERVIEW
AND AGGREGATE COMPLIANCE COST ANALYSIS
4.1 OVERVIEW OF METHODOLOGIES
In this chapter, EPA presents an overview of potential impacts of regulatory options for
the Coastal Guidelines. The overall analysis covers:
• Compliance costs to industry.
• Production losses (in terms of quantities of hydrocarbons not produced compared
to a no-regulation [baseline] scenario).
• Lost economic lifetime (i.e., the loss of productive years associated with wells
shutting in earlier under the regulation than under a baseline scenario).
• Numbers of production facilities or platforms immediately ceasing production as a
result of the regulation (first-year shut-in).
• Losses to operators (in terms of annualized compliance costs and losses in present
value of project net worth to the operator [NPV]),1 state governments, and the
federal government.
• Firm-level impacts (firm failure analysis).
» Employment impacts (losses and gains in employment).
• Balance of trade and inflation impacts.
• Impacts on small businesses (an analysis of whether impacts on small businesses
are severe, required by the Regulatory Flexibility Act [RFA], as amended).
• Impacts on new sources (barriers to entry).
1NPV is the total stream of a project's (e.g., platform's or facility's) cash inflows minus cash
outflows (operating costs, taxes, and investments) over a period of years (the facility's or
platform's lifetime) discounted back to present value.
4-1
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These individual analyses are interrelated, with the output of one analysis often used as
input for another analysis. The general flow of the analyses and their relationship to one another
are shown in Figure 4-1. As the figure shows, the first step in the analysis is to identify the
appropriate inputs. Because compliance costs (capital as well as operating and maintenance
[O&M] costs) are major inputs to all of these analyses, how these costs are annualized is a key
methodological decision. Section 4.2 discusses how and why costs are annualized, Section 4.3
describes all the regulatory options under consideration and the options selected for the Coastal
Guidelines, and Section 4.4 presents total aggregate compliance costs associated with each of the
BAT regulatory options and the Coastal Guidelines as a whole (the costs for the selected
regulatory options).
The first major analysis following cost annualization is the production loss analysis.2 In
general, EPA calculates compliance costs based on the volume of wastes generated by each
discharging treatment/separation facility.3 EPA then inputs the total compliance costs associated
with each treatment facility into an economic model of surveyed platforms (Cook Inlet, Alaska),
and treatment facilities (Major Pass operations) to look at annual cash flow and production
decisions (produce/shut in) based primarily on production operating cash flow (see Chapter Five
for more details). Compliance costs and production losses lead to losses in economic lifetime
(when the decision to shut in is made earlier than if the regulation were not in effect), which in
turn leads to production losses. Sometimes the results indicate that the operator might shut in a
2The cost annualization method used in this chapter (Chapter Four) is a simple method using
only the discount rate and number of years assumed to be typical for the life of a well, a
platform, or for drilling activity. The production loss model for Cook Inlet and Major Pass
dischargers uses a more sophisticated method to calculate annual costs that takes into account
accelerated depreciation and the modeled life of each platform (see Section 5.1). The simple
annualization used in Chapter Four produces pre-tax estimates of compliance costs and thus
overstates costs and impacts to producers because the state and federal governments will partially
subsidize these expenditures through deductions for accelerated capital equipment depreciation
and increased operating costs, which serve to reduce taxable income. The more sophisticated
Cook Inlet/Major Pass model can calculate the actual cost faced by producers in each year (a
post-tax cost). Additionally, if any baseline or first-year shut-ins occur, some portion of the
compliance costs presented in this chapter will not be incurred.
Compliance costs, i.e., capital and O&M costs to achieve different levels of control, were
derived separately from this economic analysis effort and are presented in a separate document
(see EPA's Development Document, for more details on the derivation of compliance costs).
4-2
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o:\s\g\econ\eia.ppt
4-3
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platform or facility as soon as the regulation becomes effective (referred to here as a first-year
shut-in); the Agency tallies this result. Compliance costs and production losses also lead to
declines in the present value of the project's net worth (i.e., NPV), which can be estimated when
EPA compares the model outputs from a baseline scenario to those from a postcompliance
scenario. The detailed methodology for the production loss modeling is discussed in Chapter
Five and Appendix A. Results are presented in Chapter Five. Production losses, first-year shut-
ins, and declines in the present value of project net worth (NPV) lead to secondary impacts on
federal and state revenues (see Chapter Five), operator revenues (see Chapter Five),
employment (see Chapter Seven), and possibly the balance of trade and inflation (see Chapter
Eight).
For the firm-level analysis, EPA again uses annual compliance costs compiled on an
operator-by-operator basis. The Agency compares these costs to working capital and equity
among the affected firms. Where a reduction in working capital and equity both exceed 5
percent, a more in-depth analysis, looking at cash flows and/or facility-specific data (where
possible), is undertaken to identify whether firm failure is a possibility (see Chapter Six).
Because a firm can use equity, working capital, or a combination of the two (among other
sources of financing), EPA judges that a firm will be able to obtain the capital and maintain and
operate the pollution control equipment if at least one measure changes by less than 5 percent.
4.2 COST ANNUALIZATION PURPOSE AND METHOD
EPA uses cost annualization to estimate the annual compliance cost to the operators of
new pollution control equipment. The cost of additional pollution control equipment has two
components: the initial capital investment to purchase and install the equipment, and the annual
cost of operating and maintaining such equipment. Capital costs are a one-time expense
incurred only at the beginning of the equipment's life, and O&M costs are incurred every year of
the equipment's operation.
To determine the economic feasibility of upgrading a treatment facility or transporting
and disposing wastes at a commercial facility, the costs for such efforts must be compared against
4-4
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the operation's annual revenues and its operator's capital structure. The initial capital outlay
should not be compared against the operation's or operator's income in the first year because
this capital cost is incurred only once. Additionally, annualizing costs over several years reflects
the common practice of financing capital expenditures, as well as the IRS requirement that
capital expenditures on pollution control be amortized and depreciated, not expensed.45 This
initial investment, therefore, should be spread out over either the well's or platform's life or the
equipment's life. Annualizing costs is a technique that allocates the capital investment over the
lifetime of the equipment, incorporates a cost-of-capital factor to address the costs associated
with raising or borrowing money for the investment, and includes annual O&M costs. The
resulting annualized cost represents the average annual payment that a given company will need
to make to upgrade its facility. The annualized cost is analogous to a mortgage payment, which
spreads the one-time purchase price of a home (the capital investment) into a series of constant
monthly payments.
In this section, the Agency annualizes costs using three inputs: the initial capital costs, the
discount rate, and the time period over which payments are made. EPA has set the discount
rate (real, adjusted for inflation) at 7 percent for simplicity. The average cost of capital over all
coastal respondents in the Section 308 Survey was estimated as 8 percent, but the typical (mean)
rate for Major Pass dischargers, weighted by production volumes, is 7 percent. Additionally, the
Office of Management and Budget (OMB) recommends a 7 percent real discount rate6 for
discounting social costs and benefits. The difference in results using 7 percent and 8 percent is
negligible.
The time period over which costs are annualized is 10 years for produced water and TWC
wastes and 7 years for drilling waste, since drilling will only occur during approximately a 7-year
4Houghton, James L. 1987. Arthur Young's Oil and Gas Federal Income Taxation.
Commerce Clearing House, Inc., Tulsa, OK.
5Research Institute of America. 1995. The Complete Internal Revenue Code. Research
Institute of America, New York, NY.
6U.S. Office of Management and Budget (OMB). Economic Analysis of Federal Regulations
under Executive Order 12866. January 11,1996.
4-5
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period in Cook Inlet.7 Because the drilling waste disposal equipment might not be used past
this 7-year life, the Agency has used a 7-year period to amortize the capital costs of drilling-waste
disposal options.8 Ordinarily, pollution control equipment is amortized over 15 years, but in this
case, because remaining project lives tend to be less than 15 years, EPA has selected a 10-year
amortization period over which to annualize pollution control costs. Because well life does not
necessarily relate to treatment facility life (wells can be shut in and new wells can be drilled to
replace them), EPA considers the 10-year period over which to amortize costs a conservative
estimate of project lifetime. The shorter the time frame used in the analysis, the higher (and
thus more conservative) the estimate of annual compliance costs will be.
The Agency undertook the cost annualization for drilling wastes in this section in a
slightly different manner than for the other waste streams. Unlike other wastes, which EPA
could assume are disposed of every year, drilling wastes are disposed of each time a well is
drilled. Based on a drilling schedule provided by Cook Inlet operators, the above discount rate
and time period assumptions, and the capital and O&M costs for all planned drilling projects
(see EPA's Development Document), the Agency calculated a present value for all costs over a
7-year period and then annualized these costs to create a consistent stream of payments over the
time frame. This approach is discussed in more detail in Section 4.3.2.
43 REGULATORY OPTIONS
The regulatory options that EPA developed are the basis for the engineering cost
estimates that feed into the cost annualization. This section summarizes these options. EPA's
'Industry supplied EPA with its plans to drill in Cook Inlet until approximately 2002 or a few
years beyond (Marathon/Unocal. 1994. "Zero Discharge Analysis: Cook Inlet, Alaska."
Marathon Oil Company and Unocal Corporation. March.). EPA selected 7 years as the time
between the expected promulgation date of this rule and end of drilling. Beyond this time, the
operators did not provide drilling plans.
is a conservative assumption that overstates compliance costs as reported in this section.
In Chapter Five, the Cook Inlet/Major Pass model is able to determine the actual life of the
platforms in question to compute a more precise, post-tax compliance cost estimated to affect
producers.
4-6
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Proposal Development Document9 contains a detailed discussion of the derivation of the initial
engineering cost estimates under each option.
EPA is required under Sections 301, 304, 306, and 307 of the Clean Water Act (the Act)
to establish effluent limitations guidelines and standards of performance for industrial
dischargers. EPA has already promulgated best practicable technology (BPT) regulations.
Pursuant to this authority, EPA is promulgating the following effluent limitations guidelines and
standards:
• BPT—For produced sand only. BPT had been set previously for all other
wastestreams.
• BCT—Effluent reductions employing the best conventional pollutant control
technology as required under Section 304(b)(4) (applicable to conventional
pollutants).
• BAT—Effluent reductions employing the best available control technology
economically achievable as required under Section 304(b)(2) (applicable to
nonconventional and toxic pollutants).
• NSPS—New source performance standards covering direct discharging new
sources as required under Section 306(b) of the Act (applicable to all pollutants).
• PSES—Pretreatment standards for existing sources (indirect discharges to publicly
owned treatment works [POTWs]; applicable to all pollutants).
• PSNS—Pretreatment standards for new sources (indirect discharges; applicable to
all pollutants).
For the purposes of analysis, the range of BCT, PSES, NSPS, and PSNS options
evaluated by EPA are identical to BAT options, although the pollutants controlled through BCT
requirements are total suspended solids (TSS) and oil and grease only (conventional pollutants).
In all cases, selected PSES and PSNS options equal zero discharge. EPA knows of no existing
indirect dischargers and anticipates no new ones. Therefore, EPA estimates that PSES and
"US. EPA. 1995. Development Document for Proposed Effluent Limitations, Guidelines,
and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category.
Washington, D.C. January 31.
4-7
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TABLE 4-1
BAT REGULATORY OPTIONS CONSIDERED IN THE ECONOMIC IMPACT ANALYSIS
Type of
Waste Stream
Produced
water/TWC
fluids
Drilling
wastes
Name
Option #1
Option #2
Option #3
Option #1
Option #2
Description
Zero discharge all, except for Major Pass and Cook Inlet
operations; for exceptions, limitations equal to "offshore
limits" apply
Zero discharge all, except for Cook Inlet operations; for
exceptions, limitations equal to "offshore limits" apply
Zero discharge all
Zero discharge all, except for discharge limitations
equivalent to current practice in Cook Inlet
Zero discharge all
4-8
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PSNS options for indirect dischargers will have no costs or impacts. This section discusses the
BAT, NSPS, and BCT options for the following waste streams:
• Produced water and well treatment, workover, and completion (TWC) wastes
• Drilling fluids and drill cuttings
The following waste streams also are regulated:
• Deck drainage
• Produced sand
• Sanitary waste
• Domestic waste
This FEIA does not assess impacts associated with these four waste streams because EPA
is selecting regulatory options for them that are equivalent to current practice and therefore
impose no costs on the industry.
All of the BAT, NSPS, and BCT options for produced water/TWC and drilling wastes are
described below in detail. (BAT options considered for waste types are summarized in
Table 4-1.) The selected options for produced sand, deck drainage, sanitary waste, and domestic
wastes also are briefly discussed. Note that BAT options for TWC wastes and produced water,
discussed separately in the proposal, are now combined.
4-3.1 Produced Water and TWC Wastes
Certain operations in the Gulf of Mexico and Cook Inlet currently discharge produced
water and are considered within the scope of the Coastal Guidelines. Additionally, some other
Gulf of Mexico operations that currently discharge produced water (but are expected to cease
discharging shortly as they are covered under the EPA Region 6 General Permit) might continue
to discharge TWC wastes if not for the Coastal Guidelines (the Region 6 permit for produced
4-9
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water does not cover TWC wastes). EPA proposed five BAT options for produced water (and
two for TWC wastes), but EPA is considering only three BAT options for produced water/TWC
wastes for final promulgation:
• Option #1 is zero discharge, except for Cook Inlet and offshore produced water
discharged into a major deltaic pass of the Mississippi River. For these
exceptions, limits on total oil and grease are 29 mg/L for monthly average and 42
mg/L for daily maximum (known henceforth as "offshore limits").
• Option #2 requires zero discharge except for Cook Inlet. For the exception,
requirements equivalent to "offshore limits" must be met.
• Option #3 requires zero discharge for all operations.
The selected BAT regulatory option is Option #2, which prohibits discharge in the Gulf
of Mexico but allows operations in Cook Inlet to meet limits equivalent to offshore limits. The
selected NSPS option is also Option #2, thus NSPS equals BAT (see Chapter Nine for a
discussion of NSPS). All options fail the BCT cost test (see EPA's Development Document), so
BCT is set equal to BPT, as required by Clean Water Act regulations.
433, Drilling Fluids and Drill Cuttings
All coastal areas, with the exception of Cook Inlet, are currently achieving zero discharge
of drilling fluids and drill cuttings. EPA Region 6 has promulgated a General Permit prohibiting
the discharge of drilling fluids and cuttings10; discharge of these wastes also is prohibited in
states outside Region 6 with coastal oil and gas operations (see Chapter Three), except for
Alaska. Also included in this waste stream is drill water effluent, but little to no drill water
effluent is currently discharged (see EPA's Proposal Development Document). EPA proposed
three BAT options, but is considering only two here (a toxicity-based option was dropped due to
lack of data):
1058 Federal Register 49126, September 21,1993. Final NPDES General Permits for the
Coastal Waters of Louisiana (LAG330000) and Texas (TXG330000).
4-10
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Option #1 requires zero discharge, except that Cook Inlet operations are required
to meet limitations equivalent to offshore limitations (30,000 ppm toxicity
limitation, no discharge of free oil, no discharge of diesel oil, and a
mercury/cadmium limitation in barite). This option reflects current practice and is
a no-cost alternative.
Option #2 requires zero discharge, regardless of location.
EPA has selected Option #1. EPA's selected NSPS option is also Option #1, EPA has
selected this option for both BAT and NSPS for the reasons stated in the preamble to the final
rule. Given that Option #2 does not pass the BCT cost test for the transport and landfilling
scenario, EPA has set BCT equal to BPT. Thus no costs are associated with this selected option
for either BAT or NSPS. EPA has set PSES and PSNS to zero discharge, and thus these options
also impose no costs.
4.3.3 Other Miscellaneous Wastes
EPA has selected zero discharge for produced sand under BPT, BAT, NSPS, PSES, and
PSNS, and has set BCT equal to BPT. This is a no-cost option (zero discharge is current
practice).
For deck drainage, EPA has set BAT, BCT, and NSPS requirements equal to BPT: no
free oil. EPA expects no costs or impacts because the proposed requirements are current
practice. The Agency also has set PSES and PSNS to zero discharge. As this is current practice,
this is also a zero-cost option.
EPA's NSPS and BCT options for sanitary waste only apply to facilities continuously
manned by 10 or more persons. Sanitary effluent must contain a minimum residual chlorine
content of 1 mg/L, with the chlorine level maintained as close to this concentration as possible.
Facilities continuously manned by nine or fewer persons must not discharge floating solids.
Alternative water quality-based limitations may be used to address state standards for total
residual chlorine. These options are equivalent to current practice and thus are no-cost options.
EPA has considered no BAT limitations (because the only parameters considered for regulation
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are conventional) and has set no PSES or PSNS limitations (these are standard wastes for
POTWs).
The options selected for domestic wastes are as follows: BCT is no discharge of floating
solids or garbage, BAT is no discharge of foam, and NSPS is no discharge of floating solids,
foam, or garbage. PSES and PSNS are not regulated (domestic wastes are standard wastes for
POTWs). These options are equivalent to current practice and thus are no-cost options.
4.4 AGGREGATE COMPLIANCE COSTS
This section presents the aggregate compliance costs for BAT options for the waste
streams considered in this FEIA, and also presents estimates of costs of NSPS under the selected
option for produced water/TWC and drilling wastes (NSPS costs for other waste streams are
zero). These estimates of compliance costs are considered worst-case because in some instances
certain costs will not be incurred. For example, if a facility is projected to shut in in the baseline
analysis, costs to meet zero discharge requirements will not be incurred. Nonetheless, the
compliance cost analysis discussed below includes such costs.
4.4.1 BAT Options
4.4.1.1 Produced Water/TWC Wastes
EPA has derived the aggregate compliance costs for produced water from estimates of
capital and operating costs for the following types of locations and pollution control approaches
(see EPA's Development Document):
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Gulf of Mexico
Improved gas flotation: Capital and operating expenditures to install
improved gas flotation equipment (i.e., equipment capable of meeting the
more stringent offshore limitations on grease and oil) at discharging
separation/treatment faculties were estimated. The discharging
separation/treatment facilities of concern are those Gulf of Mexico
operations that will need to dispose of TWC wastes (EPA's Proposal
Development Document), as well as Major Pass dischargers.
Zero discharge: Capital and operating expenditures to install injection
wells or to transport produced water to commercial disposal facilities were
estimated for the same group of treatment facilities identified above. In
general, injection wells were assumed to be installed at the larger
treatment facilities, whereas produced water from the smaller facilities was
assumed to be transported to a commercial disposal facility.
Cook Inlet
Improved gas flotation: Costs to install and operate improved gas
flotation equipment were derived for each platform (where platform
treatment and discharge currently takes place) or centralized onshore
treatment facility (where produced water is piped to shore for treatment).
Zero discharge: Costs to install and operate injection wells, as well as
relevant piping, were derived for each platform or onshore treatment
facility.
After EPA annualized the capital costs and added them to operating costs for each
platform or facility, it combined costs for each of these options within regions. Aggregate
annualized compliance costs for Options #1 through #3 are shown in Table 4-2. The
compliance costs range from $3.7 million to $47.9 million. The selected option, Option #2, is
associated with costs totaling $15.6 million. The columns for each affected group do not add to
the total because TWC waste disposal costs of $0.7 million per year have not been broken down
by group but instead have been added to the total to reflect the fact that they affect not only the
Major Pass operations, but also certain other operations in the Gulf. Total Cook Inlet costs
already incorporate costs to dispose of TWC wastes. Note that EPA has calculated all
compliance costs on a pre-tax basis. This approach overestimates the annual costs to industry
because the state and federal governments will partially subsidize these expenditures through
deductions for accelerated capital equipment depreciation and increased operating costs, which
serve to reduce taxable income. Although EPA has not calculated post-tax compliance costs to
4-13
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TABLE 4-2
AGGREGATE ANNUAL COSTS FOR BAT OPTIONS BY
REGULATORY OPTION AND AFFECTED GROUP ($ millions 1995)
Type of Waste Stream
Produced water/TWC
fluids
Drilling waste
Option
Number
Option #1
Option #2
Option #3
Option #1
Option #2
Major
Pass
$0.5
$12.5
$12.5
$0
$0
Cook
Inlet
$2.5
$2.5
$34.8
$0
$9.2
Aggregate
Annual Cost
(Pre-tax)
$3.7
$15.6
$47.9
$0
$9.2
Note: Aggregate totals include costs of $0.7 million for TWC, while costs for individual
affected groups do not.
Source: ERG estimates based on engineering costs from EPA's Development Document.
4-14
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industry, in Chapter Five the Agency uses post-tax costs to estimate changes in project net worth
and production losses and also estimates the reduction in tax revenues to the state and federal
governments from both compliance cost effects and production losses.
4.4.1.2 Drilling Waste
In all coastal subcategory locations but Cook Inlet, zero discharge of drilling waste is
current practice; consequently, requirements for drilling waste under the Coastal Guidelines are
no-cost requirements. In Cook Inlet, Option #1 is current practice, but Option #2 requires zero
discharge of drilling waste. For Cook Inlet dischargers, EPA has derived aggregate compliance
costs for zero discharge of drilling wastes from estimates of capital and operating costs
(presented in EPA's Development Document) under two scenarios: 1) drilling waste is disposed
of by grinding and injecting the waste into Class II injection wells, and 2) drilling waste is
disposed of by transporting waste to onshore disposal facilities using closed-loop systems to
reduce wastes. EPA uses the more expensive scenario (onshore disposal) here as the relevant
cost of compliance because it is not clear that injection is technologically feasible.
In annualizing costs, EPA first calculated costs for landfill disposal per barrel of waste
and converted these to costs per new or recompleted well drilled, based on the expected volume
of wastes. Then, using a drilling schedule developed from discussions with operators (Table 4-3),
EPA developed a cost schedule based on the drilling schedule (Table 4-4). Costs assumed to be
incurred in the first year include all capital costs for any operations incurring a capital cost, plus
the costs to dispose of wastes from the wells planned to be drilled in the first year. In the
second and subsequent years, EPA included only those costs for disposing of the wastes from
wells planned to be drilled. To derive an annualized cost figure, the Agency calculated the
present value of these expenditures and annualized this value over 7 years, producing a constant
stream of expenditures over the 7-year period (Table 4-4).
Table 4-2 presents the aggregate compliance costs for drilling waste Options #1 and #2;
compliance costs range from $0 to $9.2 million.
4-15
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TABLE 4-3
ASSUMED DRILLING SCHEDULE USED FOR ANNUALIZING DRILLING COSTS
Platform
Grayling
King Salmon
Dolly Varden
Steelhead
Monopod
Baker
Dillon
Bruce
Granite Pt.
Anna
Spark
Spurr
SWEPI A and
C
Tyonek
1997
3N
3N
4N,
2R
3N
ION
1998
3R
2N,
3R
IN,
2R
1R
1999
4N,
2R
3N
2R
2000
5N,
2R
2001
2R
1R
2002
2003
3N
N = New well
R 3* Recompletion
Sources: Mclntyre, Jamie, Avanti, Personal communication with Anne Jones, ERG, dated
May 17,1996, regarding numbers of new wells and recompletions to be drilled by
platform.
Marathon/Unocal. 1994 "Zero Discharge Analysis: Cook Inlet Alaska." Marathon Oil
Company and Unocal Corporation. March.
4-16
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4-17
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4.4.1.3 Total Aggregate Compliance Costs for the Selected BAT Regulatory Options
Table 4-5 presents the total aggregate compliance costs for the selected regulatory
options (Option #2 for produced water/TWC wastes and Option #1 for drilling waste). These
regulatory requirements will amount to $15.6 million annually.
4.4.2 NSPS Options
Produced Water/TWC
For produced water dischargers in the Major Passes, as discussed in EPA's Development
Document, EPA does not expect any new sources to discharge to the Major Passes. Further, in
the absence of the Coastal Guidelines, any new source in an area covered by the existing General
Permit would be subject to zero discharge. For these reasons, there are no costs for NSPS for
produced water in the Gulf of Mexico coastal area (see EPA's Development Document).
With respect to produced water/TWC requirements in Cook Inlet, EPA estimates that
even if oil prices were to increase substantially, the economics in Cook Inlet preclude the
development of a new platform, given the level of production per platform currently and
historically seen in the Inlet. EPA constructed a financial model using data from the most
recently constructed platform in Cook Inlet and concluded that, given no major changes in oil
prices or other unusual conditions, a profitable new platform could not be constructed in the
Inlet.11 Discussions with industry have substantiated EPA's findings (see Chapter Three). The
Agency did conduct an analysis to determine if NSPS costs could pose a barrier to entry for new
projects in Cook Inlet. The results of this analysis, as well as EPA's baseline NSPS analysis, are
presented in Chapter Nine.
Discharge of TWC wastes in the Gulf of Mexico area is not covered by either of the
Region 6 General Permits (drilling waste or produced water). Thus, EPA has estimated that 45
"NSPS Production Loss Model Runs (CBI data; in rulemaking record).
4-18
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TABLE 4-5
AGGREGATE ANNUAL COSTS FOR SELECTED BAT REGULATORY OPTIONS
($ million 1995)
Type of Waste Stream
Produced water/TWC fluids
Drilling waste
Total
Selected Option
Number
Option #2
Option #1
Aggregate Annual
Cost Range
(Pre-tax)
$15.6
$0
$15.6
Source: ERG estimates based on engineering costs from EPA's Development
Document.
4-19
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new wells meeting the definition of a new source will be drilled each year in the Gulf coastal
region and will require disposal of TWC fluids (see EPA's Development Document). The costs
per year for each group of 45 wells will total $85,909 under Option #\ and $86,363 under
Options #2 and #3. In year 1, O&M costs for 45 wells are incurred. In year 2, O&M costs for
90 wells are incurred. In year 3, O&M costs for 135 wells are incurred, and so on out to 15
years. EPA compiled the present value of these capital and O&M outlays over 15 years12 (at a 7-
percent real discount rate). Note that EPA assumed that the initial outlay occurs at the end of
1996 and recurs at the end of every period thereafter (as opposed to occurring at the beginning
of the period, which provides a slightly different result). EPA then annualized the present value
of these outlays.
The total present value of zero discharge of TWC wastes under NSPS is approximately
$5.3 million, with an annual cost around $0.6 million. Table 4-6 presents the cost for the
selected NSPS option (Option #1—zero discharge all, except discharge limitations for Cook
Inlet).
Drilling Wastes
NSPS for drilling waste is set at zero discharge all, except for Cook Inlet, for which
toxicity limits equivalent to current practice is required. Thus NSPS for drilling waste is a no-
cost requirement.
4.4.3 Total Estimated Cost of the Coastal Guidelines
The estimated cost of the Coastal Guidelines is $15.6 million per year for BAT
requirements and $0.6 million per year for NSPS requirements, for a total of $16.2 million.
"EPA assumed a 15-year lifetime rather than a 10 year-lifetime in the NSPS analysis because
new wells or projects should have a longer productive life than existing wells or projects.
4-20
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TABLE 4-6
TOTAL ANNUAL COSTS FOR ALL SELECTED BAT AND NSPS REGULATORY OPTIONS
($ million 1995)
Type of Waste Stream
Produced water/TWC fluids
Drilling waste
NSPS, produced water/TWC fluids
Total
Selected
Option
Number
Option #2
Option #1
Option #1
Aggregate
Annual
Cost Range
(Pre-tax)
$15.6
$0
$0.6
$16.2
Source: ERG estimates based on engineering costs from EPA's Development
Document.
4-21
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Thus, this rulemaking does not qualify as a major rule under OMB guidelines (Executive Order
12866) and a Regulatory Impact Analysis (RIA) is not required.
4-22
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CHAPTER FIVE
PRODUCTION LOSS IMPACTS AND OTHER IMPACTS TO
PLATFORMS AND FACHJTIES
This chapter describes the production loss model EPA developed to simulate the
economic performance of coastal production and drilling projects, as well as the results of
inputting the compliance costs into this model. Section 5.1 presents a description of the
economic simulation methodology for Cook Inlet and Major Pass operations, and Section 5.2
presents the results of production loss modeling for these groups. Firm-level impacts are
discussed later in Chapter Six.
As part of its modeling effort, EPA defines a "baseline" scenario in which modeled
treatment/separation facilities and platforms are assumed to be operating without incremental
compliance costs. To estimate the incremental impacts of the rulemaking, EPA then compares
this baseline scenario to a "postcompliance" scenario that incorporates the costs of complying
with new pollution control requirements.
More specific information on the methodology used in this FEIA can be found in the
appendices. Appendix A presents detailed derivations of selected assumptions used in the
models. Appendix B provides greater detail on the Cook Inlet/Major Pass production loss model
and presents the calculations summarized in this chapter.
5.1 DESCRIPTION OF THE ECONOMIC MODEL FOR COOK INLET, ALASKA,
OPERATIONS AND MAJOR PASS DISCHARGERS
This section reviews the economic model and its components for Cook Inlet, Alaska,
operations and Major Pass dischargers.
Fifteen platforms are located in Cook Inlet, all in the coastal subcategory of the oil and
gas extraction point source subcategory. Thirteen of these platforms are currently productive
5-1
-------
and are included in the Cook Inlet model analysis. Two platforms operated by Shell Western
(SWEPIA and SWEPI C) send production to the East Forelands facility and are combined in
this analysis to more accurately reflect the circumstances faced by Shell Western in making
operating decisions.1 Phillips operates a single platform (Tyonek A), and Unocal operates four
platforms (Anna, Baker, Bruce, and Dillon) and two facilities (Granite Point, which services the
Granite Point platform, and Trading Bay, with platforms Dolly Varden, Grayling, King Salmon,
Monopod, and Steelhead). Unocal has suspended production at two other platforms (Spurr and
Spark); these platforms are not included in the analysis since no associated drilling is planned.
ARCO's Sunfish project is uncertain, but it is unlikely that a Sunfish platform will be
constructed.2
Analysis of coastal oil and gas production for the Major Pass dischargers is conducted at
the level of produced water treatment facilities (defined by outfall), rather than at the platform
level. There are eight produced water treatment/separation facilities included in the model
analysis. All eight discharge offshore produced water into the major passes of the Mississippi
River (see EPA's Development Document).
5.1.1 Economic Model Overview
The production loss model simulates the performance and measures the profitability of a
petroleum production project. For the Cook Inlet region of the coastal subcategory, EPA
defines a project as a single platform or, in the case of SWEPI, the platform pair. For Major
Pass dischargers, EPA defines a project as a single facility (i.e., outfall). All projects used in the
Cook Inlet/Major Pass model are modeled starting in productive midlife (i.e., not including
*At proposal, these were treated as separate facilities.
2Wiedeman, Allison, U.S. EPA, Personal communication with Jim Short, ARCO, dated
May 9,1994, regarding ARCO's future drilling activity in Cook Inlet—status of ARCO's Sunfish
operations in Cook Inlet, Alaska.
5-2
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exploration and development costs, which are sunk costs).3 For each project, modeling inputs
include production and operations cost data, typical production rates, oil and gas selling prices,
on-going drilling schedules and costs, and other pertinent data. Drilling plans associated with
existing structures/facilities and related production increases are also considered. For each
project, EPA calculates the annual post-tax cash flow for each year of operation, as well as
cumulative performance measures such as the present value of the project net worth (i.e., the
net present value [NPV] of the project4) and total lifetime petroleum production. The same
cash flow results enter into firm-level calculations discussed in Chapter Six.
Figure 5-1 summarizes the schematic design of the EPA model. Three sets of exogenous
values are entered into the model: general model parameters (Tables 5-1 and 5-2), project-
specific variables, and pollution control costs (discussed in Chapter Four).
Calculation procedures and algorithms in the model duplicate 1) the oil industry's
standard accounting procedures, 2) federal taxation rules enacted by the Tax Reform Act of
1986, and 3) standard financial rate-of-return calculation methods. The model's outputs are a
series of yearly project cash flows and cumulative performance measures.
EPA incorporates regulatory costs into the economic model by adding regulation-induced
capital costs and operating expenses to the set of cost data. The Agency calculates all yearly and
cumulative outputs for both the baseline case and the regulated case for each project. The
incremental impacts of regulation are the differences in results between these two scenarios.
3OMB directs government agencies to disregard sunk costs in regulatory analysis as part of
establishing a baseline (U.S. Office of Management and Budget [OMB]. Economic Analysis of
Federal Regulations under Executive Order 12866. January 11, 1996.) As will be discussed in
Section 5.1.5.4, cost depletion, which is calculated on the basis of the leasehold cost, would be
inappropriate to model because the leasehold cost is a sunk cost.
4NPV is the present value of a stream of cash inflows (oil and gas revenues) minus cash
outflows (including operating costs, investments, and taxes) from a baseline year to the end of a
project's economic life, discounted annually by the real discount rate. The project end is defined
as the point when operating costs, including pollution control costs, exceed revenues. The
difference between baseline NPV and post-compliance NPV represents the impact of pollution
control requirements on an oil and gas project's net worth as seen by the producer.
5-3
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Oil & Gas Prices
Production Levels
Decline Rates
Royalties
Severance Taxes
Corporate Taxes
Baseline O&M Costs
Depreciation Schedule
Depletion Allowance
Pollution Control Costs:
Capital Costs
O&M Costs
Baseline Annual Costs
Incremental Annual
Costs
Operate for
Another Year
I
Baseline Analysis:
Annual Decision
Is Cash Flow Positive?
No
Calculate:
Net Present Value
Annualized Costs
Summary Statistics
(includes well/platform lifetime and lifetime production)
5^
?aaggM»ilaaa?a
Postcompliance Closure Analysis
Pre- vs. Postregulatory Model Results
(comparison external to model):
• Well/platform has shortened economic lifetime
or
• Well/platform closes in first year due to annual costs
exceeding revenues in first year
or
•Well/platform determined to close in first year because investment
pollution control is not economic:
-Unregulated NPV >0
-Regulated NPV <0
in
_L
Count as Regulated
Closure:
• Closes in first year
or
• NPV changes from
positive to negative
Compute
Lost Years
of
Production
Compute
Loss of
Revenues
(lifetime)
Compute
Loss of
Production
(lifetime)
Figure 5-1. Overview of closure analysis methodology
closs.ppt
5-4
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5.1.2 Model Parameters and Variables
A distinct set of parameter values and project-specific variables is required for each of
the operating units (platforms or facilities) modeled; this set constitutes a complete economic
description of an individual project. EPA has incorporated the following categories of common
parameters and project-specific variables into the model:
Production rates per operating unit. Initial production rates of oil and gas, and
production decline rates.
Baseline operating and maintenance costs per operating unit (estimated by
multiplying the initial year per-BOE cost by the initial year's production in
BOE5). In the absence of production increases due to drilling activity, total
operating costs are held constant over the life of each individual project because it
is assumed that the total volume of fluid pumped remains constant even as oil and
gas production levels decline. Holding the cost constant has the effect that the
per-BOE cost rises over time as production declines. If drilling results in
increased production, baseline O&M costs are increased on a per BOE basis or,
where sufficient information is available, on a marginal cost per BOE basis.
Incremental pollution control capital costs.6
Incremental pollution control operating and maintenance costs. The assumption of
constant pollution control O&M costs is made for Cook Inlet platforms and
Major Pass facilities, although it does not hold true for individual wells (Chapter
Ten uses a different approach since it is based on analysis of individual wells). In
Cook Inlet, produced water volumes have remained relatively steady over the last
five or six years, and thus are assumed to continue to remain steady. Unocal, in
fact, appears to have used a constant O&M compliance cost assumption in its own
zero discharge analysis (Marathon/Unocal presentation).7 Relevant data provided
by the Major Pass operators, moreover, also does not appear to support a rising
O&M cost assumption.
5Barrels of oil equivalent (BOE) represents the total oil and gas produced, with gas converted
to an equivalent measurement based on the amount of energy in a cubic foot of gas and the
number of cubic feet of gas needed to match the energy in a barrel of oil.
'This is an endogenous variable in EPA's analysis (i.e., the costs depend on the pollution
control option analyzed).
7Marathon/Unocal. 1994. "Zero Discharge Analysis: Cook Inlet, Alaska." Marathon Oil
Company and Unocal Corporation. March.
5-5
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• Discount and inflation rates.
• Tax rates. Rates for federal and state income taxes, severance taxes, royalty
payments, depreciation, and depletion.
» Price. Wellhead selling price of oil and gas (also called the "first purchase price"
of the product).
• Drilling cost per well. Costs for both new production wells and recompletions.
" Drilling schedule. Schedule for Cook Inlet, detailing platform-specific drilling
activity from 1997 to 2002 for new production wells and recompletions (see
Table 4-3 in Chapter Four). Schedule for Major Pass operations varies, as
reported by the individual operators.
For some of these categories, values may be common to all Cook Inlet operators while varying
among the Major Pass operators; for other categories, values may be common to all Major Pass
operators while varying among the Cook Inlet operators. Tables 5-1 and 5-2 summarize some of
the values used by EPA in its analysis. Appendix A describes the model parameters and project-
specific variables in more detail.
5.13 Model Calculation Procedures
The model's calculation procedures include the rules and logic used to convert the
common parameters and project variables into measures of a project's financial performance.
These procedures fall into several categories: production logic, cost logic, incremental pollution
control cost logic, cost accounting practices, price and revenue calculations, earnings and cash
flow analysis, and financial performance calculations. Each of these categories is discussed
briefly below.
5.13.1 Baseline Production Logic
EPA defines a production profile for each operating unit using values for peak, or initial,
production rates and production decline rates that were provided by the individual operators or,
where individual operator data was missing, estimated these values based on averages for the
5-6
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-------
relevant group (i.e., Cook Inlet or Major Pass). Production figures include both current
production and increases in production from new and recompleted wells brought online. EPA
also calculates summary measures of production for the entire project lifetime.
5.1.3.2 Baseline Cost Logic
EPA uses exogenous cost data to define the yearly capital and operating costs of each
project. Exogenous parameters include drilling capital costs, production costs (including existing
pollution control costs), and drilling operating costs. The Agency assumes that capital costs for
new wells are incurred in the year in which they are drilled. A portion of these costs is expensed
for purposes of calculating taxable income. EPA converts all cost information to annual capital
and operating cost streams and calculates summary measures (e.g., of all capital and operating
costs for the entire project lifetime) using the model.
5.1.3.3 Incremental Pollution Control Cost Logic
A set of equations defined by EPA incorporates the capital and operating costs of
additional pollution control approaches into the project cost stream, thus creating a simulation of
the economic effects of the various regulatory alternatives. Pollution control costs can include
capital and operating costs for disposal of both produced water and drilling wastes. Pollution
control capital costs are incurred in the base year (1997) and are capitalized and depreciated for
the purposes of calculating taxable income for the year in which they are incurred. EPA analyzes
pollution control operating costs in the same way as other operating costs for the project.
5-10
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5.1,3.4 Cost Accounting Practices
EPA analyzes capital and operating costs and project cost streams in accordance with oil
industry accounting practices.8-9-11*11 The Agency calculates the expensed and capitalized
portions of each capital expenditure, then uses these amounts to estimate depreciation and
taxable income for each year of the project's lifetime.
5.1.3.5 Price and Revenue Calculations
For the Cook Inlet projects, wellhead prices of oil and gas (exogenous parameters in the
model) are based on information provided by the Marathon/Unocal presentation.12 Wellhead
prices for the Major Pass projects are based on information provided by the individual
operators.13 EPA multiplies these prices by the annual production volumes to calculate annual
project revenues. Revenues are calculated both as an annual stream and as a present-value-
equivalent total for the project's lifetime.
8Johnston, Daniel. 1992. Oil Company Financial Analysis in Nontechnical Language.
PennWell Publishing, Tulsa, OK.
'Logsdon, Charles. Personal communication between Charles Logsdon, Alaska Department
of Revenue, and Cathy Scholz, ERG, dated August 14,1996, regarding oil and gas taxes in
Alaska.
10Snook, S.B., and WJ. Magnuson, Jr. 1986. "The Tax Reform Act's Hidden Impact on Oil
and Gas." The Adviser. December, pp. 777-783.
"Research Institute of America. 1995. The Complete Internal Revenue Code. Research
Institute of America, New York, NY.
12Marathon/Unocal. 1994. "Zero Discharge Analysis: Cook Inlet, Alaska." Marathon Oil
Company and Unocal Corporation. March.
13Major Pass Dischargers Data Submittals (CBI data; in rulemaking record).
5-11
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5.13.6 Earnings and Cash Flow Analysis
As part of its analysis, the Agency calculates a project's annual net cash flow from
operations (i.e., the difference between a project's revenues and its operating costs). First,
severance tax and royalty payments are subtracted from total revenues to calculate annual net
revenues. Operating costs (including pollution control operating costs) are then subtracted to
calculate earnings, and federal and state corporate taxes are removed to calculate net cash flow
from operations. Federal laws dictate EPA's treatment of depreciation, depletion, and
expensable capital costs in these calculations (see Appendix A).
A $0.05/bbl tax is applied to oil production in Cook Inlet, and severance taxes on gas
production in the Inlet are calculated using an Economic Limit Factor (ELF). Severance taxes
for the Major Pass dischargers are based on Louisiana state tax rates and tax abatements, as
specified by the individual operators. Tables 5-1 and 5-2 present tax rates and royalty rates.
5.1.3.7 Financial Performance Calculations
EPA calculates a variety of summary financial measures using the model. For Cook Inlet
present value calculationsrEPA discounted annual project cash flows using an 8 percent real
discount rate (i.e., 8 percent after adjusting for inflation). The 8 percent discount rate is both
the rate used in the Offshore EIA14 and the average reported by all Section 308 Survey
respondents (Section 308 Survey Questionnaires, Rulemaking Record). For the Major Pass
dischargers, EPA discounted annual project cash flows using a 7 percent discount rate, the
production weighted average for the Major Pass operations that reported a discount rate to
EPA.15
"U.S. EPA. 1993. Economic Impact Analysis of Effluent Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry. Washington, D.C. January.
* "Major Pass Dischargers Data Submittals (CBI data; in rulemaking record).
5-12
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In addition to cash flows, EPA's model summarizes lifetime petroleum production (on a
total and present value basis), total revenues, total costs, years of production, and average costs
per unit of production (calculated as the present value of all project costs divided by the present
value of all petroleum production).
The specifics of each of these calculations are given in more detail in Appendix B, which
describes the Cook Inlet/Major Pass production loss model.
5.1.4 Interpretation of Model Results
Based on the economic model logic described above, EPA calculates a number of
summary statistics and performance measures for each project, including:
• NPV of the project (present value of project net worth from the producer's
perspective)
• Total lifetime production (BOB)
• Present value equivalent of production (PVBOE)
» Total years of production
» Economic viability of the project (first-year closure)
• Present value of all project costs
• Present value of all project revenues
• Present value of additional pollution control costs
• Present value of severance tax payments
• Present value of corporate income tax payments
• Present value of royalties
• Corporate cost per unit of production
• Production cost per unit of production
5-13
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The analysis of the economic status of the baseline case (presented in Section 5.2) focuses on the
first few performance measures listed above. The analysis of regulated cases includes
comparisons between the base case statistics and regulated (postcompliance) case results.
The net present value of the project is calculated as the difference between the present
values of all cash inflows and all cash outflows associated with a project (from the perspective of
the firm). A positive value indicates that a project generates more revenues than would be
realized by investing the capital in a different opportunity with an expected rate of return equal
to the cost of capital (discount rate) used in this analysis.
Total lifetime production sums the stream of future petroleum production.
The present value equivalent of production is defined as the value of the discounted stream
of future petroleum production (i.e., it reflects BOE discounted to the present under the
assumption that a barrel of oil today is worth more than a barrel of oil in the future under a
constant, real dollar per barrel of oil scenario).
Total years of production is calculated as the number of years the project will operate with
a positive cash flow. EPA's model can estimate annual cash flows over a 30-year lifetime. The
Agency assumes that a platform will stop producing when operating cash flow becomes negative
(i.e., when current variable costs exceed current revenues).16
The corporate cost per unit of production is defined as the present value of all net
corporate cash outflows for the project life (i.e., the cost of operation, royalties, severance tax
and income tax payments, with adjustments made for tax savings based on expensed capital
expenditures, depreciation, and depletion) divided by the present value of all production (e.g.,
BOE of oil and gas production). The present value calculations use a cost-of-capital interest rate
of 8 percent for the Cook Inlet platforms and 7 percent for the Major Pass dischargers to
16In the Cook Inlet/Major Pass model, variable costs consist of the baseline operating costs
plus (in postcompliance scenarios) the O&M cost component of pollution control costs. Fixed
costs do not play a role in the production decision.
5-14
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discount costs, cash flow, and production.17 If the corporate cost per unit of production is
lower than the projected wellhead selling price, the project is considered viable.
The production cost per unit of production is a measure of the value of net social
resources expended in operation of coastal petroleum projects. In contrast to the corporate cost,
the production cost ignores the effect of transfers that do not use social resources, such as
income taxes, revenue taxes, and royalties. The present values of all investment costs and
operating costs are summed in the calculation of this cost. This sum is divided by the present
value equivalent of production to obtain production costs.
5.1.5 Data Sources and Values for Common Parameters and Project-Specific Variables
For all Cook Inlet platforms and Major Pass dischargers, EPA considers previously
expended costs (i.e., leasing, exploration, delineation, and platform installation costs) to be sunk
costs. Tables 5-1 and 5-2 summarize the common parameter values and some of the project-
specific variables used in the models. All costs are in 1995 dollars (or are deflated/inflated to
1995 dollars), and year 1 in the model is 1997, the year the regulation is assumed to go into
effect. Pollution control costs are incorporated into the model at the beginning of 1997 because
even if the regulation is not effective until mid-1997, partial years cannot be modeled for
impacts.
5.13.1 Drilling Schedule and Drilling Cost per Well
EPA analysis of the Cook Inlet platforms and Major Pass dischargers incorporates future
drilling and production as well as current production. The economic model for each platform
"The 8 percent discount rate for Cook Inlet is based on the average for all operators among
the Section 308 Survey respondents and is unchanged from analyses used to support the proposal
(Section 308 Survey Questionnaires, in rulemaking record). The 7 percent discount rate is the
production-weighted average of discount rates reported by the Major Pass dischargers (Major
Pass Dischargers Data Submittals [CBI data; in rulemaking record]).
5-15
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reflects the costs for the new and recompleted wells in the baseline case (i.e., drilling costs and
the resultant production increases are included in the economic profile of platforms before
compliance costs are incurred).
The planned drilling programs in Cook Inlet are summarized in Chapter Four (see
Table 4-3). Drilling is projected to occur from 1997 through 2002. The Agency made three
assumptions in developing the drilling schedule from the information submitted to EPA by the
Cook Inlet operators:
• The regulation takes effect in 1997.
» Drilling is begun and completed in a 3-month period.
• All wells are drilled in the earliest year possible after 1996, given the planning
window (e.g., if the well is to be drilled sometime between 1997 and 1999, the well
is assumed to be drilled in 1997). Given the previous assumption, since no more
than four rigs are available at any one time to Unocal, Unocal can drill a
maximum of 12 wells in any one year.
The drilling schedule and drilling costs for the Major Pass dischargers are based on
information provided by the individual operators regarding development plans and expected
production from new and recompleted wells.
The model differentiates between drilling costs for new and recompleted production
wells. Drilling costs for new wells include costs to drill three segments of a well. Recompletion
costs include costs to recomplete the third segment of a well. Section 308 Survey data estimated
the per-well cost for new production wells in Cook Inlet to be $4.5 million and the cost for
recompletions to be $1.5 million (see EPA's Development Document). Drilling costs applied in
the Major Pass analysis vary by operator.
EPA assumes that the oil company elects to expense intangible drilling costs (IDCs)
incurred in the development of oil and gas wells. IDCs are estimated, on average, to represent
5-16
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60 percent of the cost of production wells and their infrastructure. 18>19>2° The Tax Reform
Act limits major integrated oil producers to expensing 70 percent of IDCs, with the remaining 30
percent capitalized (i.e., a major may only expense 0.60 times 0.70, or 42 percent of its costs of
production wells and infrastructure). The remaining 58 percent of the total cost of production
wells and infrastructure is capitalized and depreciated for tax purposes.21 EPA depreciates
these capital costs using the Modified Accelerated Capital Recovery System (MACRS) over a 7-
year period (see Appendix A). Once adjustments have been made for all depreciation and tax
shield benefits, EPA takes the total capital cost into account in calculating the project NPV.
5J.J.2 Production Kates
The Agency estimates 1997 production for projects in the Cook Inlet/Major Pass model
on the basis of 1995 production rates (see EPA's Development Document). Based on responses
to the Section 308 Survey, EPA assumes that the platforms in Cook Inlet (except Steelhead and
Tyonek A) consume all gas produced at the platform. Information supplied to EPA by the
individual Major Pass operators indicates that all the affected facilities produce and sell both oil
and gas.
18U.S. Department of Commerce. 1992. Annual Survey of Oil and Gas, 1980. U.S.
Department of Commerce, Bureau of the Census, Current Industrial Reports. MA-13k(80)-l.
March.
19U.S. Department of Commerce. 1993. Annual Survey of Oil and Gas, 1981. U.S.
Department of Commerce, Bureau of the Census, Current Industrial Reports. MA-13k(81)-l.
March.
20API. 1986. 1984 Survey on Oil and Gas Expenditures. American Petroleum Institute,
Washington, D.C. October.
21Snook, S.B., and W.J. Magnuson, Jr. 1986. "The Tax Reform Act's Hidden Impact on Oil
and Gas." The Tax Adviser. December, pp. 777-783.
5-17
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5.13.3 Baseline Operation and Maintenance Costs per Project
Annual operating costs for oil-producing platforms in Cook Inlet are estimated as the
product of 1995 production rates and a per-barrel operating cost. In making this calculation,
EPA assumes a per-barrel cost of $7.68, loosely based on approximations of baseline projections
provided by the Marathon/Unocal presentation and inflated to 1995 dollars. This figure falls
within the range for per barrel O&M costs submitted by Marathon/Unocal.23 For gas producing
platforms, annual operating costs are based on Section 308 Survey data (Section 308 Survey
Questionnaires).
Operating costs for the Major Pass projects (which produce both oil and gas) are based
on information provided to EPA by individual operators. Each operator's per-BOE cost is
multiplied by 1995 production rates (in BOE) to approximate annual costs.
For projects with drilling plans expected to yield substantial additional production relative
to current production, the Agency assumes that operating costs will increase relative to the
volume of additional oil, gas, and water to be handled by treatment facilities (i.e., the larger
volume of produced fluids to process would result in additional operating costs). These
additional costs are calculated on a per-BOE basis or, where sufficient information is available,
on a marginal cost-per-well basis.
5.13.4 Tax Rates
The tax rates used in the model include federal and state corporate tax rates, severance
taxes, and royalty payments.
^Marathon/Unocal. 1994. Confidential data provided to U.S. EPA. Document Control
Number 1304-1. March 24.
5-18
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In Cook Inlet, EPA applies a federal corporate tax rate of 34 percent to all operators.24
Severance taxes are calculated using the ELF. The Alaska Department of Revenue reports that
oil wells in Cook Inlet have not incurred severance taxes for several years (see Appendix A for
more information); only the gas severance tax is in effect. Royalties are based on
nonconfidential Survey data. The same royalty rates are applied to all platforms with the same
ownership (e.g., all Unocal platforms have an 11.1 percent royalty on oil production). Royalty
rates are presented in Table 5-3 for each of the platforms.
The rates applied to the Major Pass dischargers vary according to information provided
by the individual operators. Federal corporate tax rates vary between 34 and 35 percent.
Projects in Louisiana waters are also subject to a state corporate tax of 8 percent and state
severance taxes, which differ from operator to operator. Royalties are based on lease ownership.
Using the model, .EPA adjusts earnings to taxable income according to tax regulations
that permit expensing and depreciation of certain capital expenditures and depletion of wasting
assets. Depreciation for capital expenditures is based on MACRS (details are provided in
Appendix A). Depletion of oil and gas reserves can be calculated on either a cost or a
percentage basis, depending on whether the project is owned by a major (integrated) or
independent oil company. Independent oil companies have the option of calculating depletion
using either method. Percentage depletion, which allows a company to write off 15 percent of
taxable revenues up to and including 1,000 bpd oil or 6,000 Mcf gas per day per lease of
production, generally yields higher values. EPA therefore assumes that independent Major Pass
producers use percentage depletion. Major oil companies must use the cost basis for depletion.
This method of calculating depletion permits deduction of the leasehold cost over the production
24As discussed in Appendix A, operators with taxable income between $100,000 and $1 millon
annually are subject to the 34 percent federal tax rate. For simplicity in the proposal, EPA
assumed all projects were subject to a 34 percent tax rate. EPA received no comments regarding
its use of the 34 percent tax rate in analysis of Cook Inlet operators for either the Offshore
Guidelines (Offshore EIA) or the proposed Coastal Guidelines (PEIA). Some of the Major Pass
operators, however, specifically indicated that they are subject to the 35 percent tax rate
applicable for corporations with taxable income greater than $1 million annually. In analysis of
these operators, the 35 percent tax rate is used. The use of 35 percent rather than 34 percent
makes very little difference in the analysis, except that it very slightly increases baseline NPV and
decreases baseline federal tax receipts.
5-19
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lifetime of the project according to the proportion of total reserves sold in each given year.
Because EPA assumes all prior investments to be sunk costs, and thus not a part of this analysis,
no basis exists for estimating depletion for the major oil companies operating in Cook Inlet and
the Major Pass regions. This omission leads to a slight underestimate of the profitability of these
projects in the baseline analysis (which is offset by the exclusion of sunk costs in estimating
profitability). Omitting depletion has little to no effect on the incremental impact analysis. The
two methods of depletion are discussed further in Appendix A.
5.13.5 Prices
The wellhead prices of oil and gas in Cook Inlet are presented in Table 5-1. The value
for oil, $15.91 per barrel in 1995 dollars, is inflated from data provided by the Marathon/Unocal
presentation. Average rates from the Section 308 Survey database are comparable. The
wellhead price of gas is scaled to 10.8 percent of the price of oil (Offshore EIA), and the
resultant figure of $1.72/Mcf is also comparable to data from the Section 308 Survey (Section
308 Survey). Wellhead prices for the Major Pass dischargers are based on individual operator
data.
5.1.6 Calculation Procedures
5.1.6.1 Production Logic
To determine total production at a platform or facility, EPA begins with estimates of
1997 production, as discussed above, and assumes that peak production rates occur in the first
year of production and are maintained for the first year only. The subsequent pattern of decline
in a well's productivity varies greatly due to many factors. Production decline is modeled as an
exponential function (i.e., a constant percentage of the remaining reserves produced in any given
year). In Cook Inlet, EPA assumes that oil and gas production declines by 8 percent annually, a
value typical for that region (Marathon/Unocal presentation). The Agency uses project-specific
decline rates provided by the individual operators to model the Major Pass dischargers.
5-21
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EPA also includes increases in production originating with recompleted or new
production wells in its analysis. In Cook Inlet, when a company drills new wells or recompletes
existing wells, production increases of 500 barrels of oil per day (Marathon/Unocal presentation)
or 15,000 Mcf of gas per day25 per well are added to existing production figures. The
corresponding production increases for the Major Pass dischargers vary by operator. Some
Major Pass operators reported specific drilling plans in conjunction with per-well expected
increases, while others reported drilling expenditures on an aggregate level in conjunction with
production increases based on likely drilling success rates.
5.2 PRODUCTION LOSS MODELING RESULTS2"
This section presents the results of the production loss modeling for Cook Inlet platforms
and Major Pass facilities potentially affected by the proposed guidelines (i.e., operations not
covered by the Region 6 permit). EPA calculates summary statistics, for both baseline and
postcompliance scenarios, broken down by region. Postcompliance results include, by option,
numbers of first-year shut-ins of wells, platforms, or facilities; production losses; years of
production lost; net present dollar value of production losses; and state and federal revenues lost.
Impacts on each of the groups are described first separately and then in aggregate.
"Alaska Oil and Gas Association (AOGA). 1991. Produced Water Issues. Handout
presented to U.S. EPA. October 29.
MAU results shown in the text and tables in Section 5.2 are based on Cook Inlet and Major
Pass Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
5-22
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5.2.1 Produced Water/Treatment, Workover, and Completion Wastes
,27
5.2.1.1 Cooklntef*
Baseline (Current Practice)
Currently there are thirteen platforms operating in Cook Inlet. EPA estimates that these
thirteen platforms will produce 311.3 million discounted BOB (501.1 million total BOE) over
their combined lifetime without any further regulatory action. All thirteen are expected to
operate for at least one year; the Agency's analysis shows none closing in the baseline. EPA
further estimates that, in combination, the Cook Inlet platforms will operate for a total of 152
platform-years, or 12.7 years on average. The NPV of this combined lifetime production (i.e.,
the present value of projected revenues minus cash outflows [operating costs, capital
expenditures, and taxes] associated with Cook Inlet projects) is $838.6 million. The present value
of severance taxes collected is estimated at $146.7 million, the present value of royalties to the
state is $434.9 million, and the present value of federal income taxes collected is $446.6 million.
Table 5-4 summarizes baseline and postcompliance results.
Options #1 and #2 (Gas Flotation)
Both Options #1 and #2 require Cook Inlet platforms to meet offshore limits (i.e.,
improved gas flotation). Although the Agency does not expect any platforms to shut in in the
first year, EPA analysis of production in Cook Inlet suggests that use of gas flotation would
result in total lifetime production dropping by 1.1 million discounted BOE to 310.2 million
discounted BOE (equal to a loss of 2.4 million total BOE). This loss amounts to approximately
27TWC wastes are discussed in conjunction with produced water because operators generally
combine these wastes. The guidelines for TWC are therefore the same as those for produced
water, and there are no incremental costs associated with TWC disposal (beyond the costs for
produced water) in Cook Inlet. There are, however, small incremental costs associated with
TWC disposal for NSPS and BAT in the Gulf region.
results shown in the text and tables in Section 5.2.1.1 are based on Cook Inlet
Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
5-23
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TABLE 5-4
IMPACTS OF PRODUCED WATER OPTIONS
ON COOK INLET PLATFORMS (1995 S)
Type of Impact
Projected lifetime discounted production (PVBOE)
Chinge in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current Practice
311,318,836
—
_
Gas Flotation
Options #1 and #2
310,246,742
1,072,094
0.3%
Zero Discharge
Option #3
301,852,447
9,466,390
3.0%
* -.V.
. :, -r% f ' $
Total projected lifetime production (BOE)
Change in total projected lifetime production (BOE)
Percentage change in discounted baseline production
501,066,400
_
_
498,662,817
2,403,582
0.5%
481,663,447
19,402,953
3.9%
< f -> > ~ >
.v :> > '
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
$838,618
—
_
$826,735
$11,883
1.4%
$683,863
$154,755
18.5%
•• * v x ...
* <° j * !• ^
Number of platforms ceasing production in first year (postcompliance)
Total number of production years (1997 on)
Average production years per platform (all platforms)
Average production years per platform (nonclosing platforms)
Total production years lost among closing platforms
Total production years lost among nonclosing platforms
0
152
12.7
12.7
—
—
0
148
12.3
12.3
0
4
1
125
10.4
11.4
6
21
; i »» J.JMIJ > <_ > , > ^ , ,, #$:&
Present value of severance and state income taxes collected ($000)
Change in present value of severance and state income taxes ($000)
Percentage change in severance and state income taxes
$146,730
—
—
$146,676
$54
0.0%
$146,256
$473
0.3%
> ^ ~ * >&£ < > > i> :» ^
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes ($000)
Percentage change in federal income taxes
$446,615
_
—
$441,644
$4,971
1.1%
$378,796
$67,820
15.2%
.' j ^tJ-<< f^^v^^^^rt-
: v f> -s ;„
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$434,946
_
—
$432,955
$1,991
0.5%
$417,383
$17,563
4.0%
Source: Cook Inlet Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
5-24
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0.3 percent of lifetime discounted production in Cook Inlet. The average number of production
years per platform also drops from 12.7 to 12.3, indicating that the installation and operation of
improved gas flotation equipment would result in platforms shutting in an average of 5 months
earlier than they would have without the regulation.
EPA further estimates that the NPV of the Cook Inlet projects would drop $11.9 million
to $826.7 million, a 1.4 percent loss of baseline net present value among all Cook Inlet projects.
This reflects both lost production and capital and O&M costs of compliance. The total present
value of lifetime federal income taxes lost under this option is estimated to be $5.0 million, or 1.1.
percent of the baseline federal taxes estimated to be collected over the life of the platforms. The
present value of severance taxes lost amounts to $54,000 over the life of the platforms. Royalties
lost to the state total $2.0 million in present value terms over the life of the platform, or 0.5
percent of the baseline royalties collected (see Table 5-4).
Option #3 (Zero Discharge)
Option #3 requires that the Cook Inlet platforms meet zero-discharge requirements with
respect to produced water. Under a zero-discharge requirement, EPA analysis indicates that one
platform would shut in (cease production) during the first year, and Cook Inlet lifetime
production would drop by 9.4 million discounted BOE (19.4 million total BOE), or 3.0 percent
of baseline production. Project NPV is estimated to drop by $154.8 million, which is 18.5
percent of baseline NPV. The average productive life of the platforms among those remaining
active is 11.4 years, or a loss of 0.7 years per platform.
In addition, the EPA estimates that, under this option, a total of $67.8 million (present
value) would be lost in federal income taxes over the lifetime of the Cook Inlet platforms, or
15.2 percent of projected income tax receipts in the baseline. The present value of severance
taxes lost is estimated to be $473,000 over the lifetime of the Cook Inlet platforms, or 0.3
percent of total baseline severance taxes estimated to be collected. Loss in royalty payments to
the state (in present value terms) would total $17.6 million over the life of the platforms, or 4.0
percent of baseline royalties collected (see Table 5-4).
5-25
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5.2.1.2 Ma/or Pass Dischargers29
Baseline (Current Practice)
Table 5-5 summarizes the baseline and postcompliance scenarios for the Major Pass
dischargers. Currently, there are eight facilities associated with oil and gas production and
offshore produced water discharge in the Major Pass region. None of these facilities shut in at
baseline. EPA estimates that, in combination, the Major Pass dischargers will produce 434.7
million lifetime discounted BOE (599.9 million total BOE). The present value of these Major
Pass projects in baseline is $1,459.6 million. The productive lifetimes of the Major Pass
dischargers total 82 years, an average of 10.3 years per facility. In addition, the present value of
federal income tax collected over the economic lifetime of the operations is estimated at $752.8
million, the present value of severance and state income tax collected is $399.4 million, and the
present value of total royalties paid to states and other leaseholders is $815.9 million.
Option #1 (Gas Flotation)
Under Option #1, the Major Pass dischargers would be required to meet limits
equivalent to those for offshore operations to discharge offshore water into a major pass of the
Mississippi River. EPA analysis indicates that this requirement would not result in any shut-ins.
In addition, the Agency projects that use of gas flotation would not result in losses in either
lifetime discounted (or total, non-discounted) BOE production or the total number of production
years (see Table 5-5).
The gas flotation option is estimated to result in a loss of $2.5 million in the NPV of the
discharging Major Pass projects (a 0.2 percent drop from baseline to $1,457.0 million). The loss
in present value federal income taxes collected associated with gas flotation is $832,000, or 0.1
percent of baseline. Present value state tax losses amount to $168,000, or 0.04 percent of total
baseline state severance and income taxes. Neither severance taxes nor royalties are lost because
2'A11 results shown in the text and tables in Section 5.2.1.2 are based on Major Pass
Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
5-26
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TABLE 5-5
IMPACTS OF PRODUCED WATER OPTIONS
ON MAJOR PASS FACILITIES (1995 $)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
*
Total projected lifetime production (BOE)
Change in total projected lifetime production (BOE)
Percentage change in discounted baseline production
-. V. « -. V
Present value of project net worth (NPV) (SOOO)
Change in NPV ($000)
Percentage change in NPV
Number of facilities ceasing production in first year (postcompliance)
Total number of production years ( 1997 on)
Average production years per facility (all facilities)
Average production years per facility (nonclosing facilities)
Total production years lost among closing facilities
Total production years lost among nonclosing facilities
* **'- ^
Present value of severance and state income taxes collected (SOOO)
Change in present value of severance and state income taxes (SOOO)
Percentage change in severance and state income taxes
•s
Present value of federal income taxes collected (SOOO)
Change in present value of federal income taxes (SOOO)
Percentage change in federal income taxes
- -\ v ss ^
Present value of royalties collected (SOOO)
Change in present value of royalties ($000)
Percentage change in royalties
Baseline
Current Practice
434,713,377
—
—
•*•
599,860,713
—
—
_ -
$1,459,603
—
_
0
82
10.3
10.3
—
—
S *~* ,*i
$399,427
—
—
> ^ * >
$752,818
—
—
u •. ' <*•. •.•.•.•3.-. •. jf^ ^ ^
> v \ % •• -•
$815,892
_
—
Gas Flotation
Option #1
434,713,377
0
0.0%
599,860,713
0
0.0%
'''••'-
$1,457,042
$2,560
0.2%
0
82
10.3
10.3
0
0
$399,259
$168
0.0%
„
$751,987
$832
0.1%
"}„„
$815,892
$0
0.0%
Zero Discharge
Options #2 and #3
432,592,658
2,120,719
0.5%
^
596,461,487
3,399,226
0.6%
$1,407,790
$51,812
3.5%
* >~-± f "•
t ' JviO"
0
79
9.9
9.9
0
3
' - "-" r
$393,363
$6,063
1.5%
V /
> ;• ^ i
$737,530
$15,289
2.0%
r,-' ' * "
$809,434
$6,458
0.8%
Source: Major Pass Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
5-27
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these are calculated based on BOE produced and Option #1 is not associated with losses in
production (see Table 5-5).
Options #2 and #3 (Zero Discharge)
Under Options #2 and #3, the Major Pass dischargers are required to convert to zero
discharge of produced water. Although no facilities would shut in as a result of this requirement,
EPA estimates that total lifetime production from the Major Pass dischargers would drop 2.1
million discounted BOE to 432.6 million discounted BOE (a loss of 3.4 million total, non-
discounted BOE). The NPV of projects in this group is estimated to decrease by $51.8 million
to $1,407.8 million (3.5 percent).
In addition, EPA analysis shows that the total number of production years for the Major
Pass dischargers would drop by 3 years to 79 years (an average of 10.3 production years dropping
to 9.9 production years per facility) under zero discharge. The present value of federal income
taxes lost is $15.3 million, or 2.0 percent of the baseline federal taxes estimated to be collected
over the lifetime of the facilities. Present value state and severance taxes collected is reduced by
$6.1 million, or 1.5 percent of baseline, and royalties lost are estimated at $6.5 million (in present
value terms), or 0.8 percent of baseline.
5.2.2 Drilling Wastes30
Option #1 (Current Practice)
Option #1 requires Cook Inlet operators to meet requirements equivalent to those in the
Oil and Gas Industry Offshore Guidelines and all other operators to practice zero discharge.
Current drilling waste practices meet these requirements; Cook Inlet platform discharges are
results shown in the text and tables in Section 5.2.2 are based on Cook Inlet Dischargers
Production Loss Model Runs (CBI data; in rulemaking record).
5-28
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within offshore discharge limitations, and all other areas of the country practice zero discharge.
As such, Option #1 is a no-cost option. Baseline numbers for Cook Inlet, as indicated in Table
5-6, are the same as those in Table 5-4.
Option #2 (Zero Discharge-Landfill)
Under Option #2, coastal oil and gas operators are required to achieve zero discharge of
drilling waste. EPA assumes the Cook Inlet operators do this by sending their drilling waste to a
landfill. The Agency investigated a less expensive option but did not model it because of
concerns that this alternative was not technically feasible. Table 5-6 summarizes the impacts of
this option on Cook Inlet, the only area of the United States (outside of offshore regions) not
currently practicing zero discharge of drilling wastes. Under this option, no platforms shut in
during the first year, and there are no losses in total lifetime production. Furthermore, since
production levels do not change between the baseline and postcompliance scenarios, there are no
losses in royalties or severance taxes collected.
Option #2 is associated with a $32.5 million decrease in the NPV of Cook Inlet projects,
or a 3.9% loss compared to baseline NPV. The present value of federal income taxes collected
drops $16.4 million, as well (3.7% of baseline federal taxes collected).
5.2.3 Combined Impacts (Cook Inlet and Major Pass)31
EPA examined the impacts of each produced water and drilling waste option on the
Cook Inlet platforms and the Major Pass discharging facilities combined.
As Table 5-7 shows, total produced water impacts for the Cook Inlet and Major Pass
operators tend to increase with option number. In particular, Option #3, which requires both
groups to go to zero discharge, shows a large incremental change in impacts from Option #2,
"Unless otherwise noted, results shown in the text and tables in Section 5.2.3 are based on
Cook Inlet Dischargers Production Loss Model Runs and Major Pass Dischargers Production
Loss Model Runs (CBI data; in rulemaking record).
5-29
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TABLE 5-6
IMPACTS OF DRILLING WASTE OPTIONS
ON COOK INLET PLATFORMS (1995 S)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Option #1
311,318,836
—
—
Landfill
Option #2
311,318,836
0
O.O^o
> r jj %lK;ra I< rf-> ,. , y /f> 4% } '' t > ! '
< $ ^VAJJJJJ
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOB)
Percentage change in discounted baseline production
501,066,400
—
—
501,066,400
0
0.0%
' ^ f1 % vj 1 ! J ! > 4 ,
* ' • S > : ' y ^
A5 .. ... f . . .
Present value of project net worth (NPV) ($000)
Change in NPV ($000)
Percentage change in NPV
$838,618
—
—
$806,118
$32,500
3.9%
--: • • • •••!;. :vrn::t":'[fUT%.u:;s;:""^:"n;";":;n::"U"*::>:::v^"::::":>::~;^^
''.':.•'•.'''.'. ':'.';,>'.';'' ^::!'!;;l'!;j!!l!l"ii;l!HHI!;-i!:L'!l!!H:H!i::!l:!!ti"H:;^
Number of platforms ceasing production in first year (postcompliance)
Total number of production years (1997 on)
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
152
12.7
12.7
—
—
0
152
12.7
12.7
0
0
' >' ~ )•- >' '' ^M1
Present value of severance and state income taxes collected ($000)
Change in present value of severance and state income taxes ($000)
Percentage change in severance and state income taxes
$146,730
—
—
$146,730
$0
0.0%
*• * < i s
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes ($000)
Percentage change in federal income taxes
$446,615
—
—
$430,225
$16,391
3.7%
> "*•
Present value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$434,946
—
....
$434,946
$0
0.0%
Source: Cook Inlet Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
5-30
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I
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5-31
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which requires zero discharge from the Major Pass facilities but allows continued discharge from
the Cook Inlet platforms provided that gas flotation limits are met. Total losses from Option #3
are higher because, as discussed in Section 5.2.1, zero-discharge requirements in Cook Inlet are
associated with higher costs and the closure of one platform.
Regulatory impacts increase further when the produced water options are analyzed in
conjunction with zero discharge of drilling wastes. In Cook Inlet, the use of gas flotation for
produced water (Option #2) in combination with zero discharge of drilling wastes (Option #2) is
associated with a slight drop in NPV and federal and state taxes collected, although no
production is lost. If Option #3 for produced water is combined with Option #2 for drilling
wastes (the zero-discharge/zero-discharge scenario), EPA analysis indicates that four of the
thirteen platforms in Cook Inlet would shut in. Losses in production, NPV, severance taxes and
royalties, and state and federal income taxes collected all are incurred under this scenario.
TWC wastes, as noted above, are discussed in this FEIA in conjunction with produced
water because operators generally combine these wastes. Hence impacts associated with the
various produced water options tend to encompass the impacts of the TWC options. However,
in certain operations not examined above, TWC waste disposal costs may apply. Costs of
disposing of TWC under a zero-discharge option are $0.6 million annually (see Chapter Four of
this FEIA) for all Gulf of Mexico wells estimated to discharge TWC (a minimum of 334 wells;
see EPA's Development Document), or an average of $1,796 per well. A typical Gulf of Mexico
well produces an average of 36 barrels of oil per day according to the Section 308 Survey
Questionnaires. At $19.75 per barrel (the Section 308 Survey Questionnaire average inflated to
1995 dollars), EPA estimates that total gross production revenue at a typical well is $260,000 per
year. Thus, under a zero discharge option, TWC disposal costs are estimated to be 0.7 percent
of annual gross production revenues at a typical Gulf of Mexico well. These TWC costs add
negligibly to the impacts discussed earlier.
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5.2.3.1 Combined Impacts — Selected Options*2
EPA's selected regulatory options are Produced Water Option #2 and Drilling Waste
Option #1. Table 5-8 shows the total maximum impacts from these selected options. Since
Drilling Waste Option #1 is a no-cost option, the impacts in Table 5-8 are the same as those
indicated in Tables 5-7. Disposal of TWC wastes involves negligible additional impacts.
Under Option #2/Option #1, the Cook Inlet platforms and Major Pass dischargers
experience no incremental shut-ins. EPA estimates total maximum impacts as follows:
production losses of 3.2 million discounted BOE (5.8 million total BOE), which amounts to 0.4
percent of projected discounted baseline production in Cook Inlet and the Major Passes, or 0.2
percent of projected discounted baseline production from all coastal oil and gas operations
outside of California and North Slope, Alaska; and total present value losses of $99.0 million (1.9
percent of the total NPV, taxes, and royalties in Cook Inlet and the Major Passes, or 0.7 percent
of the total NPV, taxes, and royalties associated with total coastal production outside of
California and North Slope). The latter figure represents losses of $63.7 million in project NPV,
$6.1 million in present value severance and state income taxes, $20.3 million in present value
federal taxes, and $8.4 million in present value royalties (see Table 5-8). Note that production
losses would have additional effects on other parts of the economy. These effects are discussed
in Chapter Seven.
32Unless otherwise noted, results shown in the text and tables in Section 5.2.3.1 are based on
Cook Inlet Dischargers Production Loss Model Runs and Major Pass Dischargers Production
Loss Model Runs (CBI data; in rulemaking record).
5-33
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5-34
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CHAPTER SEX
FIRM-LEVEL ECONOMIC IMPACTS ON THE
COASTAL OIL AND GAS INDUSTRY
The firm-level analysis evaluates the effects of regulatory compliance on firms owning one
or more affected coastal oil and gas operations. It also serves to identify impacts not captured in
the production loss analysis. For example, some companies might be too weak financially to
undertake the investment in the required effluent control, even though the investment might
seem financially feasible at the facility or platform level. The Section 308 Survey and EPA's later
data collection effort among the Major Pass operators asked respondents for financial data from
the lowest level of organization at which assets, liabilities, and taxes are clearly identifiable.
Thus, the financial data should reflect the most financially sensitive level of organization (e.g., a
division of a major company rather than all corporate holdings, if the division acts as a profit
center).
EPA's firm-level analysis consists of three steps. In the first step, the Agency conducts a
baseline analysis to determine which firms might fail even if the Coastal Guidelines are not
promulgated. In the second step, EPA examines the firms' equity and working capital to
determine which operators could not comfortably cover annual compliance costs (i.e., where
annual compliance costs both exceed 5 percent of working capital and 5 percent of equity). EPA
then examines, in depth, the finances of operators for whom annual compliance costs exceed 5
percent of working capital and 5 percent equity to determine whether any potential major
impacts are likely to materialize.
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6.1 ANALYTICAL METHODOLOGY
6.1.1 Baseline Methodology
EPA uses a cash-flow analysis to determine whether any firms are likely to be considered
baseline failures (i.e., whether any firms are highly likely to fail regardless of the regulation under
consideration because their financial health is so precarious). For the Major Pass and Cook Inlet
operators, EPA considers positive after-tax cash flow or net income (if cash flow information was
not available) as reported by the operators (1995 data)1 or in OGJ (OGJ 200)2 to be an
indicator of adequate baseline financial health.
6.1.2 Postcompliance Analysis
In the postcompliance analysis, EPA identifies firms at which impacts from compliance
with the regulation are likely to be significant. Equity and working capital are common measures
of a firm's ability to afford new projects, acquisitions, etc. Equity is measured as a firm's total
assets minus its total liabilities (i.e., its net worth). Working capital is a measure of a firm's
liquidity and is measured as current assets (typically cash or near-cash assets that can easily be
liquidated) minus current liabilities, which are debts or other obligations due within one year. In
other words, working capital describes available cash. If the annual cost of complying with a zero
discharge or other requirement contributes to a small percentage change in equity and working
capital at a firm, EPA considers it likely that impacts at the firm will not be substantial (i.e., the
firm is not likely to fail as a result of compliance).3
jor Pass Dischargers Data Submittals (CBI data; in rulemaking record).
2HOGJ 200," Oil and Gas Journal (OGJ), Vol. 94, No. 36, September 2, 1996, pp. 56-74.
3Working capital is not considered an issue for the major integrated oil companies.
Occasionally these firms have low or negative working capital, but this appears to have no ill
effects on their financial health. Thus, change in equity is the measure used for majors. Since
working capital is a much more critical source of financing at small independents, EPA is more
concerned with changes in working capital at small firms.
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EPA identifies firms needing further analysis on the basis of whether the firm would
experience a greater than 5 percent change in equity and working capital. In this more detailed
analysis (assuming all other things equal), EPA makes adjustments to the firm's cashflow
statement, including baseline operating costs, depreciation, and interest using the conservative
assumption that the firm will choose to finance pollution control costs out of debt, not equity.
EPA adds pollution control operating costs to baseline operating costs, the depreciation
allowance on the incremental capital expenditure (straight-line assumed for simplicity) to
baseline deprecation, and the associated first-year interest payment to baseline interest using the
affected operator's reported discount rate. EPA then determines whether after-tax cash flow is
still positive. EPA also estimates the magnitude of first-year the declines in after-tax cash flow
compared to baseline, and the declines over 10 years in present value terms (assuming all other
revenues and costs remain constant both in the baseline and the postcompliance scenarios). As a
complement to the cash flow analysis, EPA investigates each firm's financial health to determine
if the firm appears capable of raising the capital needed to purchase and install the necessary
pollution control equipment. Firm failure is not considered likely if capital will be available to
purchase and install equipment (e.g., if the firm has an available credit line that can easily
accommodate the additional capital requirements).
6.2
SOURCES OF DATA
EPA obtained 1995 data for Cook Inlet operators from financial data published in OGJ
(OGJ 200) (see Chapter Three). For the Major Pass analyses, EPA contacted potentially
affected operators directly for information and supplemented this information with annual
and/or quarterly reports, where available. All but one Major Pass operator provided EPA with
the necessary financial data. The one firm that did not provide data stated that compliance costs
would have no material effect on its financial condition.
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63 RESULTS OF FIRM-LEVEL ANALYSIS
As discussed in Section 6.1, the results of three levels of analysis are presented here.
Section 6.3.1 presents the results of the baseline analysis, and Section 6.3.2 presents the results of
the postcompliance analysis, including the screening analysis and the detailed analysis. Results
are not discussed in detail to protect data confidentiality for the few firms that provided
confidential data.
63.1 Baseline Analysis
Six Major Pass firms and three Cook Inlet firms are potentially affected by the Coastal
Guidelines. Given cash flow results based on OGJ (OGJ 200) and data collected from the Major
Pass operators (including most recent quarterly reports), EPA anticipates no baseline failures
among either the Major Pass or Cook Inlet operators (i.e., all firms reporting financial
information show positive cash flow). More detailed information is not provided here because of
confidentiality issues.
633, Postcompliance Analysis
EPA anticipates that compliance with regulatory options would cause no firm failures
among Major Pass or Cook Inlet firms. Annual pollution control costs for one or more of the
firms that provided EPA with financial data exceed the 5 percent benchmark for equity and
working capital (independents only) under Options #2 and #3 for produced water/TWC (i.e.,
these firms' annual compliance costs are greater than 5 percent of their equity and 5 percent of
their working capital), but no firms fail a cash flow analysis under these options. All have only
small declines in first-year and 10-year present value after-tax cash flow.4 Furthermore, after
more in-depth analysis of credit line availability and capital investment plans, EPA considers all
4Cash Flow Analysis of Major Pass Dischargers (CBI data; in rulemaking record).
Percentage declines are not reported to protect confidential business information.
6-4
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firms likely to be able to raise the necessary capital to meet zero discharge requirements (note
that operating costs are not a major issue, since these operations can absorb the increased costs
of production with little to no effect, as shown in Chapter Five). Thus EPA expects no firm
failures as a result of the Coastal Guidelines (see Chapter Ten for an analysis of firm impacts
under an alternative baseline assumption).
Note that a finding of no firm failure does not mean that there will be no impacts on
these firms. Rather, it means that EPA does not expect the impacts to be so severe as to cause
the firms in question to fail.
6-5
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CHAPTER SEVEN
REGIONAL AND NATIONAL EMPLOYMENT
IMPACTS AND TOTAL OUTPUT LOSSES
This chapter of the FEIA assesses the employment impacts of the Coastal Guidelines on
both regional and national levels. It also discusses output losses to the national economy
induced by revenue losses in the oil and gas industry. Only impacts from BAT options are
discussed here.1 Chapter Nine discusses impacts from NSPS options, and Chapter Ten discusses
impacts under an alternative baseline.
The employment analysis is divided into national- and regional-level analyses. The
national-level analysis addresses the net gain or loss of employment resulting from the Coastal
Guidelines throughout the United States, whereas the regional-level analysis addresses the effects
of employment dislocations (layoffs) in the regional economy where the coastal industry is
located. Employment losses and gains will occur throughout the economy in response to a
reallocation of expenditures caused by implementation of the Coastal Guidelines. Pollution
control expenditures divert investment from oil and gas production, which leads to direct oil and
gas employment losses, as well as oil and gas production losses. These losses are offset by gains
in employment in the manufacturing firms that produce the pollution control equipment and
gains in employment associated with installing and operating the equipment. Gains and losses
occur within the oil and gas industry as a result of investment reallocation.
Employment gains may or may not occur in the same region as employment losses but,
on a national level, gains will more or less offset losses, with the exception of "dead weight
losses"2 or losses in production efficiency. To compute national-level employment changes,
output effects must be considered. Typically, output is measured as revenues. Oil and gas
lrThere are no costs associated with BCT, PSES, or PSNS, as explained in Chapter Four of
this FEIA.
economic productivity that will not be replaced (i.e., that is not a transfer payment to
another economic sector).
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production losses become revenue losses to the oil and gas industry, which affect the revenues of
input industries (industries that supply goods and services to the oil and gas industry), which in
turn eventually result in a reduction of household consumption by workers in these industries,
decreasing demand for products at the national level. Impacts on the oil and gas industry are
known as direct effects, impacts that continue to resonate through the economy are known as
indirect effects (effects on input industries), and effects on consumer demand are known as
induced effects. These effects are tracked both nationally and regionally in massive "input-
output" (I-O) tables prepared by the U.S. Department of Commerce's Bureau of Economic
Analysis (BEA). For every dollar spent in a "spending industry," these tables identify the portion
spent in contributing or vendor industries.
For example, as a result of this rule, an oil and gas firm might purchase equipment to
meet standards equivalent to improved gas flotation. One piece of this equipment could be a
tank to hold produced water. To make the tanks, the manufacturer would purchase stainless
steel. The steel manufacturer would purchase iron ore, coke, energy sources,, and other
commodities, etc. Thus a portion of a dollar spent by the oil and gas industry becomes a smaller
portion of a dollar spent by the tank manufacturer, and a smaller portion of a dollar spent by the
steel manufacturer, and so on. These iterations are captured in the BEA's I-O tables and
summarized as regional and national multipliers for output (revenues). BEA. also has
determined average wages and the proportion of output in each industry that goes to employee
earnings and, as a result, the number of employees or full-time equivalents (FTEs)3 associated
with each $1 million change in output. I-O analysis provides a straightforward framework as long
as the direct effects to the industry are small and certain limiting assumptions about technology
are valid (e.g., constant returns to scale, fixed input ratios).
Four types of changes may occur in employment and output, some of which are offset by
gains and some of which are not (dead weight losses). These four types of changes, discussed in
detail in the sections to follow, include:
3One FTE = 2,080 labor hours = 1 person-year of employment.
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• Type 1 - Compliance Costs: Direct oil and gas employment losses due to
expenditures diverted to compliance.
• Type 2 - Production Losses: Production losses at oil and gas operations that install
and operate pollution control equipment.
• Type 3 - First-year Shut-ins: Employment and output losses at operations that shut
in in the first year and do not install pollution control equipment.
• Type 4 - Delayed Investment: Employment and output losses resulting from
delayed investment (i.e., where the need for pollution control expenditures delays
investment in oil and gas exploration and development).
The analysis of these employment and output losses (as well as related impacts) is divided into
two parts. Section 7.1 analyzes the national-level impacts of the Coastal Guidelines on both
labor and output. Section 7.2 examines the regional impacts associated with employment losses
and presents the methodology and results of the employment loss and community-level impact
analysis. Note that the net change in employment at the national level includes the regional-level
losses (i.e., national and regional losses are not additive).
7.1 NATIONAL-LEVEL OUTPUT AND EMPLOYMENT IMPACTS
7.1.1 Introduction
To comply with the Coastal Guidelines, firms will need to install and operate pollution
control systems. The manufacture, installation, and operation of these systems will require labor
resources. The labor resources needed to comply with the Coastal Guidelines, however, are very
similar to the labor resources that would have been needed if the affected coastal firms had been
able to invest in oil and gas production. Specifically, the inputs required for the manufacture,
installation, and operation of an injection well are similar to those required for a production well.
For example, both an injection well and a production well require tanks, tubular goods, cement,
etc. Both require drilling and installation. Both require energy, chemicals, and labor for
operation. Therefore, the dollars spent on drilling and operating an injection well would add
roughly the same number of employees to the national economy as the dollars spent on drilling
and operating a production well. Thus, EPA does not anticipate substantial changes in
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employment (gains or losses) associated with direct expenditures on pollution control equipment
(Type 1 loss as described above) to comply with the Coastal Guidelines.
Despite this balance between losses and gains in employment associated with pollution
control expenditures, there are differences in the national-level economy between baseline and
postcompliance scenarios. The major differences between baseline and postcompliance labor
effects are associated with production losses (described in Chapter Five), which generate Type 2
and Type 3 employment and output losses (production losses from operations that do or do not
install and operate pollution control equipment, respectively). Type 2 losses (losses to operations
that install and operate pollution control equipment) are dead weight losses (losses in
productivity). The losses associated with first-year shut-ins (Type 3 losses) are offset by gains
when the money that would have been spent on oil and gas production is reallocated to other
productive investments in the general economy. EPA therefore does not count any employment
losses from first-year shut-ins in the national-level analysis.4
Additionally, the money coastal firms spend on pollution control equipment can be
assumed to have been spent on further exploration and development in the absence of the
Coastal Guidelines. Although this investment in exploration and development will most likely be
delayed rather than never undertaken (since if it is a good investment, it will remain a good
investment), some revenue is lost as a result of the investment delay. These output effects will
result in net losses in employment (Type 4 losses), which are also dead weight losses.
The following sections present the methodology for determining the impacts associated
with the two types of dead weight losses (Types 2 and 4). Section 7.1.1 discusses the
methodology for estimating national-level output losses and employment impacts resulting from
output losses in the oil and gas industry. Section 7.1.2 presents the results of this analysis.
4However, these losses are considered in the regional analysis (see Section 7.2).
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7.1.2 Methodology for Estimating National-Level Output and Employment Impacts
EPA estimates two categories of national-level impacts associated with the Coastal
Guidelines: impacts on output in the economy as a whole (in dollars) and impacts on national
employment (in FTEs). Both impacts are calculated on the basis of the losses in production and
revenue in the oil and gas industry discussed in Chapter Five (Type 2 losses), combined with
losses due to delayed investment in further production (Type 4 losses). Losses in production
cause losses in oil and gas revenues (output); these output losses, in turn, have effects
throughout the economy. For the oil and gas industry, BEA has estimated a national-level
multiplier of 1.9420 (RIMS II National Multipliers).5 This multiplier represents the total dollar
change in national output for all industries for each dollar change in oil and gas. Using the BEA
multiplier, EPA adjusts oil and gas revenue losses (based on production losses as presented in
Chapter Five) to estimate impacts throughout the national economy:
Oil and Gas Industry Revenue Losses (Output) x BEA Multiplier = National Output Losses.
In calculating national-level employment impacts, the Agency uses a similar approach.
BEA (RIMS II National Multipliers) has estimated a final-demand multiplier for national-level
employment based on oil and gas industry output. This number, 13.0, represents the total
change in the number of jobs in all industries nationally for each $1 million change in output
delivered to final demand by the oil and gas industry. To determine the results of output losses
associated with the production losses calculated in Chapter Five, EPA subtracts losses from first-
year shut-ins and annualizes the remaining production losses (in PVBOE) to estimate an average
Type 2 production loss per year.6 Average annual production loss is then converted to an
average annual output or revenue loss by multiplying by the price of oil. Since output is
equivalent to revenue at the point of final demand, the market value (not the wellhead price) of
5Bureau of Economic Analysis (BEA). U.S. Department of Commerce, 1992. Table A-
2.4—Total Multipliers, by Industry Aggregation, for Output, Earnings, and Employment.
Regional Input-Output Modeling System (RIMs II), Regional Analysis Division, Washington,
D.C.
6Present value BOE, rather than total BOE, is used to calculate annualized production losses
since EPA uses a constant, real-dollar assumption for the price of oil.
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oil is the relevant price to compute the output loss associated with the production loss. EPA has
selected $22/bbl as a reasonable market price for oil.7 To calculate the output loss to the
industry, EPA multiplies the market price of $22 per bbl by the average annual production loss.
This output loss is then divided by $1 million (since employment losses are per $1 million dollars
of output loss) and multiplied by BEA's employment multiplier.
To determine the losses associated with delayed production (Type 4), EPA assumes that
the affected firms will lose revenues because funds equal to the pre-tax compliance costs are
diverted from productive to nonproductive investment. EPA assumes that this investment is not
permanently lost to the industry as a result of the Coastal Guidelines, but instead is delayed for 5
years.8 While the investment will be undertaken as long as it is profitable, raising new capital to
replace diverted exploration and development capital takes time. The investment delay will
result in a present value loss of revenues relative to the baseline.
To quantify the impacts of the investment delay, EPA assumes that the investment would
have been made in Year 1 in the baseline and would have provided a pre-tax return of 15
percent9 of the compliance cost. This number (in dollars), which represents the baseline present
value of the return from a productive investment, is then discounted for 5 years at 7 percent to
represent a 5-year investment delay. The present value of the investment delay is subtracted
from the baseline present value of the investment and the difference is annualized. This estimate
will overstate impacts if first-year and baseline shut-ins occur, since compliance costs would not
7Recent events have driven the market prices somewhat higher, but $22 (a midpoint between
this year's and last year's price of Louisiana oil) may be a more reasonable estimate for the long
term. The Watt Street Journal (Thursday, October 8,1996, p. C21) reports Louisiana Sweet at
$25.68, up from $17.70 this time last year. The midpoint is $21.69. Worldwide, current prices
range from about $21/bbl (Arab heavy oil) to $25/bbl. Additionally, netting out transportation
costs, a $22/bbl price is more consistent with wellhead price in EPA's production loss and firm
failure analysis.
8EPA believes that a 5-year delay is conservative, given that if an investment is a good one,
firms will attempt to undertake it as soon as feasible. Raising new capital actually should take at
most a year or two with a viable project already planned.
'EPA's use of a 15 percent internal rate of return on the investment (actual return, not
projected) is somewhat high (to be conservative) (see Table 3-2 in Chapter Three of this FEIA
for typical rates of return).
7-6
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be incurred by first-year and baseline shut-ins, and these costs are included in EPA's compliance
cost estimate.
EPA multiplies this result by the BEA national-level final demand multipliers for output
and employment (1.9420 and 13.0, respectively) (RIMS II National Multipliers) to calculate
national-level output and employment losses associated with delayed investment.
7.1.3 National-Level Output Reductions and National-Level Employment Impacts
7.1.3,1 Output Losses
Type 2 Output Losses
Table 7-1 shows the total national-level output losses associated with the estimated
production losses for Major Pass and Cook Inlet operations discussed in Chapter Five. As the
table shows, the average annual production loss is 454,585 BOE.10 At $22 per bbl (see Section
7.1.2), the associated revenue (output) loss is $10.0 million. Using the output multiplier of
1.9420, national-level output effects are estimated to total $19.4 million per year.
Type 4 Output Losses
Table 7-2 shows the national-level output losses associated with delayed production. The
annualized compliance costs for Major Pass and Cook Inlet operations are estimated to be $15.6
million (see Chapter Four of this FEIA). The total present value of these compliance costs is
$109.6 million.11 EPA assumes that this money is no longer immediately available for
investment and revenues will be delayed for 5 years. Using the method discussed in Section
7.1.2, where 15 percent of the present value of compliance costs (or $16.4 million) is assumed to
10No first-year shut-in production losses occur.
"$15.8 million expended each year for 10 years discounted to the present at 7 percent.
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TABLE 7-1
NATIONAL OUTPUT LOSSES ASSOCIATED WITH
POSTCOMPLIANCE PRODUCTION LOSSES
FOR THE CURRENT REGULATORY BASELINE UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES AND COOK INLET PLATFORMS)
(1995 S)
Major Pass
Cook Inlet
Total
Annualized
production loss
(BOE)
301,943
152,642
454,585
Annualized
industry output
(revenues) lost
(SOOO)
$6,642.7
$3,358.1
$10,000.9
Final-demand
output
multiplier tal
1.9420
1.9420
1.9420
Annualized
national-level
output effects
(SOOO)
$12,900.2
$6,521.5
$19,421.7
[a] Represents the total dollar change in output that occurs in all industries for each dollar change in
output delivered to final demand by the oil and gas industry.
Sources: Major Pass Dischargers Production Loss Model Runs and Cook Inlet Dischargers Production
Loss Model Runs (CBI data; in rulemaking record).
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by Industry
Aggregation, for Output, Earnings, and Employment. Regional Input-Output Modeling
System (RIMS H), Regional Economic Analysis Division.
TABLE 7-2
NATIONAL OUTPUT LOSSES ASSOCIATED WITH
DELAYED PRODUCTION FOR THE CURRENT
REGULATORY BASELINE UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES AND COOK INLET PLATFORMS)
(1995 S)
Major Pass
Cook Inlet
Total
Annualized
industry output
(revenues) lost
(SOOO)
$565.0
$106.9
$671.9
Final-demand
output
multiplier [a]
1.9420
1.9420
1.9420
Annualized
national-level
output effects
(SOOO)
$1,097.2
$207.6
$1.304.8
[a] Represents the total dollar change in output that occurs in all industries for each
dollar change in output delivered to final demand by the oil and gas industry.
Sources: Major Pass Dischargers Production Loss Model Runs and Cook Inlet
Dischargers Model Runs (CBI data; in rulemaking record).
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by
Industry Aggregation, for Output, Earnings, and Employment. Regional
Input-Output Modeling System (RIMS II), Regional Economic Analysis
Division.
7-8
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be the return associated with this investment, the delayed investment will result in a present
value loss of $4.7 million.12 This investment delay will result in a reduction in annualized
returns of $0.7 million. Multiplying these output numbers by the national output multiplier for
the oil and gas industry gives a loss of $1.3 million per year resulting from the investment delay.
7.1.3.2 Employment Losses
Type 2 Employment Losses
Table 7-3 presents the national-level employment losses associated with the lost oil and
gas industry output estimated above. EPA converts the industry revenue losses into millions of
1992 dollars13 and multiplies these losses by the employment multipliers to determine total
employment losses of 119 FTEs.
Type 4 Employment Losses
Table 7-4 presents the national-level reduction in employment associated with the output
losses estimated above. EPA converts the returns forgone due to delayed investment into
millions of 1992 dollars and multiplies these numbers by the employment multipliers to
determine the total reduction in employment of 8 FTEs.
12$16.6 million is multiplied by 1/1.075 to discount this return to Year 1 from Year 5. This
equals $11.9 million. The loss is calculated as: $16.6 million - $11.9 million = $4.8 million.
13BEA's RIMS II national multipliers are based on 1992 data.
7-9
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TABLE 7-3
NATIONAL EMPLOYMENT LOSSES
ASSOCIATED WITH LOST OUTPUT (TYPE 2 LOSSES) FOR THE
CURRENT REGULATORY BASELINE UNDER THE SELECED OPTIONS
(MAJOR PASS FACILITIES AND COOK INLET PLATFORMS)
Major Pass
Cook Inlet
Total
Annualizcd
industry-level
output effects
($000 1995)
56,642.7
S3.358.1
S10.000.9
Annualizcd
industry-level
output effects
(SOOO 1992) fa]
$6,052.7
$3,059.8
$9,112.5
Final-demand
employment
multiplier |b]
13.0
13.0
13.0
Total annual
employment
losses
(FTEs)
79
40
119
[a] Output values deflated from 1995 dollars to 1992 dollars because the Bureau of
Economic Analysis employment multipliers are based on 1992 data.
[b] Represents the total change in number of jobs that occurs in all industries for each
SI million change in output delivered to final demand by the oil and gas industry.
Sources: Table 7-1 in this FEIA.
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by
Industry Aggregation, for Output, Earnings, and Employment Regional
Input-Output Modeling System (RIMS II),- Regional Economic Analysis
Division.
TABLE 7-4
NATIONAL EMPLOYMENT LOSSES
ASSOCIATED WITH DELAYED PRODUCTION (TYPE 4 LOSSES) FOR THE
CURRENT REGULATORY BASELINE UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES AND COOK INLET PLATFORMS)
Major Pass
Cook Inlet
Total
Annualized
industry-level
output effects
(SOOO 1995)
$565.0
$106.9
$67 1.9
Annualized
industry-level
output effects
(SOOO 1992) [a]
$514.8
$97.4
S612.2
Final-demand
employment
multiplier [b]
13.0
13.0
13.0
Total annual
employment
losses
(FTEs)
7
1
8
[a] Output values deflated from 1995 dollars to 1992 dollars because the Bureau of
Economic Analysis employment multipliers are based on 1992 data.
[b] Represents the total change in number of jobs that occurs in all industries for each
SI million change in output delivered to final demand by the oil and gas industry.
Sources: Table 7-2 in this FEIA.
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by
Industry Aggregation, for Output, Earnings, and Employment. Regional
Input-Output Modeling System (RIMS II), Regional Economic Analysis
Division.
7-10
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7.13.3 Total Type 2 and Type 4 Output and Employment Losses
Total Output Losses
Given the $10.0 million of lost oil and gas industry output leading to $19.4 million in
national-level support losses and the $0.7 of foregone oil and gas industry output per year
leading to $1.3 million in national-level output losses, total output effects (based both on lost and
delayed production) are estimated to be $20.7 million per year. This reduction in output is
0.0003 percent of gross domestic product (GDP) of $7.2 trillion14 and 0.03 percent of oil and gas
industry's contribution to GDP in 199515 (see Table 7-5 for a summary of output losses).
Total Employment Losses
Combining the employment losses and foregone employment, EPA estimates a total
reduction of 127 FTEs as a result of the Coastal Guidelines. This lost or foregone employment
is only 0.0001 percent of total 1995 U.S. employment of 124.9 million persons (see Table 7-5 for
a summary of employment losses).16
"Economic Report of the President, February 1996, U.S. Government Printing Office,
Washington, D.C.
"Estimated at $70.0 billion in 1995, based on the estimate that the oil and gas industry
contributes approximately 1 percent to total GDP. Percent contribution estimated using 1992
data, cited in Table Nos. 700 and 1173, Statistical Abstract of the U.S. Department of
Commerce, U.S. Bureau of the Census, September 1995.
"Bureau of Labor Statistics, Personal communication with Anne Jones, ERG, dated July 24,
1996, regarding total U.S. employment.
7-11
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TABLE 7-5
SUMMARY OF NATIONAL EMPLOYMENT AND
OUTPUT LOSSES FOR THE CURRENT REGULATORY BASELINE
UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES AND COOK INLET PLATFORMS)
(1995$)
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses [a]
Type 4 Losses fbl
Total Losses
Annualized
production
losses
(BOE)
—
454,585
~
..
454,585
Annualized
industry output
(revenue) losses
($000)
—
$10,000.9
—
$671.9
$10,672.8
Annualized
national-level
output losses
($000)
—
$19,421.7
i
$1,304.8
$20.726.5
Annual
Reduction in
FTEs
—
119
~
8
127
[a] Type 1 and Type 3 losses are not calculated in this FEIA because any losses and gains
are assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
Sources: Tables 7-1,7-2,7-3, and 7-4 in this FEIA.
7-12
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7.2 REGIONAL EMPLOYMENT IMPACTS
7.2.1 Introduction
As noted above, compliance costs by themselves do not really have a national-level
impact because the money is not lost; it is simply reallocated. In fact, it is even reallocated to
many of the same inputs, so the capital-to-labor ratio of the reallocated investment does not
change substantially between baseline and postcompliance scenarios.17 First-year shut-ins and
firm failures (Type 3 losses), production losses from earlier shut-ins (Type 2 losses), and losses
from delayed investment (Type 4 losses) are used to determine the potential dislocation effects
of the Coastal Guidelines at the regional level.
The methodology for calculating Type 2 and Type 4 losses at the regional level is similar
to that used to compute national-level losses. Production (revenue) losses are used to estimate
regional employment losses in the same way as at the national level, but using regional, rather
than national, level multipliers to determine average annual primary and secondary losses in
employment. These losses encompass all losses that will occur sometime over the course of the
analytical time frame (but not in the first year). Losses associated with delays in investment are
an issue at the national level, but less so at the regional level, since the delayed investment may
not have occurred in the region of interest. To be conservative, EPA has assumed that
productive capital would have stayed in the region, and so estimates Type 4 losses also.
The major difference in calculating employment losses at the regional level vs. at the
national level (other than the use of regional-level rather than a national-level multiplier) is that
losses due to first-year shut-ins (Type 3 losses) are counted at the regional level, whereas at the
national level, these losses are balanced by gains when investments are reallocated to other
regions or economic sectors. To calculate Type 3 losses, EPA uses the primary direct losses
occurring only in the portion of the coastal oil and gas industry discharging produced water as of
the effective date of the rule (i.e., Major Pass and Cook Inlet dischargers; Chapter Ten discusses
"If the capital-to-labor ratio is much smaller in one industry and larger in another, when
money is reallocated from one to another industry, employment can change.
7-13
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impacts under an alternative baseline scenario).18 As discussed above, secondary (indirect and
induced) impacts must also be estimated. These losses include employment losses in industries
providing inputs to the coastal oil and gas industry (as well as other supporting industries, such
as community-based services) that lose income when layoffs occur; such losses would result from
any significant decline in demand for inputs, as well as from regional reductions in personal
income. To compute total primary plus secondary losses, EPA uses another type of multiplier, a
regional direct-effect multiplier. EPA multiplies the direct losses from shut-ins and firm failures
by the appropriate regional direct-effect multiplier. These losses are the immediate impact (Type
3 losses) on community employment levels resulting from implementation of the Coastal
Guidelines.
7.2.2 Methodology
The following sections present the methodology for computing Type 3 losses, then
summarize the approach for estimating Type 2 and Type 4 losses on a regional level.
7.22.1 Type 3 Primary Employment Lasses
Primary employment losses for the regional impact analysis include employee layoffs
associated with the first-year facility/platform shut-ins estimated in the production loss analysis
and the firm failures in the firm-level analyses. These job losses (measured in hours) are
estimated using survey data regarding annual employment hours.
To estimate total primary employment losses, EPA first calculates losses from first-year
facility/platform shut-ins. Based on the Section 308 Survey, the Agency estimates that 1.16 full-
time equivalents (FTEs) are required to operate each coastal oil and gas well in the Gulf of
Mexico (4,675 Gulf of Mexico wells divided by 5,403 Gulf of Mexico employees reported in the
18EPA recognizes that the rule only becomes "real" when it is implemented through issuance
of an NPDES permit to discharge. For purposes of analysis here, EPA assumes immediate
implementation.
7-14
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Section 308 Survey—see Chapter Seven of the PEIA). This estimate may be high because some
operators might have reported secondary employment (e.g., well service portions of their
business, or drilling), not just oil and gas production employment, in their financial data. Such
over-reporting is assumed to be offset, however, by the fact that some firms hire outside
contractors to run their operations and thus report very few operating employees.
For Cook Inlet, EPA uses the same methodology as for the Gulf to estimate employment
per well, i.e., EPA divides numbers of employees reported in the Section 308 Survey by numbers
of wells (431 employees and 224 wells19 = 1.9 employees per well). First-year facility or
platform shut-ins are assumed to be associated with the direct loss of this number of employees
per well in each region summed over all first-year shut-ins.
However, in general, these first-year shut-ins only have a few additional years of
economic life in the baseline. EPA assumes that the true impact is the difference between a loss
now and a loss in the future (i.e., the year when the facility or platform would have shut in in the
baseline). Thus the number of FTEs lost (which can be thought of as "earnings" lost) a number
of years later (as determined based on the relevant model runs) is discounted to create a loss in
a present value sense, and then subtracted from the first-year losses. These differences are then
annualized. The difference in employment can be attributed to the Coastal Guidelines.
To calculate employment losses from firm failures, EPA analyzes firms to determine
whether they are likely to fail under the various regulatory options. If a firm is shown to be
likely to fail, it is assumed that some firm-level employment is lost. Facilities/platforms (owned
by failing firms) that do not shut in as a result of the Coastal Guidelines are assumed to be sold
intact with no loss of employment when their operator fails.20 Thus, no additional employment
"See Chapter Three of this FEIA.
^This assumption follows from assuming a fixed level of productivity (producing wells per
employee). Given that the wells in question are shown to be productive and assuming that a
fixed number of employees are needed to operate them, any losses in employment are expected
to be temporary because firms acquiring new wells would most likely need to expand their
employment. The costs associated with dislocations and relocations should be limited, given that
the wells remain in the same geographic area and operating personnel would most likely be hired
locally. This is true both in the Gulf of Mexico and Cook Inlet.
7-15
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losses are associated with firm failure beyond administrative and other nonproduction personnel
(production personnel losses are accounted for in the production loss side of the analysis). It is
difficult to estimate the proportion of nonproduction employment that might be affected; other
areas of business that could be sold intact rather than liquidated are not surveyed in sufficient
detail. At maximum, however, all nonproduction employment can be assumed to be lost with a
firm failure (for firms included in the Section 308 Survey, the 1992 nonproduction employment is
known). EPA expresses total employee hours lost in FTEs, assuming that 2,080 hours (52
x 40 hours/week) equals 1 FIE.
73,22 Type 2, Type 3, and Type 4 Secondary Employment Losses
As discussed above/secondary employment losses occur in industries providing inputs to
the coastal oil and gas industry as a result of reduced expenditures for these inputs. The
discussion below focuses first on the effects of the first-year shut-ins and firm failures, and then
addresses the impacts derived using the effects of production losses.
To estimate Type 3 secondary employment losses using the first-year shut-ins and firm
failure employment effects, EPA uses BEA's regional (state-level) direct-effect multipliers,
instead of the national final-demand multipliers discussed above (which are used to compute
changes in employment based on changes in output). Direct-effect multipliers represent the total
change in the number of FTEs in all industries in a region for each FTE lost or gained in the oil
and gas industry. In this regional analysis, since the number of employees (FIEs) lost in the
region is known (i.e., employment losses do not have to be estimated based on output), the
direct-effect multipliers are the appropriate multipliers to use. These multipliers will somewhat
overstate the effects in the immediate regions near the affected operations in Louisiana and
Alaska, however, because they reflect statewide changes in employment.
7-16
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In this analysis, the industry directly affected is the Crude Petroleum and Natural Gas
Industry (SIC 131).21 The regional (state) multiplier (measuring direct, indirect, and induced
employment effects) reported by BEA (RIMS II Handbook) for this industry is 2.6985 for
Louisiana and 2.7792 for Alaska. The total number of job losses, both primary and secondary, is
computed by multiplying the primary losses in coastal oil and gas industry jobs (measured in
FTEs) by the relevant multiplier:
Total direct and indirect job losses in the Gulf coastal region =
2.6985 * primary losses in the Gulf coastal oil and gas industry.
Total direct and indirect job losses in the Cook Inlet region =
2.7792 * primary losses in the Alaska coastal oil and gas industry.
EPA also estimates impacts on employment calculated from production losses (Type 2
losses) to provide a sense of the impacts on the local economy over the full time frame of the
analysis, not just in the first year. Note that these impacts, however, represent less of an
immediate dislocation effect, since the more warning employees have that their jobs will be lost,
the better the employees can plan to minimize any dislocation effects.22 To calculate the
regional employment losses associated with production losses, EPA uses the state final-demand
employment multipliers of 8.6 FTEs per $1 million change in output for Louisiana and 4.0 jobs
per $1 million change in output for Alaska (RIMS II Handbook). As in the national-level
analysis, EPA multiplies the present value production losses by the market value of that
production ($22/bbl) to estimate the output loss in the oil and gas industry. EPA subtracts
production losses due to first-year shut-ins from total production losses since the losses in
employment for first-year shut-ins are calculated already, as discussed above. EPA then
multiplies the output change (adjusted to 1989 dollars) for each region by the appropriate
multiplier to estimate the total number of primary and secondary job losses that will occur
annually over the time frame of the analysis.
"Multipliers based on direct employment changes are available at an aggregated industry
level only.
"In many cases, the Coastal Guidelines result in a loss of a year or two of production, e.g., in
baseline the operation will produce until Year 10, while postcompliance the operation will
produce until Year 9.
7-17
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733.3 Measuring Impacts at the Community Level
The significance of employment losses for the affected community as a whole is estimated
in terms of their impact on the community's overall level of employment. Data necessary to
determine the impacts on the community include the community's total labor force and
employment rate. For purposes of the analysis in Louisiana, the community is defined as the
parishes near the affected facilities. For the Major Pass dischargers, EPA assumes employment
losses occur primarily in or around several coastal parishes in Louisiana (Plaquemines, St.
Bernard, Jefferson, and Orleans, which contain or are contiguous to the Mississippi Delta and its
Major Passes). Other parishes might also be affected, but are considered less likely. According
to Bureau of Labor Statistics for 1991 (BLS data),23 an estimated 465,406 employed persons live
in these four parishes. The unemployment rates over all four parishes range from 5.6 to 7.0
percent, with a weighted average for the four-parish region of 5.9 percent. In Alaska, community
employment information is taken from the Kenai region of Alaska (Kenai Peninsula Borough),
where 16,882 employed persons live and where the unemployment rate was 12.7 percent in 1991.
1.23 Results—Regional Employment Impacts From BAT Options
723.1 Basdine Losses: Primary and Secondary Employment Losses
As discussed above, employment losses are counted when a facility or platform shuts in
(100 percent of the per-well employment) and when a firm fails (100 percent of nonproduction
employment).
Under the current regulatory baseline, no Major Pass operations are expected to shut in,
nor are any firms expected to fail. Thus no baseline direct employment losses are estimated for
this group. Total coastal employment in the Major Pass discharger group is estimated at a
data obtained at http://www.census.gov/datamap/www/index.html. The most recent year
for which parish-level BLS data are available is 1991. Weighted average calculated by EPA on
the bans of population.
7-18
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minimum of 406 production FTEs (most firms did not report employment or break out coastal
employment).
Total current Cook Inlet direct oil and gas production employment is estimated to be 431
FTEs (Section 308 Survey Questionnaire). No employment is expected to be lost under the
current regulatory baseline (i.e., no firms are expected to fail and no production is expected to be
lost in baseline). Among the Major Pass and Cook Inlet operations combined, total baseline
employment is at least 837 FTEs.
7.23,2 Postcompliance Losses: Primary and Secondary Employment Losses
EPA's selected options for the Coastal Guidelines are Option #2 for produced
water/TWC (zero discharge all; discharge limitations for Cook Inlet) and Option #1 for drilling
wastes (which corresponds to current practice and thus is a no-cost option). No direct losses of
employment occur under Option #2 for produced water/TWC and Option #1 for drilling wastes,
since no firm failures or first-year shut-ins occur (see Chapters Five and Six of this FEIA). Thus
EPA expects no direct, first-year employment impacts due to the Coastal Guidelines.
However, for the selected options, employment losses associated with production losses
(Type 2 losses) will occur over time. Total production losses in Louisiana (among the Major
Pass dischargers) amount to 2.1 million PVBOE (see Table 5-5 in Chapter Five of this FEIA), or
301,943 BOB annually (these losses do not need to be adjusted for first-year shut-ins, since none
occur). The value of this output is $5.6 million in 1989 dollars (using $22/bbl of oil and a
deflator of 0.8435),24 thus EPA calculates the annual reduction in the number of FTEs related
to production losses to be 48 FTEs in Louisiana as a result of the Coastal Guidelines, based on
8.6 FTEs lost per $1 million output loss.
Production losses in Cook Inlet, Alaska, under the selected options total 1.1 million
PVBOE (see Table 5-4 in Chapter Five of this FEIA), or 152,642 BOE annually (these losses
24-
'Engineering News Record Construction Cost Index is used to deflate from 1995 to 1989.
7-19
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also do not need to be adjusted for first-year shut-ins). The value of this output is $2.8 million
in 1989 dollars. Thus the total number of FTEs lost annually in Alaska as a result of the Coastal
Guidelines is estimated to be 11, based on 4.0 FTEs lost per $1 million output loss.
Employment losses due to delayed investment among the Major Pass dischargers is
estimated to be 4 FTEs, based on an annual output loss of $0.5 million in 1989 dollars (see
Table 7-4) and given the 8.6 FTEs lost per $1 million change in output.
Employment losses due to delayed investment among the Cook Inlet dischargers is
estimated to be 1 FTE, based on an annual output loss of $0.1 million in 1989 dollars (see Table
7-4) and given the 4.0 FTEs lost per $1 million change in output.
Based on losses due to first-year shut-ins and firm failures (no losses) and production
losses and delayed investment under the selected options, jobs estimated to be lost annually in
Louisiana and Alaska as a result of the Coastal Guidelines total 5 FTEs (see Table 7-6 for a
summary of these impacts).
Employment losses combined for Type 2, Type 3, and Type 4 losses are 52 FTEs in
Louisiana and 12 FTEs in Cook Inlet, for a total of 64 FTEs under the current regulatory
baseline.
7.2.3.3 Community-Level Impacts
Selected Options
EPA anticipates no immediate direct, indirect, and induced employment losses associated
with first-year shut-ins and firm failures under the selected options, so no immediate community-
level impacts are anticipated. Based on employment losses calculated using production losses,
EPA estimates that 48 employees in Louisiana and 11 employees in Alaska might be lost in the
community per year on average over the timeframe of the analysis. Added to this are the 4
FTEs lost in Louisiana and 1 FTE lost in Alaska due to delayed investment. This estimate
7-20
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TABLE 7-6
SUMMARY OF REGIONAL EMPLOYMENT
AND OUTPUT LOSSES FOR THE
CURRENT REGULATORY BASELINE
UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES AND COOK INLET PLATFORMS)
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses
Type 4 Losses Jbl
Total Losses
Annualizecl
production
losses
(BOB)
-
454,585
-
_
454,585
Annualized
industry output
(revenue) losses
(SOOO 1995)
-
$10,000.9
-
$671.9
$10,672.8
Annualized
industry output
(revenue) losses
(SOOO 1989) [cl
-
$8,436.1
~
$566.8
$9,002.9
Annual
Reduction in
FTEs
-
59
0
5
64
[a] Type 1 losses are not calculated in this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Sources: EPA analysis described in text; Tables 7-1,7-2,7-3, and 7-4 in this FEIA.
TABLE 7-7
SUMMARY OF REGIONAL EMPLOYMENT AND
AND OUTPUT LOSSES FOR THE COOK INLET PLATFORMS
UNDER THE OPTION #3 FOR PRODUCED WATER (ZERO DISCHARGE)
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses
Type 4 Losses [b]
Total Losses
Annualized
production
losses
(BOE)
1,347,801
1,347,801
Annualized
industry output
(revenue) losses
(SOOO 1995)
$29,651.6
$1,627.2
$31,278.8
Annualized
industry output
(revenue) losses
(SOOO 1989) [c]
$25,012.3
$1,372.6
$26,384.9
Annual
Reduction in
FTEs
100
3
5
108
[a] Type 1 losses are not calculated in this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Source: EPA analysis described in text.
7-21
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overstates community losses, since the multipliers used to develop these estimates project losses
in employment over the entire state, not just in the parishes and boroughs of concern.
Using the employment losses projected in Louisiana and the current employment in the
four parishes in Louisiana expected to bear the greatest impact (465,406 employed persons),
EPA estimates that these losses represent a 0.01 percent change in employment in the affected
areas of Louisiana (unemployment rate changes from 5.9 percent to 5.91 percent).
For Kenai Peninsula Borough, Alaska (with employment of 16,882 persons), EPA
estimates that the employment losses in the affected area of Alaska lead to a change of 0.05
percent in the unemployment rate in this area (the unemployment rate increases from 12.7
percent to 12.76 percent). EPA concludes that employment impacts of the Coastal Guidelines
for the four parishes in Louisiana or for the Kenai Peninsula, Alaska, are not significant.
Option #3 (Zero Discharge All)
Employment Losses Under Option #3 in Cook Inlet—Under Option #3 for produced
water/TWC wastes (zero discharge all), which is not EPA's selected option, employment losses
totaling 25 FTEs (based on one platform with 13 wells in Cook Inlet25 shutting in the first
year—see Chapter Five of this FEIA) are expected to occur. When the discounted value of
those FTEs lost 6 years from now when the platform shuts in in baseline is subtracted from the
loses in the first year, 8 FTEs are estimated to be lost as a result of the Coastal Guidelines.
When this loss is annualized, EPA estimates that 1 FTE will be lost annually. No firm-level
employment losses are expected to occur. Total direct primary and secondary Type 3 losses
(using the direct effect multiplier of 2.7792 for Alaska) are estimated to be 3 FTEs based on firm
failures and first-year shut-ins.
Production losses in Cook Inlet, Alaska, under Option #3 for produced water total 9.5
million PVBOE (see Table 5-4 in Chapter Five of this FEIA), or 1.3 million BOE annually. The
"Major Pass results do not change under this option so are not discussed in this subsection.
7-22
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value of this output is $25.1 million in 1989 dollars. Thus the total number of FTEs lost annually
in Alaska as a result of the Coastal Guidelines is estimated to be 100, based on 4.0 FTEs lost per
$1 million loss of output.
Employment losses due to delayed investment among the Cook Inlet dischargers is
estimated to be 5 FTEs, based on an annual output loss of $1.4 million in 1989 dollars (see
Table 7-7) and given the 4.0 FTEs lost per $1 million change in output.
The total annual job loss in Alaska as a result of the Coastal Guidelines due to first-year
shut-ins and firm failures, production losses, and delayed investment under Option #3 for
produced water is estimated to be 108 FTEs (see Table 7-7 for a summary of Option #3
impacts).26
Community-Level Impacts Under Option #3 in Cook Inlet—EPA estimates that the losses of
employment (108 FTEs annually) in the affected area of Alaska under produced water
Option #327 would increase the unemployment rate by 0.6 percent in this area (employment
rate changes from 12.7 percent to 13.3 percent). EPA concludes that the impact to Kenai
Peninsula Borough is significant under this option. The Kenai is disproportionately dependent
on oil and gas production. In the borough, the oil and gas industry accounts for 6.3 percent of
total payroll and makes up 12.3 percent of the total labor force (BLS data). Because of the
borough's high unemployment rate and sensitivity to employment impacts on the local oil and gas
industry, EPA concludes that employment impacts (along with results of analyses in Chapter
Five) contribute to a finding of economic inachievability for zero discharge of produced water in
Cook Inlet.
26These losses would be further compounded if EPA had selected zero discharge
requirements for drilling waste. Additional platforms shut in under this scenario and
substantially more production is lost (see Chapter Five).
"Impacts in Major Pass communities do not change from Option #2 results under
Option #3.
7-23
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CHAPTER EIGHT
IMPACTS ON THE BALANCE OF TRADE, INFLATION, AND CONSUMERS
Although the costs and economic impacts of the BAT and NSPS regulations will fall
primarily on the coastal oil and gas industry, including its employees, other secondary effects in
other sectors of the economy will also occur. Chapter Seven discusses secondary employment
effects, and Chapter Five discusses impacts on federal and state tax revenues. This section
reviews the potential effects of regulatory costs on the balance of trade and on inflation and
consumers.
8.1 IMPACTS ON THE BALANCE OF TRADE
The United States has now reached a point where oil imports exceed total oil production.
Oil and Gas Journal reports that "for the first time in history, more than half the oil used in the
United States in a given year [1994] was imported."1 A shortage of trained personnel and
workover rigs are factors cited as limiting any near-term sizable increase in domestic
production.2-3-4 Indications are that unless domestic demand for oil is curbed, the United States
will continue to import a growing percentage of the supply needed to satisfy domestic
consumption. In 1995, U.S. domestic production of crude oil was approximately 47 percent of
1('OGJ Newsletter," Oil and Gas Journal (OGJ), Vol. 93, No. 4, January 23, 1995, p. 2.
2"Despite Output Push, U.S. Probably Cannot Avoid Oil Production Decline in 1991," Oil
and Gas Journal (OGJ), September 17, 1990, pp. 21-24.
3"W. Coast Best Potential for Output Hike Soon," Oil and Gas Journal (OGJ), October 1,
1990, pp. 38-42.
. Oil Flow Hike Unlikely Outside W. Coast," Oil and Gas Journal (OGJ), October 1,
1990, pp. 32-36.
8-1
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total U.S. demand (production plus imports).5 This phenomenon is occurring independent of
any incremental pollution control costs.
EPA estimated the potential lifetime total production loss of 5.8 million BOB in Chapter
Five. Under the selected options, annual production declines of 0.4 million BOB equal 0.02
percent of U.S. domestic crude oil production (over 2 billion barrels in 1995).6 Furthermore,
the lifetime losses are only 0.2 percent of total coastal production (not including California and
the North Slope) over the lifetimes of the affected discharging wells and platforms (see Chapter
Five). This is a relatively small percentage given the estimated annual decline in domestic
production of about 3 percent per year cited in projections.7 Thus the change in the balance of
trade expected from the rulemaking will not be significant compared to changes caused by other
factors.
8.2 IMPACTS ON INFLATION AND CONSUMERS
The regulations will lead to higher costs for industry operators. When evaluating the
possibility of this effect on typical companies, EPA did not assume that companies could raise
prices to recover these costs. This assumption would be consistent with the fact that the United
States is a price-taker in the world oil market (i.e., the price the companies will receive for their
product is determined by the world oil price and not domestic costs). Given the nation's
continued growth in demand, supply (and therefore price) is not likely to be controlled
domestically (although control by OPEC is still possible). The fact that coastal production is
such a small fraction of total U.S. production further reduces any potential to affect prices.
Given the inability of the companies to raise prices in response to increased costs, no substantial
impacts on inflation are likely to result from increased costs associated with pollution controls on
5U.S. Department of Energy (DOE). 1996. "Crude Oil Supply and Disposition,
1973—Present." Obtained at http://www.eia.doe.gov.
6Ibid.
'"OPEC, Once Ail-Powerful, Faces a Cloudy Tomorrow," Drewry Shipping Consultants, Oil
and Gas Journal (OGJ), August 22,1994, p. 18 (Table).
8-2
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coastal oil and gas effluents. Therefore, the effects of this rulemaking will fall exclusively on
coastal oil and gas producers and their employees and shareholders. Consumers of oil and gas
products will not be facing higher prices as a result of higher coastal production costs.
8-3
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CHAPTER NINE
IMPACTS ON NEW SOURCES
EPA has set the selected NSPS and PSNS regulations equal to the selected BAT options
for all waste streams with new source requirements. Because new sources will face the same
requirements as existing sources, most of whom are achieving zero discharge, new operations
should face no significant barriers to entry. Furthermore, since EPA has found that BAT
requirements are economically achievable, NSPS requirements should be economically achievable
as well.
To further confirm that NSPS requirements both are economically achievable and create
no barriers to entry, EPA looked more closely at how the NSPS requirement for produced
water/TWC might affect a project in Cook Inlet.1 The NSPS requirement for produced water
will require a new platform to meet standards equivalent to those achieved by improved gas
flotation (Option #2 for existing platforms). To perform its analysis, EPA used the Steelhead
platform as a model for a possible future Cook Inlet project. Steelhead was selected as the
model because it is the platform most recently constructed in the Inlet (in the mid-1980s). Data
for Steelhead from the PEIA were supplemented with updated data and parameters from a
model for a Cook Inlet NSPS platform developed in the EIA for the offshore oil and gas
industry ("Offshore EIA").2
lrThe Region 6 General Permits for produced water and drilling wastes already require zero
discharge in the coastal Gulf of Mexico area, so only the Coastal Guidelines covering TWC
wastes will have an incremental regulatory impact in that region under NSPS requirements.
Incremental TWC losses, moreover, amount to less than $2,000 per well annually. Additionally,
under NSPS requirements, a new platform in Cook Inlet will need to meet the same toxicity
limits on drilling wastes currently being met by other operations in Cook Inlet. NSPS limits on
drilling wastes, therefore, are no more stringent than baseline assumptions for an existing Cook
Inlet platform and, as such, are not associated with any incremental costs.
2U.S. EPA. 1993. Economic Impact Analysis of Effluent Guidelines and Standards of
Performance for the Offshore Oil and Gas Industry. Washington, D.C. January.
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EPA has estimated capital costs for constructing and installing dedicated wells for
produced water injection (zero discharge) for a new platform in Cook Inlet to be $8.1 million
(see EPA's Develoment Document),3 which is only 2.3 percent of the estimated present value
costs for the construction of an entire NSPS platform (approximately $357 million in 1995 dollars
for leasebid, platform construction, and drilling of exploratory, development, and production
wells, based on data from Steelhead [see Chapter Five] and the Offshore EIA). The costs of
purchasing and installing gas flotation equipment, moreover, are generally much less than the
capital costs incurred in meeting a zero discharge requirement. The highest capital cost for
retrofitting an existing Cook Inlet platform for gas flotation (excluding platform modification
costs), for example, is estimated at $1.7 million.4 This amount is equal to 0.05 percent of the
construction cost of a platform like Steelhead. Thus, given the selected NSPS produced water
option of gas flotation, capital costs of compliance are very small (less than 2.3 percent, in the
worst case), relative to the capital expenditures required for the project as a whole.
The addition of up to 2.3 percent (under zero discharge) to the overall costs of
constructing a platform in Cook Inlet should not present a barrier to entry, even if no other
platforms in Cook Inlet are required to meet BAT requirements. Additionally, since BAT
modeling shows that it is economically achievable (with minimal impacts) for existing platforms
to meet discharge limits based on improved gas flotation, it should be economically achievable
for new platforms to meet the same limits. All new and existing offshore platforms must meet
similar limits, so a new Cook Inlet platform also is no more disadvantaged than any new offshore
platform.
Despite the economic achievability of the selected NSPS regulations, however, it does not
appear likely that an NSPS project will be undertaken in Cook Inlet in the near future. EPA's
baseline model, in fact, suggests that a new platform will not be built in Cook Inlet in the next 15
3McIntyre, Jamie, Avanti, Memorandum to Ron Jordan, U.S. EPA, dated May 30,1996,
entitled "NSPS Compliance Costs for Drilling Wastes and Produced Water Management in Cook
Inlet."
4Avanti. 1996. Costs and Loadings for Effluent Limitations Guidelines for the Coastal
Subcategory of the Oil and Gas Extraction Industry. Prepared for the U.S. Environmental
Protection Agency. April 29.
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years without substantial changes in oil price, peak production rates per well, or other related
factors.5 In creating this model, EPA assumed that the NSPS operator would be a major,
integrated producer. Costs (inflated to 1995 dollars from the Offshore EIA) to develop the
model platform include: $71,000 for leasebid, $12.9 million for drilling of each exploratory or
delineation well (with a discovery efficiency of 0.27), $254.8 million for platform construction and
drilling, and $4.7 million drilling costs per production well. The platform is initially assumed to
service 34 wells, with an additional 7 wells added after 10 years of production.6 As noted above,
the present value of all capital costs associated with such an NSPS project is estimated to be
$357.0 million. Other inputs in the NSPS model, including wellhead prices, production levels,
operating costs, decline rate, and tax and royalty rates are based on the common parameters and
Steelhead-specific inputs used in the Cook Inlet/Major Pass production loss model (see Chapter
Five).
For an NSPS project to be viewed as a good investment, it must have an estimated
internal rate of return greater than the 20 to 25 percent "hurdle rate" generally associated with
oil and gas projects (Offshore EIA). A potential investment with an internal rate of return less
than the hurdle rate does not offer revenues high enough to offset the costs and risks associated
with that investment.
EPA's baseline analysis of the model NSPS project indicates that a new project would
have to have much higher production earnings (i.e., much lower costs, or much higher prices
combined with much higher initial production) than the typical existing Cook Inlet project before
the internal rate of return would be high enough to justify such an investment. EPA confirmed
these conclusions by conducting sensitivity analysis on the wellhead prices, operating costs, and
peak production rates associated with the platform. Prices had to be 50 percent higher and all
wells drilled had to be assumed to be productive (i.e., a 100 percent success rate) at the peak
5NSPS Production Loss Model Runs. (CBI data; in rulemaking record.)
fiNSPS Model Input Parameters and Assumptions. (CBI data; in rulemaking record.)
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production rates currently reported for new wells in Cook Inlet before the project's internal rate
of return even approached a figure that would attract the interest of an investor.7
Thus, EPA believes a new platform is unlikely to be built in Cook Inlet at this time
without, for example, substantial increases in the price of oil and the discovery of a major new
field capable of producing initially at rates greater than the peak production rates currently
experienced in the Inlet. This finding is substantiated by industry contacts who have indicated
that no new platforms are likely to be constructed in Cook Inlet in the foreseeable future (see
Chapter Three of this FEIA).
7NSPS Production Loss Model Runs. (CBI data; in rulemaking record).
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CHAPTER TEN
ALTERNATIVE BASELINE SCENARIO
10.1 INTRODUCTION AND PROFILE OF AFFECTED OPERATIONS UNDER THE
ALTERNATIVE BASELINE SCENARIO
The preceding chapters of this FEIA present the impacts of the Coastal Guidelines under
the current regulatory baseline. In response to concerns raised in comments on the proposal,
this chapter considers two additional groups of dischargers and assesses all impacts on the basis
of an alternative regulatory baseline in which these groups, in addition to Major Pass and Cook
Inlet dischargers, are assumed to be affected by the Coastal Guidelines. The two groups are
referred to here as the Louisiana Open Bay and Texas Individual Permit applicant dischargers.
To analyze impacts on the alternative baseline, EPA assumes that the dischargers in these
groups, in the absence of the Coastal Guidelines, will apply for and receive individual permits
allowing them to continue to discharge produced water despite the Louisiana state law
prohibiting produced water discharge to open bays beyond January 1997 and despite the Region
6 General Permits currently applicable to these facilities. Analysis based on this assumption
provides an estimate of the broadest possible impact of the Coastal Guidelines, although the
assumption that these entities would be allowed to discharge in the absence of the Coastal
Guidelines is not necessarily realistic, and does not follow OMB guidelines, which recommend a
baseline that takes into account the effect of other laws and regulations.1
EPA's identification and examination of the Louisiana Open Bay dischargers are based
on decisions presented in EPA's Development Document, which provides a list of permits and
outfalls in Louisiana that are located in open bays. Some of these facilities may have already
achieved zero discharge to comply with Louisiana state law, but EPA was unable to obtain
information from LADEQ to ascertain these facilities' status. As a result, this analysis presents a
worst-case scenario. The Texas Individual Permit applicant dischargers are those EPA identified
'OMB, 1996. Economic Analysis of Federal Regulations Under Executive Order 12866.
January 11, p. 9.
10-1
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as described in EPA's Development Document as having applied for individual permits allowing
discharge, rather than complying with the existing General Permits requiring zero discharge of
produced water in Texas.
Some Louisiana Open Bay and Texas Individual Permit applicant dischargers were
included in the CWA Section 308 Survey, discussed in detail in Chapter Three of the PEIA.
EPA therefore primarily bases its profiles of these groups on and obtains potentially affected well
data from Section 308 Survey responses. This information was used to represent other similarly
situated firms and wells, as discussed below.
To determine economic impacts on Louisiana Open Bay dischargers and Texas Individual
Permit applicants on a well basis, EPA determined how many wells owned by these dischargers
were surveyed, used information from the 308 Survey to estimate impacts on surveyed wells, and
developed a "multiplier" to take into account additional Louisiana Open Bay wells and Texas
Individual Applicant wells that were not surveyed. Each of these steps is detailed below.
First, in developing the Survey to apply to the whole coastal subcategory, EPA started
with a list of wells determined to be in the coastal subcategory that had been completed since
1980 (and not recompleted since 1980) and were still productive (see PEIA, Chapter Two).2
2As noted in Chapter Two of the PEIA, EPA developed this list of wells using several
computerized databases purchased and/or obtained from Tobin Surveys, Inc. (Tobin), Petroleum
Information (PI), the Louisiana Department of Natural Resources (DNR), and the Texas
Railroad Commission (RRC) (see Chapter Three for a discussion of the Coastal Subcategory).
EPA defined an area in the Gulf of Mexico region likely to contain coastal wells to narrow down
the data set for the Survey. The total number of wells in this area, however, was still very large,
over 56,000. Of these, 10,582 wells completed or recompleted since 1980, and 26,861 wells
completed prior to 1980, were active at some prior time. Because gathering information on all
27,000 wells would be a significant burden on the operators and on EPA, EPA limited its
purchase of data to that for 11,000 post-1980 wells. It is likely that data searches by operators
for pre-1980 wells would have been very time consuming, costing hundreds of thousands to
millions of dollars. As it was, survey respondents indicated that data for some wells, typically
older post-1980 wells, were difficult to obtain (Helpline Tracking Database; CBI data included in
rulemaking record, Volume H-8). EPA also conducted a possible sensitivity analysis of
production and discharge at the facility level (in addition to its well-level analysis), which EPA
believes more accurately reflects the combination of pre-1980 and post-1980 wells at these
facilities (see Section 10.3.2.5).
10-2
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EPA sent the Survey to all owners of these wells. As part of the Survey, EPA asked the owners
of sampled wells (see below) to tell EPA how many wells were associated with their
treatment/separation facilities (either discharging or nondischarging). When respondents
answered this question, they included both pre-1980 wells and post-1980 wells; thus, where both
existed, EPA obtained this information. Based on this information, EPA estimated an average of
7.35 wells per discharging treatment/separation facility across the coastal subcategory in the Gulf
of Mexico (see PEIA Chapter Three).
EPA determined the number of Louisiana Open Bay dischargers and Texas Individual
Permit applicants as described in the Development Document. Because this information
provided only the number of treatment/disposal facilities (82 outfalls in Texas and 82 outfalls in
Louisiana),3 EPA used the estimate of 7.35 wells per facility to estimate the total number of
wells represented by Louisiana Open Bay dischargers and Texas Individual Permit applicants.
This calculation results in an estimate of 603 wells in Texas and 603 wells in Louisiana. Since
the factor of 7.35, takes into account both pre-1980 and post-1980 wells, the total well estimate
represents production from both pre-1980 and post-1980 wells.
EPA did not perform a census of all wells, since the cost to the respondents to perform a
census would have been exorbitant. Instead, before conducting the Survey, EPA stratified its
sample (i.e., grouped wells into various categories before selecting some to be surveyed). A
stratified sampling approach helps reduce the number of samples needed to produce reliable
estimates. To stratify the samples, EPA looked at all the post-1980 wells determined to be
currently producing in the coastal subcategory (roughly 2,600 in the Gulf of Mexico area), and
then grouped the wells according to a variety of factors (such as major or small independent,4
freshwater or saltwater). EPA then randomly selected several wells in each group (or stratum)
and issued a detailed questionnaire asking the identified owner/operator to respond to technical
3This match on the number of outfalls between Louisiana Open Bays and Texas Individual
Permits is coincidental. EPA assumes one outfall is associated with one treatment facility
because this is usually the case.
"Small independents were identified as all operators who only had one coastal well identified
in the list of wells.
10-3
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information on the selected wells.5 Each surveyed well was given a survey weight based upon
how many wells it represented in its group (stratum). For example, in general, if the small
independent group included a total of 10 wells and 2 wells were selected for sampling, each small
independent well would represent 10/2 (or 5 wells, statistically), and each of the two wells would
have a statistical weight of 5.0.
To evaluate economic impacts to the wells in the alternative baseline, EPA identified
facilities included in the group of Texas Individual Permit applicants and Louisiana Open Bay
dischargers that were included in the detailed Survey as well as the surveyed wells comprising
those facilities. EPA then multiplied each Texas Individual Permit applicant well and Louisiana
Open Bay discharger well that was surveyed by its Survey weight to determine that the surveyed
Louisiana Open Bay discharging wells represent 167 of the 603 Louisiana Open Bay discharging
wells and the surveyed Texas Individual Permit applicant wells represent 119 wells of the 603
Texas Individual Permit applicant wells. The surveyed wells, however, only represent the portion
of those Texas Individual Permit applicant and Louisiana Open Bay discharger wells that were
completed or recompleted since 1980, and do not account for the pre-1980 wells (those never
recompleted since 1980). Thus to estimate the total economic impacts on the entire group, EPA
took the economic information from the surveyed wells and multiplied it by 603/167 for
Louisiana and 603/119 for Texas.
EPA has received comments arguing that the Section 308 Survey is not representative of
the pre-1980 wells because these wells were not surveyed. The principal concern expressed in
these comments was that pre-1980 wells, particularly those in Texas, are primarily "marginal
producers" (i.e., they produced 10 bbls of oil per day or less, including those with zero oil and
some gas, in 1992). Thus, the surveyed wells might misrepresent the limited production capacity
and end-of-life situation of the pre-1980 wells. In fact, EPA did potentially capture some wells
completed prior to 1980 that were recompleted after 1980. Additionally, EPA captured data
from both pre- and post-1980 wells on a facility basis. Furthermore, EPA's analyses show that
the older wells that have not been recompleted since 1980 are not likely to differ from the wells
SA11 operators associated with all wells in the list of wells were sent a survey to provide
financial data (a census of all known operators).
10-4
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captured in the Survey. For example, EPA determined that, among the surveyed wells in Texas
that are operated by the Texas Individual Permit applicants, the 25th percentile well produced
3.2 bbls of oil per day, the 50th percentile (or median) well produced 6 bbls of oil per day, and
the 75th percentile well produced 13 bbls of oil per day in 1992. That is, a majority of the Texas
Individual Permit wells surveyed could be considered marginal producers according to the
definitions given above, and thus marginal wells are well represented in the Survey. Using this
Survey data to represent pre-1980 wells therefore will not appreciably overstate production or
revenues, and will not exaggerate the pre-1980 wells' financial health.
Furthermore, for pre-1980 wells still in operation, EPA's estimate of a 15 percent decline
rate for oil and gas production in the Gulf may be high. The Texas Railroad Commission6
implies that the decline rate on Texas wells may be very much lower than 15 percent, stating that
"many of these [marginal] wells have been producing at marginal rates for decades."7 The
decline rate is used to project not only declines in operating revenues in the financial model (see
Section 10.3) but also to calculate increases in produced water production. Water production
increases as oil (BOE) decreases to meet an assumption of a constant volume of fluids produced.
Since costs are calculated on a dollar per barrel basis, as produced water volumes increase, costs
increase (see Section 10.3 for more details). A lower decline rate will therefore also result in
slower increases in O&M costs to dispose of produced water. If the actual decline rate is lower
than 15 percent, the cost and impacts of the Coastal Guidelines on pre-1980 wells, and possibly
on post-1980 wells, would be substantially lower than those estimated by the Agency in this
FEIA, as well as in the PEIA.8 Wells with a lower decline rate tend to be less likely to shut in
the first year and to show production losses and more likely to show a positive NPV over the life
of the project, postcompliance. If decline rates lower than 15 percent are prevalent in Texas,
6Letter to Mr. Marvin Rubin, U.S. EPA, from Lori Wrotenbury, Railroad Commission of
Texas, August 23,1996.
7At a decline rate of 15 percent per year, the average productive life of a typical Gulf Coastal
well would be between 25 and 30 years.
8EPA estimated impacts using a 1 percent and 2 percent decline rate. At a 2 percent decline
rate losses were substantially less on a percentage basis, and at 1 percent, losses were lower still
(Decline Rate Sensitivity Analysis of Louisiana Open Bay Dischargers and Texas Individual
Applicants, ERG, Inc., October 1996).
10-5
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EPA's calculations with respect to the pre-4980 wells (and possibly the post-1980 wells) using a
15 percent decline rate are likely to be conservative.
10.1.1 Louisiana Open Bay Dischargers—Wells, Treatment Facilities, Production, and
Firms
The Louisiana Open Bay dischargers operate 82 outfalls under 37 permits and represent
22 firms. Each outfall is assumed to represent one treatment/separation facility that must meet a
zero discharge requirement. As discussed above, when numbers of wells estimated using the
Survey are extrapolated to represent the pre-1980 wells, EPA estimates that 603 wells are
operating under the Louisiana Open Bay designation. This subset of the Gulf coastal population
of wells is associated with lifetime production of 72 million BOE9 in present value terms
(PVBOE), or 103 million total BOE (undiscounted).
The 82 discharging treatment facilities operating in Louisiana Open Bays are currently
associated with a total of 120.4 million bbls of produced water discharges annually, and with up
to 180.6 million bbls per year over the next 10 years (see EPA's Final Development Document).
Daily water production at these facilities ranges from 1 to 41,700 bpd. These facilities are
currently meeting BPT requirements using equipment much like that described in Chapter Three
for the Major Pass operators.
Of the 22 firms identified as Louisiana Open Bay dischargers, 17 (22 percent) are
estimated to be small businesses with fewer than 500 employees.
*BOE (barrels of oil equivalent) represents the total oil and gas produced, with gas converted
to an equivalent measurement based on the amount of energy in a cubic foot of gas and the
number of cubic feet of gas needed to match the energy in a barrel of oil. The present value of
BOE (PVBOE) reflects BOE discounted to the present under the assumption that a barrel of oil
today is worth more than a barrel of oil in the future. It is a useful measure to compare with
other present value figures.
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10.1.2 Texas Individual Permit Dischargers—Wells, Treatment Facilities, Production,
and Firms
The Texas Individual Permit applicant dischargers that are associated with 82 outfalls
have applied for 74 permits serving 603 wells (see EPA's Development Document). The
production associated with these wells is estimated at 56 million PVBOE, or 79 million total
BOB (undiscounted).10
The 82 discharging facilities in the Texas Individual Permit applicant category are
estimated to discharge 24.9 million bbls of water annually (see EPA's Development Document).
EPA projects this volume to increase to approximately 37.4 million bbls over the 10-year time
frame of this analysis. Daily average discharges range from 1 to 9,316 bpd (see EPA's
Development Document). On average, these facilities are smaller (i.e., have lower volumes of
produced fluids) than those in the Louisiana Open Bay group (Section 308 Survey data).
A total of 40 firms are identified as Texas Individual Permit applicants. Thirty-nine (98
percent) of these are estimated to be small businesses.
10.13 Financial Profile of Louisiana Open Bay and Texas Individual Permit Firms
EPA developed a financial profile of the affected subgroups under the alternative
baseline using detailed Survey responses from 28 of the 61 firms identified as either Louisiana
Open Bay or Texas Individual Permit applicant dischargers. Although the Louisiana Open Bay
and Texas Individual Permit applicant dischargers are a subset of all Section 308 operators in the
Gulf, financial conditions in the two groups differ somewhat from those in the Survey as a whole,
which represents all Gulf operators. A detailed discussion of financial conditions in the Gulf as
a whole can be found in the PEIA.
"Louisiana Open Bay Discharger and Texas Individual Permit Applicant Production Loss
Model Runs October, 1996 (CBI data; in CBI rulemaking record).
10-7
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As Table 10-1 shows, median coastal revenues among Louisiana Open Bay/Texas
Individual Permit applicant dischargers (not including majors) may be somewhat higher than
those among the larger group of Section 308 Survey operators ($369,000 versus $179,000)."
The median ratios of coastal revenues to total revenues (including revenues from other
noncoastal operations as well as from other industrial designations, such as refining or
contracting) may also be higher for the Louisiana Open Bay/Texas Individual Permit groups than
for the Section 308 Survey group, but in neither group do firms appear to rely heavily on coastal
revenues to support them.
Operating costs appear higher for operators in the Louisiana Open Bay and Texas
Individual Permit applicants groups (except majors) as compared to the Section 308 Survey
operators as a whole. This observation might be consistent with the Louisiana Open Bay and
Texas Individual Permit applicant dischargers being involved in deep water operations. The
Section 308 Survey data may include a higher proportion of firms primarily operating Chapman
(on-land) wells and wells in relatively shallow water, which tend to be less expensive to operate
than wells located in the deeper open bay waters. Gross profit margins appear slimmer among
the Louisiana Open Bay/Texas Individual Permit applicant dischargers than among the Section
308 Survey population as a whole. This factor may make coastal operations among the Louisiana
Open Bay and Texas Individual Permit dischargers relatively unimportant to the typical firm in
terms of the firm's overall profitability, given the already very small portion of total firm
revenues represented by coastal operations at a typical firm. In other words, if the typical firm
were to shut in all its coastal operations, this action is unlikely to have a major impact on either
revenues or earnings.
Given the possibility that the Louisiana Open Bay dischargers and Texas Individual
Permit applicants experience higher operating costs, it is not surprising that they appear to be
somewhat larger (with the exception of the majors and "other small independents") in terms of
assets, owner equity, and working capital than the average operator in the wider Survey
population (Table 10-2). This is especially true when the larger groupings (e..g., "all small
"No formal statistical tests have been performed to judge the statistical significance of these
differences.
10-8
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10-10
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independents") are assessed. However, the current ratio, i.e., the ratio of short-term debt to
working capital, calculated for these operators is slightly less than that calculated for the Section
308 Survey group, indicating that while the Louisiana Open Bay dischargers and Texas Individual
Permit applicants have more working capital over all firms, their short-term debt is perhaps
disproportionately greater than that of Section 308 operators as a whole.
Interestingly, Louisiana Open Bay dischargers and Texas Individual Permit applicants
may be healthier financially than the Section 308 population as a whole. As Table 10-3 shows,
nearly all categories of Louisiana Open Bay dischargers and Texas Individual Permit applicants
for which information is reported appear to have better or substantially better return on assets,
return on equity, and interest coverage ratios than operators in the Section 308 Survey group as
a whole, although the interest coverage ratio over all firms is still below 3 (which indicates that
they may have some difficulties sustaining more debt). Lenders and investors generally look for
strong returns on assets and equity, and/or high interest coverage ratio (typically a ratio of 3 or
greater indicates that the firm can easily handle more debt; as the interest coverage ratio
declines, debt financing may become more difficult). Therefore, the firms in the alternative
baseline appear possibly better positioned to raise capital than those in the larger Section 308
Survey group, although some firms may need to turn to equity or working capital (rather than
debt) to finance pollution control capital equipment.
The numbers for majors, large independents, and small corporate independents can also
be compared to 1992 Dun & Bradstreet benchmarks for the industry as a whole. According to
Dun & Bradstreet, in 1992, average ROA12 in the industry was 3.5 percent; the lowest quartile
was -1.3 percent. For ROE, the average was 6.2 percent; the lowest quartile was -2.0 percent.
(Nearly all data used to judge firm-level impacts are 1992 firm data from the Section 308 Survey,
so 1992 Dun and Bradstreet data are used for comparability.) These average ROA and ROE
figures are comparable to those calculated for majors, large independents, and small corporate
independents (given in Table 10-3). Firms in the "other small independents" category cannot be
compared because many of them are privately owned or S corporations, which are not included
12See Chapter Three for a detailed discussion of financial benchmarks used in analyzing
firms.
10-11
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•5 c 3
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10-12
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in Dun & Bradstreet's statistics. Thus, the Louisiana Open Bay and Texas Individual Permit
dischargers' ROA and ROE medians are in the acceptable range for financial health and are
near the median for comparable measures for the industry as a whole.
10.2 COSTS OF COMPLIANCE UNDER THE ALTERNATIVE REGULATORY BASELINE
Assuming that the Louisiana Open Bay dischargers see a change in state law authorizing
discharge beyond January 1997, and this group and the Texas Individual Permit applicant
dischargers receive individual permits authorizing discharge despite the no-discharge requirement
of the 1995 Region 6 General Permits, the costs of compliance under the alternative regulatory
baseline incorporate the costs required for these operations to achieve zero discharge of
produced water/TWC. Zero discharge is achieved primarily by injection, but also, for smaller
dischargers, by transporting produced water/TWC to commercial disposal facilities.13 Total
alternative baseline costs also include the costs, detailed in Chapter Four, for the Major Pass and
Cook Inlet operations to meet the requirements of the regulatory options. Note that one Major
Pass discharger, under the assumptions outline above for the alternative baseline, although
required to go to zero discharge for the coastal portion of its produced water discharges under
the current Region 6 General Permits might be considered a part of the group that could
hypothetically receive an individual permit. Additional costs have been assigned to this Major
Pass operator under the assumptions of the alternative baseline (see EPA's Development
Document).
This section presents the costs to achieve zero discharge for Louisiana Open Bay
dischargers, Texas Individual Permit applicants, and both of these groups combined. The section
then summarizes EPA's estimates of costs to meet the selected regulatory options for all affected
entities under the alternative baseline scenario.
"EPA assumes small dischargers (less than approximately 100 BPD) will transport produced
water/TWC to commercial facilities and estimates compliance costs accordingly (see EPA's
Development Document).
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The costs presented here are annualized costs. EPA has estimated these costs using the
capital and O&M costs presented in the Development Document and the methodology described
in Chapter Four.
Under the assumptions stated above, EPA estimates that the annual costs of meeting
zero discharge requirements for the Louisiana Open Bay dischargers will total $28.1 million. The
annual costs of meeting zero discharge for the Texas Individual Permit applicants will total $6.1
million.14 Total costs under the alternative baseline are calculated by combining: 1) Louisiana
Open Bay discharger and Texas Individual Permit applicant costs to meet produced water
requirements with 2) zero discharge costs for certain Gulf coastal wells that might discharge
TWC wastes in the absence of the Coastal Guidelines (see EPA's Development Document) to
meet Option #2 TWC requirements (zero discharge) and 3) the costs for the Major Pass and
Cook Inlet operations to meet Option #2 produced water/TWC requirements (zero discharge all
except for discharge limitations, Cook Inlet) and (for Cook Inlet only) Option #\ drilling waste
requirements (which is a no cost option). This last cost includes an additional $2.5 million per
year to reflect the increased cost -to one Major Pass discharger under the assumption of the
alternative baseline. EPA estimates total alternative baseline costs of BAT and NSPS (for TWC
waste only) to be $52.9 million.15 Table 10-4 summarizes these costs. Note that these
compliance costs are pretax costs and include costs to baseline and first-year shut-ins to install
and operate pollution control equipment, costs that will not be incurred in reality.16 These costs
therefore represent a worst-case estimate of impacts on the Louisiana Open Bay dischargers and
the Texas Individual Permit applicants.
The losses in NPV, discussed in Chapter Five and Section 10.3 of this FEIA, are a better
estimate of the actual costs faced by producers. Loss in NPV is the difference between baseline
"Based on costs presented in EPA's Development Document. Costs are calculated on the
basis of a facility's produced water flow.
"Includes $0.6 million for costs associated with zero discharge under NSPS requirements for
TWC wastes.
"In place of compliance costs, first-year shut-in facilities or platforms will experience
production losses, which are accounted for in Chapter Five and Section 10.3 of this FEIA.
10-14
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TABLE 10-4
TOTAL ANNUAL POLLUTION CONTROL COSTS UNDER THE
ALTERNATIVE BASELINE SCENARIO (BAT AND NSPS COSTS')
($ Millions 1995)
Option
Texas
Individual
Permit
Dischargers
Louisiana
Open Bay
Dischargers
Total
Texas/Louisiana
Dischargers
Total
Current
Regulatory
Baseline
Total
Alternative
Baseline
Scenario
; - Fi«AM^ Water/TWC _ '
Option #1
Option #2
Option #3
$6.1
$6.1
$6.1
$28.1
$28.1
$28.1
$34.2
$34.2
$34.2
$3.7
$18.1
$50.3
$37.9
$52.3
$84.6
-•'*'« Drilling Waste > '" ' -
Option #1
Option #2
$0
$0
$0
$0
$0
$0
$0
$9.2
$0
$9.2
| Total Selected Options
Option #21
Option #1
NSPS
Total
Selected
NSPS and
BAT
$6.1
—
$6.1
$28.1
—
$28.1
$34.2
—
$34.2
$18.1
$0.6
$18.6
$52.3
$0.6
$52.9
'Includes an additional $2.5 million for a Major Pass discharger under the assumptions of the
alternative baseline.
Source: ERG annualizations based on costs presented in EPA's Development Document.
10-15
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and postcompliance NPV, where NPV is the sum of all cash inflows (revenues) minus the sum of
all cash outflows (including any O&M compliance costs, capital expenditures, taxes, etc.) for a
facility or a platform in present value terms. In postcompliance, revenues are reduced by
production losses and cash outflows are increased by the post-tax expenditures on compliance
costs (both O&M and capital costs). If a facility or platform shuts in in the first year, NPV
losses will account for the loss of production but will not account for any compliance costs.
Because the operator is assumed to make an economically rational decision, the NPV losses in
this case will be less than the compliance costs estimated for the facility or platform.
10.3 PRODUCTION LOSS ANALYSIS IN THE ALTERNATIVE BASELINE SCENARIO
103.1 Description of the Economic Model for the Louisiana Open Bay and Texas
Individual Permit Operators
EPA bases its estimates of impacts on the Louisiana Open Bay and Texas Individual
Permit operators on analyses conducted at the well level, rather than at the platform/facility
level, which is the case for the Cook Inlet and Major Pass operators.17-18 The Agency
estimates that approximately 1,206 productive wells in the Louisiana Open Bay and Texas
Individual Permit categories (603 in each group) would be discharging produced water into
coastal subcategory waters through one of the permitted treatment/separation facilities (under
the assumptions discussed in Section 10.2 above).19
"Appendix C provides a line-by-line description of the Open Bay/Individual Permit
production loss model.
18EPA obtained data on wells identified as part of the Louisiana Open Bay and Texas
Individual Permit Applicant dischargers group from the Section 308 Survey. The survey gathered
data and survey weights were developed on a well basis. EPA found that determining facility-
based statistical weights using the well-based weights might not lead to satisfactory estimates. A
well-based approach tends to be more conservative than a facility-based approach since all wells
are assumed to support their share (based on produced water volumes) of the pollution control
costs (see discussion later in this section).
19For purposes of this analysis, facilities are defined in terms of outfalls. This definition may
not match the definition used in the Development Document. This difference, however, has no
(continued...)
10-16
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To assess Open Bay discharger/Individual Permit Applicant economic impacts, EPA uses
Section 308 Survey data, which contains a stratified sample of all wells operating in the region.
Results from the analysis of each individual well have been weighted using Survey weights and
then used to represent all 1,206 wells, as discussed in Section 10.1. Production and operations
cost data, typical production and decline rates, oil and gas selling prices, and other model inputs
in the analysis were taken from responses to the Section 308 Survey. For missing data or
outliers, EPA substituted the average values calculated over the affected group. Where
necessary, costs and prices have been inflated to 1995 dollars for comparison and inclusion with
Cook Inlet/Major Pass impacts.
The Open Bay/Individual Permit model is similar to that used in examining the Cook
Inlet and Major Pass operations, described in Chapter Five. Nevertheless, some basic differences
exist between the two models.
As in the Cook Inlet/Major Pass analysis, incremental costs for produced water disposal
are based on engineering and operating expenses that would be incurred by a production facility
complying with the regulation. To distribute pollution control costs at the well level in the Open
Bay/Individual Permit model, capital costs for compliance equipment are annualized over a 10-
year period at 7 percent and added to annual operating and maintenance costs for compliance to
compute an annual cost. This cost is divided by the total permitted discharge volume of the
treatment facility to establish a cost per barrel of produced water that can be applied to the
produced water volume that each well generates. Pollution control costs in the Open
Bay/Individual Permit model thus become variable costs, as if all produced water were disposed
of on a commercial basis.
Each well is assumed to produce a constant total combined volume of oil (in BOE, with
gas converted to BOE), and water over its lifetime (see Appendix C). As the volume of oil (in
BOE) declines, water production increases commensurately. Thus, the increase in the total
volume of produced water is assumed to equal the decrease in total volume of oil (in BOE)
"(...continued)
effect on any analysis in which permit and facility are assumed equivalent for the purpose of
estimating zero discharge costs.
10-17
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produced (which declines an average of 15 percent per year). Since annual compliance costs are
calculated by multiplying the annual produced water volume by the estimated compliance costs
per barrel of produced water, annual compliance costs increase at a rate related to the decrease
in oil and gas production.20
Furthermore, since the Open Bay/Individual Permit model is designed to investigate the
effects of the regulation on the productive lifetime of a single well rather than on a facility, EPA
does not use increases in production and costs due to drilling of new and recompleted wells in
analyzing the facilities among the Louisiana Open Bay and Texas Individual Permit applicant
dischargers as was done for Major Pass and Cook Inlet discharging operations.
Developmental wells, if drilled, are likely to be connected to an existing treatment/
separation facility. Operators of these new wells will face a very small cost to treat and inject the
increases in produced water, so incremental costs for developmental wells will be relatively small.
If a developmental well is reasonably successful, the oil and gas from that well will support the
increased compliance costs for many years and thus impacts are likely to be small. EPA's
analysis of Major Pass dischargers, for example, showed that when development was included in
the model, impacts from pollution control costs that would occur without development were
minimized.21 If a well is not successful, it will not be produced, and therefore little expense for
produced water disposal will be incurred. Some effects could be felt if development wells were
found to be marginal producers, in which case they could shut in a little sooner under the
Coastal Guidelines than they would without the rule, or some wells that would produce in the
baseline might not produce. However, because this would occur only with marginal producers,
only small increased costs would be sustained and little production would be lost.
20As in Chapter Five, baseline O&M costs (i.e., O&M costs exclusive of compliance costs) are
held constant because, if a well produces a constant volume of oil (in BOE) and water
(combined) every year, EPA assumes that the baseline costs of production will remain constant
also.
"Major Pass Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
10-18
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10.3.2 Produced Water/TWC
10.3.2.1 Louisiana Open Bay Operators
Baseline (Current Practice)
EPA's baseline analysis suggests that 37 of the 603 Louisiana Open Bay wells are not
economical independent of this rule and are likely to have been shut in since the Survey was
conducted.22 EPA estimates total lifetime production from the remaining 566 wells to be 72.2
million discounted BOE (102.6 million total BOE) at baseline. The productive lifetimes of
these wells total 8,801 years, or an average of 15.6 years per well for wells remaining open for
one year or more (see Chapter Five and Appendix C for a more complete description of how a
shut-in is determined).
EPA estimates that the present value of the Open Bay projects' net worth (NPV),
assuming constant real wellhead prices, is $525.7 million (see Table 10-5 for a summary of
baseline data; see Chapter Five for a discussion of NPV). The present value of federal income
taxes collected over the economic lifetime of the Open Bay wells is $190.5 million. The present
value of severance tax collected is $167.4 million. Royalties (present value) paid to the states
and other leaseholders are $173.6 million.
Options #1, #2, and #3 (Zero Discharge)
Regulatory options #1, #2, and #3 all require zero discharge in the Louisiana Open
Bays. When the compliance costs associated with meeting zero discharge requirements for
produced water in the Louisiana Open Bays are added to the baseline operating costs for the
model wells, 47 wells are estimated to shut in immediately23 (in addition to those that close in
22See Sections 10.3.2.4 and 10.3.2.5 for a sensitivity analysis of baseline shut ins and other
results presented below.
"Using alternative cost sharing assumption, EPA determined that no wells shift in post
compliance (Sensitivity Analysis of Alternative Cost Sharing Assumptions; CBI data in
(continued...)
10-19
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TABLE 10-5
IMPACTS OF PRODUCED WATER OPTIONS
ON LOUISIANA OPEN BAY DISCHARGERS AND TEXAS INDIVIDUAL PERMIT APPLICANTS (1995 $)
Type oTljnpact
Projected lifetime dijeounted production (PVBOE)
Ctae&i in discounted production (PVBOE)
Percentage ch*nge in discounted baseline production
Loulihm* Open B*yi
Baseline Option* #1, «,& «3
Current Practice Zero Dlschame
72,244,438
67,141,433
5.103,005
7.1%
Texas Individual Permits
Satellite Options #1, m, & *3
Current Practice Zero Discharge
55,613,281
53,175,133
2,438,149
4.4%
" > 1 ' Si*^ <* ^< ^ ^ ff-f' c /-V ^S\ < *• ;J, ^ ft \ V ., , j '
• > •• , ' , , * * >> fe$> ,' ' » ' '>" ' *
Total projected lifetime production (BOB)
Gunge in totil projected lifetime production (BOB)
Percentage change in total baseline production
102,622.481
93,698,270
8,924,211
8.7%
78,991,876
75,147,547
3.844,330
4.9%
is » >"*<•.» <•-» /• /• -• >• > y v
Proa* value of project net worth (NPV) ($000)
Change in NPV (SOOO)
Percentage change in NPV
. i > >y >
Productive wells in analysts
Baseline closures
Poxtcompliance closures
$525.656
$433,863
$91,794
17.5%
$335,943
$301.058
$34.885
10.4%
">*• v y :
603
37
—
603
_
47
603
367
—
603
_
47
\ ^ " / ' ' '
Total production lifetime (years)
Change in total production lifetime
Percentage change
L " "''•," V * i, * ,\ v
Avenge lifetime (years, among wells not shutting-in in 1st year)
Change in average lifetime (among wells not shutting-in in 1st year)
Percentage change
8,801
4,978
3,824
43.4%
2,856
2,067
789
27.6%
; ', , , /f , " 'i'.""-x""-.-f.{i'< ' - ' '• ' " "" ***•.
- " ' "•> ' < '
15.6
9.6
6.0
38.3%
12.1
10.9
1.1
9.4%
""*,„,-. ™'> % ,. / ' - * <^ ^ ^- ] ^,j, ,,r mj „ -Ss 4, ' ,,, ''-;„",, > , / ' ,-•>,, ; ;
Present value of severance and state income taxes collected ($000)
Change in present value of severance and state income taxes ($000)
Percentage change in severance and state income taxes
$167,355
$149.530
$17,826
10.7%
$44,599
$42,649
$1,950
4.4%
» > < *"~> s Kliy^ ;
Present value of federal income taxes collected ($000)
Change in present value of federal income taxes ($000)
Percentage change in federal income taxes
$190,541
$162,904
$27,637
14.5%
$128,346
$119,235
$9,110
7.1%
* f '} ' ''',, , * '•;:•"'•',/.„ ' ' , , '' "' *'*'" "Tf ' '' " "' " ", ' /" ' '-'' ''.
Piesent value of royalties collected ($000)
Change in present value of royalties ($000)
Percentage change in royalties
$173,610
$155.944
$17,666
10.2%
$120,134
$112,655
$7,479
6.2%
Note: Results are weighted using well survey weights and adjustment factors noted in the text
Source: Louisiana Open Bay Dischargers and Texas Individual Permit Applicants Production Loss Model Runs (CBI data; in rukmaking record).
10-20
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the baseline). These first-year shut-ins, combined with a reduction in the total economic lifetime
of the remaining wells from 8,801 years to 4,978 years (a 6.0 year change in average lifetime per
well), leads to declines in production totaling 5.1 million discounted BOB (8.9 million total
BOE), or a decline of 7.1 percent in present value baseline production. This production loss is
associated with a $91.8 million loss in the present value of project net worth (17.5 percent).
The present value loss in federal income taxes collected is $27.6 million, or 14.5 percent
of baseline present value federal income tax. Present value losses in severance and state income
taxes are estimated at $17.8 million (10.7 percent of baseline), and present value losses in
royalties collected are estimated at $17.7 million (10.2 percent of baseline). Table 10-5
summarizes these impacts.
In response to comments suggesting that a zero discharge requirement might have
substantially lower impacts if its application to the Louisiana Open Bay dischargers were delayed,
EPA calculated total production losses from operations shutting in under a zero discharge
requirement in Years 1 through 5.24 EPA estimates that total production losses would be
reduced by 3.5 million PVBOE (4.9 million nondiscounted BOE), or 4.8 percent of total baseline
production (PVBOE) from the Louisiana Open Bay dischargers, if these operators were allowed
to discharge for five more years. That is, among Louisiana Open Bay dischargers, approximately
69 percent of production losses would be avoided with a five-year delay.
^(...continued)
rulemaking record). Postcompliance results change slightly: losses increase, but the percentage
of losses decrease due to increased baseline production.
24Sensitivity Analysis of Delays in Implementation of Coastal Guidelines for Texas Individual
Permit applicants and Louisiana Open Bay Dischargers (CBI data; in rulemaking record).
10-21
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10.32.2 Texas Individual Permit Operators
Baseline (Current Practice)
EPA estimates that 367 of the 603 Texas Individual Permit wells are baseline closures
(i.e., they are expected to close before compliance costs are incurred).25 The remaining 236
wells are estimated to yield lifetime production of 55.6 million discounted BOE (79.0 million
total). The productive lifetimes of these wells total approximately 2,856 years, or 12.1 years per
well remaining open for one year or more (see Chapter Five and Appendix C for how a shut-in
is determined).
EPA's baseline analysis indicates that the present value of the projects in the Texas
Individual Permit category is $335.9 million. The present value of federal income taxes collected
is $128.3 million, the present value of severance taxes collected is $44.6 million, and the present
value of royalties collected is $120.1 million.26
Options #1, #2, and #3 (Zero Discharge)
EPA estimates that 47 Texas Individual Permit applicant wells will shut-in as a result of
going to zero discharge, as required under all three options. The resulting decline in production
among the Texas Individual Permit wells is estimated to be 2.4 million discounted BOE (3.8
million total, nondiscounted BOE), a 4.4 percent decrease from baseline discounted BOE
production. The change in project present value (NPV) is estimated at $34.9 million, or 10.4
percent. Total productive lifetime of the wells in this category drops from 2,856 years to 2,067
years (from 12.1 years average to 10.9 years average per well).
"See Sections 10.3.2.4 and 10.3.2.5 for a sensitivity analysis of baseline shut ins and other
results presented below.
2SNo state income tax is applied to oil and gas revenues in Texas.
10-22
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EPA estimates other losses associated with a zero discharge requirement as follows: $9.1
million in present value federal income taxes (7.1 percent); $2.0 million in present value
severance taxes (4.4 percent); and $7.5 million in present value royalties (6.2 percent). Table
10-5 details these losses.
As with the Louisiana Open Bay dischargers, EPA calculated total production losses from
Texas Individual Permit applicants shutting in under a zero discharge requirement in Years 1
through 5. EPA estimates that total production losses would be reduced by 2.2 million PVBOE
(3.1 million nondiscounted BOB), or 4.0 percent of total baseline production (PVBOE) and 92
percent of the compliance cost of related decreases in production (PVBOE), if the Texas
Individual Permit operators were allowed to discharge for five more years.
10.32.3 Combined Impacts
Table 10-6 shows the total produced water guidelines impacts for the Louisiana Open
Bay and Texas Individual Permit dischargers combined. Since all three regulatory options
require zero discharge of produced water from these operations, postcompliance results can be
summarized in a single column.
Table 10-7 presents the impacts on Major Pass dischargers under the assumptions of the
alternative baseline. As the table shows no additional production losses occur, but NPV declines
from losses shown in Chapter Five (see Table 5-5).
Table 10-8 presents the impacts of the three produced water options on the alternative
baseline as a whole (Louisiana Open Bay and Texas Individual Permit dischargers, Cook Inlet
platforms, and Major Pass facilities). Although the Louisiana Open Bay and Texas Individual
Permit operators incur the same costs (in terms of lost revenue and production) for all three
regulatory options, the aggregate costs for the alternative baseline increase with option number
10-23
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TABLE 10-6
IMPACTS OF PRODUCED WATER OPTIONS (1995 S)
(LOUISIANA OPEW BAY DISCHARGERS AND TEXAS INDIVIDUAL PERMIT APPLICANTS COMBINED)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
, X *",<*•'
Total projected lifetime production (BOE)
Change in total projected lifetime production (BOE)
Percentage change in total baseline production
": t- ='-*- j:*;';;*. U-.=l; £;";", >«*,.tr...,K....;. :•.-•:: '
Present value of project net worth (NPV) (SOOO)
Change in NPV (SOOO)
Percentage change in NPV
Total Louisiana and Texas
Baseline
Current Practice
127,857,719
Options #1, #2, & #3
Zero Discharge
120,316,566
7,541,153
5.9%
A :
181,614,357
168,845,817
12.768,541
7.0%
J \ 3 !
5861,599
5734,921
5126,678
14.7%
1 I X
^ 1 -•
Productive wells in analysis
Baseline closures
Postcompliance closures
1,206
404
__
: " ™
Total production lifetime (years)
Change in total production lifetime
Percentage change
11,657
1,206
_
94
V.
7,045
4,612
39.6%
2 "* "% X> J rtft''
Average lifetime (years, among wells not shutting-in in 1st year)
Change in average lifetime (among wells not shutting-in in 1st year)
Percentage change
15
10
5
31.5%
;^:n:^"K;:i!S««Bh-i:!U:UH"::ii:;S;in;:iiJ;-ii^
Present value of severance and state income taxes collected (SOOO)
Change in present value of severance and state income taxes (SOOO)
Percentage change in severance and state income taxes
5211,954
5192,178
519,776
9.3%
iijaijlpgplllp
Present value of federal income taxes collected (SOOO)
Change in present value of federal income taxes (SOOO)
Percentage change in federal income taxes
• * ;. :uu:"uu:i':uu":::^:»;ii^:u:2^::^:}:::::»::::^:^&^:::;::: ""::?:?::::-:. ::::::.. ::":-:::::^:
.,,,,,, ,,,.^,._..;;;.^
Present value of royalties collected (SOOO)
Change in present value of royalties (SOOO)
Percentage change in royalties
5318,887
5282,139
536,747
11.5%
yi:;^||p;n^jg;:|:gp||jj|jpn^|i|::l|i?|^
5293,744
5268,599
525,145
8.6%
Note: Results are weighted using well survey weights and adjustment factors noted in the text.
Source: Louisiana Open Bay Dischargers and Texas Individual Permit Applicants Production Loss Model Runs
(CBI data; in rulemaking record).
10-24
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TABLE 10-7
IMPACTS OF PRODUCED WATER OPTIONS
ON MAJOR PASS FACILITIES
UNDER THE ALTERNATIVE BASELINE ASSUMPTIONS (1995 S)
Type of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Baseline
Current Practice
434,713,377
—
—
Gas Flotation
Option #1
434,713,377
0
0.0%
Zero Discharge
Options #2 and 83
432,592,658
2,120,719
0.5%
•• "^ -r JV____ A ^
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOB)
Percentage change in discounted baseline production
599,860,713
—
_
599,860,713
0
0.0%
596,461,487
3,399,226
0.6%
v i
Present value of project net worth (NPV) (SOOO)
Change in NPV(SOOO)
Percentage change in NPV
$1,459,603
—
_
$1,457,042
$2,560
0.2%
Sl.398,504
$61,099
4.2%
^ '" „ - - • " ' -> ' '«
Number of facilities ceasing production in first year (postcompiiance)
Total number of production years (1997 on)
Average production years per facility (all facilities)
Average production years per facility (nonclosing facilities)
Total production years lost among closing facilities
Total production years lost among nonclosing facilities
0
82
10.3
10.3
—
_
0
82
10.3
10.3
0
0
0
79
9.9
9.9
0
3
-, x * *•
Present value of severance and state income taxes collected (SOOO)
Change in present value of severance and state income taxes (SOOO)
Percentage change in severance and state income taxes
$399,427
—
—
$399,259
$168
0.0%
$392,701
$6,726
1.7%
i •. ^ f ' -•* ': ~" f
J f -J ft '• ~t f '
Present value of federal income taxes collected (SOOO)
Change in present value of federal income taxes (SOOO)
Percentage change in federal income taxes
$752,818
__
_
$751,987
$832
0.1%
$734,863
$17,956
2.4%
1 >"f
Present value of royalties collected (SOOO)
Change in present value of royalties (SOOO)
Percentage chance in royalties
$815,892
_
—
5815,892
SO
0.0%
$809,434
$6,458
0.8%
Source: Major Pass Dischargers Production Loss Model Runs (CBI data; in rulemaking record).
10-25
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10-26
-------
because costs for the Cook Inlet and Major Pass producers increase (discussed in Chapter
Five).27 As in Chapter Four, NPV analyses combine compliance costs and production losses.
However, compliance costs for baseline and first year shut-ins are not included in NPV figures;
these costs are included in the compliance cost analysis in Section 10.2.
As in Chapter Five, because Option #1 for drilling wastes is a no-cost option, the impacts
of the selected options (Option #2 for produced water and Option #1 for drilling wastes) are
the same as those for Produced Water Option #2 alone (see Table 10-9). Option #2 requires
that Louisiana Open Bay and Texas Individual Permit dischargers and the Major Pass facilities
achieve zero discharge of produced water; Cook Inlet platforms may continue to discharge,
provided that they meet discharge limits equivalent to those for offshore operations.
The selected options are associated with 94 wells, but no platforms, shutting in relative to
the alternative baseline. These 94 wells include 47 wells each in the Louisiana Open Bay and
Texas Individual Permit categories. Losses in production under the selected options total 10.7
million discounted BOE (1.2 percent of total discounted BOE production at baseline) or 18.6
million total, non-discounted BOE. Present value losses in project net worth total $190.6 million,
or 6.0 percent of baseline project NPV among the four alternative baseline groups. Note that
these losses include the producers' share of compliance costs (post-tax costs).
The present value of federal income taxes lost is estimated at $57.2 million, or 3.8
percent of total federal taxes collected under the baseline scenario. The present value of state
and severance taxes lost is estimated at $25.9 million (3.4 percent of baseline state and severance
taxes collected). Finally, the present value of royalties lost to the states and other leaseholders
amounts to $33.6 million, or 2.2 percent of projected baseline royalties. The total present value
impacts of the selected options on the alternative baseline are estimated to be $307.3 million.
Note that EPA considers additional impacts due to regulation of TWC wastes to be negligible
(see Chapter Five in this FEIA).
"Also note the small change in the Major Pass analysis due to higher costs of compliance
assumed under the alternative baseline.
10-27
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A more appropriate comparison is provided in Table 10-8 under the combined effects of
compliance. In this table, the impacts on the affected operations are compared to a baseline that
includes the entire coastal subcategory (without California and North Slope, Alaska), which
includes the many operators who have already achieved zero discharge.28
Table 10-9 indicates that losses under the alternative baseline represent a very small
portion of production, revenues, taxes, and royalties for all coastal oil and gas operations
(excluding California and North Slope, Alaska). Under the selected options, lifetime production
losses (both discounted and nondiscounted BOE) for the alternative baseline groups amount to
0.6 percent of total coastal production. NPV losses represent 4.2 percent of total coastal NPV.
Other losses, as percentages of amounts estimated for all coastal oil and gas operations, are as
follows: 1.1 percent of severance and state income taxes, 2.4 percent of federal income taxes,
and 0.6 percent of royalties.
10.32.4 Sensitivity Analysis #1: Deletion of Suspect Data
EPA conducted a sensitivity analysis based on the deletion of suspect data. Two wells in
the above analysis were believed to have faulty data. Unfortunately, these wells had very large
survey weights and were estimated to represent about 200 wells overall (which is why the total
number of baseline shut-in wells in Texas was so large in the preceding analysis). EPA removed
these two wells from the analysis because their reported oil and gas production at the facility
level would not support the operating costs reported, so the reported figures are not credible.
Results from analysis of the remaining wells were extrapolated to represent the 200 wells instead.
Thus the total number of wells (603) remained the same, but the number of wells used to model
the total number of wells in Texas was reduced by two. The results of this analysis show a visible
increase in the baseline production (3.6 million PVBOE versus 55.6 PVBOE).29 All
"Several court cases have established that the whole industry is the proper universe for
comparing impacts.
^Sensitivity Analysis of Alternative Cost Allocation Assumptions for Louisiana Open Bay
Dischargers and Texas Individual Permit Applicants.
10-28
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10-29
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percentages remain the same as those seen in Table 10-5, but the absolute value of losses goes
up (e.g., $5.8 million lost NPV vs. $3.8 million lost NPV). Additionally, the number of baseline
shut ins changes from 367 to 247 for Texas and post-compliance shut ins change from 47 to 72
(these numbers change because baseline and post-compliance shut ins are distributed over the
200 wells represented by the suspect data).
EPA believes, however, that this analysis (as well as the original analysis) is too
conservative because all wells are assumed to be required to support themselves independent of
any other wells that might be served by the same facility. EPA has addressed the unnecessary
conservatism of the original analysis and this sensitivity analysis by running another sensitivity
analysis, which is described below.
10.3,2.5 Sensitivity Analysis #2: Alternative Cost Allocation at Facility Level
In the original production loss analysis, EPA has assumed that all wells must support
themselves and has conservatively calculated that each well well's baseline O&M costs on the
basis of the operator's average per-well O&M costs. Furthermore, EPA has assumed that the
per-well cost of compliance is allocated on the basis of the volume of produced water generated
by each well. At the treatment/separation facility level, however, marginal wells may be kept
operating long past the point at which they can support themselves because their production
continues to add to the NPV of the project as a whole (that is, in cases in which a facility
handles a relatively large volume of oil and gas production, the larger producing wells can more
than carry the costs of a few marginal wells).
This approach is substantiated by a very recent data submittal from the Texas Railroad
Commission.30 Although EPA could not perform a detailed analysis of these data before final
action on the rule, a preliminary analysis showed that they support an assumption that facilities
with substantial production serve a number of marginal wells that might have shut in earlier had
30EPA received data from the Texas Railroad Commission less than 1 week before signature
of the Coastal Guidelines (facsimile transmittal from Leslie Savage, 10/24/96).
10-30
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they been associated with single-well facilities or facilities with less production. The majority (76
percent) of the facilities listed in the data submittal were multiple-well facilities and/or served
several leases. EPA noted a typical configuration in which one or two wells contributed the
majority of production to the facility, with three or four additional wells providing marginal
amounts of oil (10 bbls/day or less). A few wells were very marginal, with daily oil production
under 2 bbls/day. Under EPA's previous assumptions, wells with this little production often were
modeled as baseline shut-ins. EPA believes the configurations shown in the data support a
facility-based approach, thus EPA's well-based approach is unnecessarily conservative.
In light of the high number of baseline shut-ins predicted in the previous analysis and the
new data submittals from the Texas Railroad Commission, EPA looked more closely at each and
every baseline shut-in well. EPA determined that many of the baseline shut-in wells are
marginal, served by facilities with substantial levels of production (several hundreds of thousands
of BOE, or more, per year). Then, instead of assuming that these marginal wells have average
operating costs for the operator, EPA used the average operating cost per well and the number
of wells at the facility reported in the Section 308 Survey to calculate a facility-level operating
cost. EPA apportioned this operating cost to the well on the basis of each well's share of total
facility production (i.e., if the facility produced 100,000 BOE annually and the well produced
1,000 BOE annually, the well would be assigned 1 percent of the operating costs).31 Under
such assumptions, many of the marginal, baseline shut-in wells were apportioned just a small
fraction of these facilities' operating costs. In nearly all these cases, EPA found that the wells
identified as baseline shut-ins in the well-based analysis no longer shut in, either in the baseline
or postcompliance, even when supporting a share of compliance costs allocated on the basis of
produced water flow. The few that could not support a share of compliance costs allocated on
the basis of produced water flow could support compliance costs allocated on the basis of
production (with the exception of a few wells in Louisiana representing the 16 post-compliance
"Sensitivity Analysis of Alternative Cost Allocation Assumptions for Louisiana Open Bay
Dischargers and Texas Individual Permit Applicants (CBI data in rulemaking record).
10-31
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shut in wells). Table 10-10 shows the results when operating costs (and, in rare instances,
compliance costs) for some wells are reallocated on the basis of production levels.32
Table 10-10 can be compared to Table 10-5. As these tables show, lifetime production is
slightly higher in Louisiana and substantially higher in Texas under the alternative facility-level
cost allocation assumptions (103.1 BOB vs. 102.6 BOB in the original analysis for Louisiana and
121.0 BOB vs. 79.0 BOB in Texas). This occurs because the number of baseline shut-ins drops
dramatically, from 367 in Texas to 8, and from 37 in Louisiana to zero; therefore, all of these
wells that do not shut in continue producing. Furthermore, the number of postcompliance shut-
ins also drops substantially, from 47 in each state to zero in Texas and 16 in Louisiana.33
Overall, production and total dollar losses by category (i.e., NPV, taxes, royalties) drop in
Louisiana, although they rise slightly in Texas (due to the greater baseline production), but both
states show a reduction in the percentage losses for BOB, PVBOE, NPV, severance and state
taxes, federal taxes, and royalties. Significantly, there are no shut ins and therefore no Type 3
loss of local employment; see Section 10.5.
Table 10-11 shows the results for both Texas and Louisiana combined, which can be
compared to the results in Table 10-6. Overall, total baseline production for the two states
combined is increased and, while the total losses resulting from the rule are slightly higher, the
percentages lost are lower.
Because EPA made some simplifying assumptions by only adjusting operating costs for
wells that were baseline shuts in in the previous analysis as well as adjusting operating and
compliance costs for a few post-compliance wells that shut-in, these results may slightly
understate baseline shut ins and overstate baseline production. EPA believes that, given the data
32This analysis also uses the adjustments to data made in sensitivity analysis #1, in which two
wells in the survey that shut in in the baseline believed to be associated with suspect data were
removed from the analysis.
33The numbers of baseline and postcompliance failures are more compatible with the results
that EPA generated using the facility-based analysis than were the results of the previous analysis
(Facility-Based Analysis of the Texas Individual Permit Applicants and Louisiana Open Bay
Dischargers; CBI data in rulemaking record).
10-32
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TABLE 10-10
IMPACTS OF PRODUCED WATER OPTIONS
ON LOUISIANA OPEN BAY DISCHARGERS AND TEXAS INDIVIDUAL PERMIT APPLICANTS,
RESULTS OF SENSITIVITY ANALYSIS USING ALTERNATIVE COST ALLOCATION ASSUMPTION (199S S)
Louisiana Open Bays
Baseline Options #1, #2, & M3
Type of Impact Current Practice Zero Discharge
Projected lifetime discounted production (PVBOE) 72,561.217
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
67.616,454
4,944,764
6.8%
Texas Individual Permits
Baseline
Current Practice
85,325,401
Options M, #2, &*3
Zero Discharge
82,372,135
2,953,266
3.5%
f ™
Total projected lifetime production (BOE) ' 103,117,736
Change in total projected lifetime production (BOE) :
Percentage change in total baseline production
94.260.289
8,857,446
8.6%
120,996,365
116.055,260
4,941,105
4.1%
- - - c" r -'
Present value of project net worth (NPV) (SOOO) $529.094
Change in NPV (SOOO)
Percentage change in NPV
$435.518
$93,576
17.7%
$513,415
1
Productive wells in analysis 603
Baseline closures 0
Postcompliance closures —
603
_
16
603
8
_
$462.445!
S50.969
9.9%
*
603 1
—
0
„
Total production lifetime (years) • 9,641
Change in total production lifetime
Percentage change
5,276
4.365
45.3%
6,375
5.198
1,177
18.5%
^•?::J:::;:::^i;HiHir"iiH::iS:i::fii:::::H:H-:ri:::i-:::;::::::?-:^:M-:S::::::::::v:::: •' :;:;j:K!Sj:S|t::t:;;::$:g:.:j^{[j:;::;K:;:::^
Average lifetime (years, among wells not shutting-in in 1st year) 16.0
Change in average lifetime (among wells not shutting-in in 1st year)
Percentage change
9.0
7.0
43.8%
10.7
8.7
2.0
18.5%
" ••
Present value of severance and state income taxes collected (SOOO) $168.551
Change in present value of severance and state income taxes (SOOO)
Percentage change in severance and state income taxes
$150.840
SI 7,711
10.5%
$68,361
$66.082
S2.278
3.3%
}ii:;iSU::::nh::::f:iH!:S;::::;::::::::;i:;:::::;:;:::::"'::::Kf:;=f:-:::-i:^i:Kii::::-;::::.. ••-l-ll^lill-^KK-l-i-ytl-m^l^x^m^
Present value of federal income taxes collected (SOOO) 5192,280
Change in present value of federal income taxes ($000)
Percentage change in federal income taxes
SI 63.598
S28.681
14.9%
$195,269
$182,419
S1Z850
6.6%
_r
Present value of royalties collected (SOOO) $173.732
Change in present value of royalties ($000)
Percentage change in royalties
$156,737
SI6.994
9.8%
$184,498
S175.734
S8.764
4.8%
Note: Results are weighted using well survey weights and adjustment factors rioted in the text.
Source: Sensitivity Analysis of Alternative Cost Allocation Assumption for Louisiana Open Bay Dischargers and Texas Individual Permit Applicants.
10-33
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TABLE 10-11
IMPACTS OF PRODUCED WATER OPTIONS, RESULTS OF SENSITIVITY ANALYSIS
USING ALTERNATIVE COST ALLOCATION ASSUMPTION (1995 $)
(LOUISIANA OPEN BAY DISCHARGERS AND TEXAS INDIVIDUAL PERMIT APPLICANTS COMBINED)
Tvpe of Impact
Projected lifetime discounted production (PVBOE)
Change in discounted production (PVBOE)
Percentage change in discounted baseline production
Total Louisiana and Texas
Baseline
Current Practice
157,886,618
Options #1, #2, & #3
Zero Discharge
149,988,589
7,898,030
5.0%
^in::::!;:-;!ui:ji;;Hi[:;j^^
Total projected lifetime production (BOB)
Change in total projected lifetime production (BOE)
Percentage change in total baseline production
224,114,100
210,315,549
13,798,551
6.2%
rf:3 j M j x 5
't ~~ X ;
Present value of project net worth (NPV) (SOOO)
Change in NPV(SOOO)
Percentage change in NPV
Sl.042,509
S897.965
S144.544
13.9%
5 ' Tf
Productive wells in analysis
Baseline closures
Postcompliance closures
1,206
8
_
1.206
—
16
• •* 3 : 3 *" a* ess s:^: : »j A
Total production lifetime (years)
Change in total production lifetime
Percentage change
16.017
10.474
5,542
34.6%
, s > J, , i :: K J J i 1 " ^ ' '
Average lifetime (years, among wells not shutting-in in 1st year)
Change in average lifetime (among wells not shutting-in in 1st year)
Percentage change
13
9
5
33.8%
5, , -, <
Present value of severance and state income taxes collected (SOOO)
Change in present value of severance and state income taxes (SOOO)
Percentage change in severance and state income taxes
5236,911
$216,922
519,989
8.4%
Li^PiH-iPiiillilHilKp&i'Bij,, /
Present value of federal income taxes collected (SOOO)
Change in present value of federal income taxes (SOOO)
Percentage change in federal income taxes
5387,548
$346.017
541,531
10.7%
<
i : 3* : ^ ^ ' ^ ' ^ is: : :
Present value of royalties collected (SOOO)
Change in present value of royalties (SOOO)
Percentage change in royalties
$358,230
$332,472
$25,758
7.2%
Note: Results are weighted using well survey weights and adjustment factors noted in the text
Source: Sensitivity Analysis of Alternative Cost Allocation Assumption for Louisiana Open Bay Discharger.! and Texas In
and Texas Individual Permit Applicants.
10-34
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available, the results of this analysis should be a lower bound estimate of the impacts of the
Coastal Guidelines. The results of the well-level analysis are an upper bound. The Agency
believes that the actual results would be closer to those of the facility-level analysis than those of
the well-level analysis, because, first, that is how operators actually manage their operations;
second, wells shown as baseline facilities are still operating; and, third, data descriptions from the
Texas Railroad Commission support this approach.
EPA performed one additional analysis using the facility-level cost allocation assumption.
The Agency looked at the impact of creating a "stripper"-type (10 bbls/day oil production or less)
category for coastal wells, which would not have to comply with the coastal rule, and assigned
zero costs to wells producing 10 bbls/day of oil or less. This analysis was not very informative
using the baseline created under the previous assumptions of self-supporting wells, because many
of the marginal wells were determined to be baseline shut-ins. Using the alternative cost-
allocation assumptions based on facility production levels, however, EPA was able to run this
analysis, which showed slightly lower percentages of losses than those shown in Tables 10-10 and
10-11. The only major change was that the 16 Louisiana wells that shut in postcompliance
(above) would not shut in under the assumption of no costs for marginal wells. The results of
this analysis are available in the rulemaking record.34 Because the wells are marginal, their
additional longevity and production do not contribute significantly to the overall production for
the Louisiana Open Bay discharger and Texas Individual Permit applicant groups.
10.4 FIRM-LEVEL IMPACTS UNDER THE ALTERNATIVE BASELINE SCENARIO
EPA uses a similar methodology to estimate firm level impacts under the alternative
baseline as under the current regulatory baseline discussed in Chapter Six of this FEIA. Section
10.4.1 presents a review of EPA's general firm failure methodology and highlights some aspects
of the analysis tailored specifically to determining firm level impacts among Louisiana Open Bay
34Sensitivity Analysis of Assigning Zero Costs to Wells Producing 10 bbls of Oil/Day or Less
(CBI data in rulemaking record).
10-35
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and Texas Individual Permit operators. Section 10.4.2 then summarizes the results of the
alternative baseline analysis.
10.4.1 Analytical Methodology
As discussed in Chapter Six, EPA's firm failure methodology consists of three stages: a
baseline analysis, a screening analysis, and a detailed analysis. EPA undertakes a detailed
analysis only when the screening analysis indicates that an operator might incur substantial
impacts. The detailed analysis enables EPA to better determine whether the potential impacts
identified by the screening analysis are really expected to materialize.35
10.4.1.1 Baseline Methodology
The first stage of EPA's firm failure analysis, baseline analysis, is designed to eliminate
baseline failure firms from the group of firms to be examined in a postcompliance scenario.
Baseline failure firms are firms whose financial health is so precarious that they are likely to fail
even without the added costs of regulation.
EPA assessed the alternative baseline using an approach that is slightly different from
that applied to the current regulatory baseline since many more firms required analysis in the
alternative regulatory baseline. For Louisiana Open Bay and Texas Individual Permit
dischargers, EPA cross-referenced firms in the Section 308 Survey with known permit holders
identified by EPA as discussed in EPA's Development Document. Firms in both databases were
then investigated to determine the status of their equity and working capital. Working capital
and equity are expected to be especially important means of financing pollution control costs in
the Gulf region. Firms with negative equity and working capital are considered extremely weak
3SAs stated elsewhere, this rule will only be applicable to those operators when it would be
applied to them in the NPDES permitting process. This analysis is especially conservative
because the Texas Individual Permit Applicants and Louisiana Open Bay dischargers are already
subject to zero discharge.
10-36
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financially and likely to fail in the baseline. Additional baseline failures were subsequently
identified during the detailed analysis that followed the screening analysis using cash flow and
returns, among other factors, to identify financially weak firms.
10.4.1.2 Screening Methodology
EPA performed the screening analysis to identify firms for which impacts from
compliance with the regulation are likely to be significant. As noted above, for the Louisiana
Open Bay and Texas Individual Permit operators, EPA matched discharge permit holders by
name to the Section 308 Survey respondents who provided financial data. In the screening
analysis, the agency compared the annualized capital and operating and maintenance (O&M)
costs for meeting the Coastal Guidelines requirements at all facilities owned by a firm identified
as a Texas Individual Permit applicant or Louisiana Open Bay discharger facility to the equity
and working capital of the affected firm (assuming financial data are available), and calculated
the firm's percentage changes in equity and working capital.
Equity and working capital are common measures of a firm's ability to afford new
projects or acquisitions. Equity is calculated as a firm's total assets minus its total liabilities (i.e.,
its net worth). Working capital is a measure of a firm's liquidity and is equal to current assets
(typically cash or near-cash assets that can easily be liquidated) minus current liabilities (debts or
other obligations due within one year). In other words, working capital describes available cash.
If the annual cost of complying with a zero-discharge requirement contributes to a very small
percentage change in equity or working capital at a firm, it is not likely that impacts at that firm
will be substantial; i.e., the firm is not likely to fail as a result of compliance. Firms at which
both equity or working capital would change by more than 5 percent are identified by EPA as
needing further analysis. Since a firm can choose to finance some portion of compliance costs
through either equity or working capital, as long as one measure does not change more than 5
percent, impacts should be minimal.
EPA uses this screening approach to limit the number of firms in the detailed analysis by
eliminating firms from the analysis if they are expected to experience negligible impacts. By
10-37
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performing a detailed analysis on a small number of firms, EPA is able to engage in case-by-case
assessments that allow for greater analytical flexibility than a computer model and that can
circumvent some data limitations.
10.4.1.3 Detailed Analysis
EPA conducts a detailed analysis of the firms that seem to experience changes in both
equity and working capital of more than 5 percent in the screener analysis. Detailed analysis
allows EPA to better gauge whether these firms may be substantially affected by the Coastal
Guidelines, since EPA cannot conclude that the firms will experience substantial impacts based
solely on the screening analysis.
Firms showing a large drop in equity and/or working capital might not be as highly
affected by the regulation as the screener analysis initially suggests for a number of reasons:
The firms might be considered baseline failures; i.e., they might be firms that are
likely to close even without the regulation in place because of their existing poor
financial condition. These firms are eliminated from any additional analysis and
are not considered to be affected by the rule.
Wells tied into the permitted facility might currently be generating insufficient
revenue to cover operating expenses. These wells would, in this case, be
considered baseline shut-ins with associated production losses; i.e., they would be
shut in regardless of the regulation. These types of losses also are not considered
impacts from the zero-discharge requirements of the Coastal Guidelines.
The regulatory requirements might be achieved more economically by shutting in
production. This scenario is likely to result in minimal impacts when the revenue
associated with the facility is a small portion of the firm's overall revenues. It is
likely to occur, for example, when wells associated with the facility are marginal
producers, providing minimal oil or gas but large quantities of produced water. In
this case, the firm incurs the cost of plugging and abandoning the wells and loses
a small portion of revenue—an impact attributable to the Coastal Guidelines, but
potentially a much smaller impact than would be incurred if the wells were to
continue production.
The firm might be in a partnership with other firms or individuals and, thus, might
incur only a fraction of the cost to meet zero discharge.
10-38
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The (surveyed) firm might be an operator only. Costs would be passed through to
the owner companies or individuals.
If only working capital is substantially affected, and the company is an S
corporation, impacts might be overstated. It is to an S corporation's advantage to
minimize working capital amounts on balance sheets when filing taxes; thus,
balance sheet statements submitted in support of tax filings for S corporations are
assumed to be at or near yearly minimums.
The firm might have an unusually low equity or working capital situation relative
to returns. When returns are analyzed in more detail,.they may show the ability
of the company to absorb compliance costs without appreciably affecting its
financial health.
EPA uses a variety of measures in its detailed analysis to assess impacts but focuses
primarily on return on assets (ROA) and return on equity (ROE). These two ratios use net
income divided by total firm assets and equity, respectively, as measures of return on investment
in the firm. When post-compliance ROA or ROE range from adequate to good compared to
industry averages, EPA estimates that no substantial impact will occur.
EPA bases its conclusions regarding impacts on the assumption that a promise of good
returns can generally attract investment capital. ROE and/or ROA are common measures of the
profitability of the firm and the ability of the firm to attract capital. A firm with an ROA or
ROE above the lowest quartile for these ratios among the industry as a whole typically would not
be in financial jeopardy (see Section 10.1.3).
Note that because most financial data from the Section 308 Survey are confidential, the
impacts for individual companies cannot be listed by name. Summary statistics are presented
instead because the aggregated nature of the statistics maintains confidentiality.
10-39
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10.4.2 Results of Firm-Level Analysis
10,42.1 Louisiana Open Bay and Texas Individual Permit Dischargers
The results of three levels of analysis are presented here. Section 10.4.2.1 discusses the
results of baseline analysis, Section 10.4.2.2 discusses the results of the screening analysis, and
Section 10.4.2.3 discusses the results of the detailed analysis.
Baseline Analysis
Two of the 29 firms that provided detailed financial data in the Section 308 Survey and
that were identified as Texas Individual Permit applicants or Louisiana Open Bay dischargers
(6.9 percent) currently have both negative equity and negative working capital. These firms are
considered very likely to fail regardless of whether any regulatory actions are taken. Both of the
baseline failure firms are considered to be small businesses based on Small Business
Administration (SBA) Guidelines (^500 employees). Thus, the 27 remaining firms are
examined in the screening analysis.
Posicompliance Screening Analysis
In the screening analysis, all Louisiana Open Bay and Texas Individual Permit applicant
firms matched in the analytical Survey database are investigated to determine changes in equity
and working capital resulting from outlays for incremental disposal costs (produced water
disposal costs). Results are broken down by size of firm.36 Table 10-12 summarizes the results
of this analysis for the 5 large and 22 small operators.
3
-------
TABLE 10-12
CHANGES IN EQUITY AND WORKING CAPITAL ASSOCIATED WITH
ZERO DISCHARGE
(LOUISIANA OPEN BAY AND TEXAS INDIVIDUAL PERMIT DISCHARGERS ONLY)
Level of Change
Small Operators
Large Operators
Total
Caattge ill Equity
NA
<1%
1% to 5%
>10%
>5% to 10%
Total
0.00
6
9
7
22
0
5
0
0
5
0.00
11
9
7
27
Change itt Working Capital
NA
<1%
1% to 5%
>5% to 10%
>10%
Total
8
4
5
5
22
0.00
4
1
0
5
8
8
6
5
27
Source: Change in Equity and Working Capital Worksheet (CBI data; in rulemaking record).
NA = Negative equity or working capital.
10-41
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None of the 27 firms that passed in the baseline analysis reported negative equity in the
Survey. Broken down by size, all 5 of the large firms and 13 of the 22 small firms (59 percent)
are expected to experience a change in equity of less than 5 percent. The change in equity
among small firms ranges from 0.05 to 618 percent, with a median of 1.67 percent. The change
in equity among large firms ranges from 0.03 to 0.11 percent, with a median of 0.09 percent (see
Table 10-13).
Eight small firms, but no large firms, report negative working capital in the Survey.
Among those with positive working capital, seven small firms (32 percent of the small firms
analyzed) and all large firms are expected to experience changes in working capital of less than 5
percent. The change in working capital among small firms ranges from 0.07 to 220 percent, with
a median of 5.87 percent. The change in working capital among large firms ranges from 0.36 to
3.09 percent, with a median of 0.63 percent (see Table 10-13).
Table 10-14 presents the number of small firms by their changes in equity and working
capital.37 As the table shows, 9 firms have changes in both working capital and equity of more
than 5 percent. EPA selected all of these firms for further analysis. Additionally, EPA selected
three firms where, although equity changed by less than 5 percent, working capital changed
dramatically (annual pollution control costs were greater than baseline working capital) or
working capital was negative in the baseline.
Detailed Analysis
Based on the above screening analysis, EPA analyzed the 12 small firms identified above
in detail using their Survey responses in greater depth. Detailed analysis attempts to identify
conditions such as those listed above that might indicate that the Coastal Guidelines would have
different impacts than the basic analysis of equity and working capital suggests (none of the large
firms in the Louisiana Open Bay and Texas Individual Permit groups are considered for further
37Large firms are not expected to have changes in either equity or working capital of more
than 5 percent.
10-42
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TABLE 10-13
RANGE AND MEDIAN CHANGE IN EQUITY AND WORKING CAPITAL ASSOCIATED
WITH ZERO DISCHARGE
(LOUISIANA OPEN BAY AND TEXAS INDIVIDUAL PERMIT DISCHARGERS ONLY)
Operator Size
Minimum Change
Maximum Change
Median Change
Change in Eqaity
Large operators
Small operators
All
0.03%
0.05%
0.03%
0.11%
618%
618%
0.09%
1.67%
0.96%
Change in Working Capital
Large operators
Small operators
All
0.36%
0.07%
0.07%
3.09%
220%
220%
0.63%
5.87%
2.90%
Source: Change in Equity and Working Capital Worksheet (CBI data; in rulemaking record).
10-43
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TABLE 10-14
COMBINED CHANGE IN EQUITY AND
WORKING CAPITAL AMONG SMALL FIRMS
Equity <5%; Working Capital <5%
Equity <5%; Working Capital >5%"
Equity >5%; Working Capital <5%
Equity >5%; Working Capital >5%b
Number
8
5
0
9
"Or working capital is negative.
""Includes one observation where working capital is not available. Equity change is very small,
however, 0.11%, so EPA did not include this firm in the detailed analysis.
Source: Changes in Equity and Working Capital Worksheet (CBI data; in rulemaking record).
10-44
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analysis since they are not estimated to have changes in their equity or working capital of more
than 5 percent).
Table 10-15 presents the results of the in-depth analysis performed on these 12 firms.
For reasons explained in the comment column in the table, 3 of these 12 firms are considered
additional baseline failures and 1 additional firm is expected to have already plugged and
abandoned the wells that are served by its discharging facility by the time the Coastal Guidelines
take effect. Of the remaining 7 firms, 1 firm is expected to plug and abandon or sell its wells (if
still economically viable) in response to the regulation. Note that the cost and tax savings to the
firm of plugging and abandoning wells is not included in this analysis, but this cost is small (on a
per well basis), the firm has few coastal wells, and the cost is a one-time cost that will not have a
significant impact on cash flow over the time frame of analysis. EPA does not consider this firm
to be significantly affected (i.e., experience firm failure), however, because coastal operations are
a very small percentage of the firm's total revenues. Furthermore, this firm's returns, measured
as ROA or ROE, are expected to be good, even after the revenue loss associated with
compliance is taken into account (i.e., net income as a percentage of total assets or equity is
much better than average for the industry).
Seven firms, shown in the last two columns in Table 10-15, might experience impacts
from the regulation. Five of these firms are expected to be somewhat affected, but not to the
extent that firm failure is likely. The two other firms might be substantially affected, but not
enough information is available in the Survey data to judge whether this is definite. These two
firms either have a very small stake in the wells they operate or have no stake and are operators
only. It is possible therefore that little, if any, of the increased costs for operating pollution
control equipment would be borne by these firms. If wells associated with these firms cease to
operate, however, the firms might cease to receive revenues entirely (i.e., a firm that is only an
operator might have no more wells to operate). EPA cannot determine whether the affected
wells would be profitable to operate once the regulation is promulgated because none of these
particular wells were surveyed. Therefore, the potential impact to these two firms ranges from
minor (e.g., some lost revenues) to major (i.e., firm failure).
10-45
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TABLE 10-15
RESULTS OF FURTHER FINANCIAL ANALYSIS OF
SELECTED COASTAL REGION OIL AND GAS PRODUCTION OPERATORS
(LOUISIANA OPEN BAY AND TEXAS INDIVIDUAL PERMIT DISCHARGERS)
firm
No.
1
2
3
4
5
6
7
Likely
Baseline
Firm
Failure
X
X
Iike(y
Baseline
P&A*
X
Likely to P&A
or Sell
Properties in
Response to
Permit but
Not Firm
Failure
X
Some
Impact
but Not
Firm
Failure
X
Possible
Finn
Failure tot
Need More
fafor.
nation
X
X
•*
•s
. Finn.
Failure
*•
-
-
Comments
Current loss in coastal
portion of business; firm
likely to plug and abandon
wells; other business appears
healthy.
Did not provide enough info.
in survey to make judgment
Analysis shows large change
in working capital, but
working capital unusually
low, probably because used
to pay for workover. If cost
of workover ignored, impact
on working capital still high
(over 30%) but change in
equity very low and return
on assets and return on
equity still likely to be good
compared to industry
average. Is an S
corporation, so change in
working capital less of an
issue.
Very complex financial
picture; only takes about a
10% share of net revenues
from wells operated.
Negative earnings, negative
net income, negative working
capital.
Negative earnings, negative
net income, negative working
capital.
Impacts from plug and
abandoning wells and lost
revenues, but return on
assets and return on equity
still likely to be very good
relative to industry averages
post-compliance.
10-46
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TABLE 10-15 (continued)
Firm
No.
8
9
11
12
14
Likely
Baseline
Finn
Failure
X
Likely
Baseline
P&A*
Likely to P&A
or Sell
Properties in
Response to
Permit but
Not Firm
Failure
Some
Impact
but Not
Firm
Failure
X
X
X
X
Possible
Firm
Failure hut
KeeaMoce
Infor*
mation
Firm
FftOure
- -
Comments
Return on assets still very
strong after compliance costs
are incurred.
Very low ROA (0.04%),
ROE (0.05%), ICR=1.04;
interest payments nearly
equal to earnings.
Returns still good after
pollution control costs are
taken into account
Although working capital is
negative, equity changes only
minimally (1.36%).
Returns still good after
pollution control costs are
taken into account
Although working capital is
negative, equity changes only
minimally (1.36%).
Large diyhole abandonment
costs expended in 1992. If
adjusted for expended item,
ROA would be adequate
both before and after
pollution control costs.
Note: Shaded columns indicate possible firm failure (used in the estimate of firms that might experience substantial impact).
Source: Section 308 Survey Questionnaires; (financial section). Annualized costs based on EPA's Development Document for
each affected facility.
10-47
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EPA concludes that, under zero discharge, a range of 0 to 2 firms might experience firm
failure, out of a total of 27 discharging firms examined in this analysis. To account for the
number of firms not captured in this analysis, EPA extrapolates this estimate of the number of
firm failures to the full universe of Louisiana Open Bay and Texas Individual Permit
operators.38 The single potentially failing Louisiana Open Bay operator captured in the analysis
represents one operator in the full universe, while the one Texas Individual Permit failing
operator captured in the analysis represents three operators in the full universe, yielding a total
of 0 to 4 fatting firms. These potentially substantially affected firms represent 0 to 6.6 percent of
all Louisiana Open Bay and Texas Individual Permit operators (61 firms, both large and small),
although at most, this is less than 1 percent of the 417 firms estimated to be operative in the
Gulf coastal area after eliminated baseline firm failures (see the PEIA) and Chapter Eleven of
the FEIA. The upper estimate of 4 firm failures assumes that firms for which information is
lacking will be substantially affected. Considering the level of uncertainty associated with the
data, a range of 0 to 4 failures might therefore overstate impacts (e.g., some of these 0 to 4 firms
might not be appreciably affected if their wells remain operative and costs are passed through to
several owners). It will not understate impacts.
10.42.2 Alternative Baseline
To estimate the impacts on firms under the entire alternative baseline scenario, EPA
adds the results of its Louisiana Open Bay/Texas Individual Permit analysis to results estimated
for the current regulatory baseline. As discussed in Chapter Six, under the current regulatory
baseline, EPA found no firm failures given the selected regulatory options. Even with the
greater costs to one firm under the assumption of the alternative baseline, EPA finds no firm
failures among Major Pass dischargers.39 Thus for the selected regulatory options under the
38There were a total of 12 surveyed Texas Individual Permit Applicant firms out of 40 total
such firms in Texas and 17 surveyed Louisiana Open Bay discharging firms out of 22 total such
firms in Louisiana. EPA assumed that the firms were representative of those not surveyed and
thus each Texas firm was estimated to represent approximately three (40/12) firms and each
Louisiana firm was estimated to represent one (22/17).
39Cash Flow Analysis of Major Pass Dischargers (CBI data; in rulemaking record.
10-48
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alternative baseline scenario, EPA estimates that 0 to 4 firms might be substantially affected by
the Coastal Guidelines under the alternative baseline analysis.
10.5 NATIONAL AND REGIONAL EMPLOYMENT IMPACTS AND TOTAL OUTPUT
LOSSES
10.5.1 National-Level Output and Employment Impacts
The Coastal Guidelines may cause four types of changes (losses) in employment and
output, some of which are offset by gains, and some of which are not (dead weight losses).
These four types of changes, discussed in detail for Texas and Louisiana in the sections to follow,
include:
• Type 1—Compliance Costs: Direct oil and gas employment losses due to
expenditures diverted to compliance.
• Type 2—Production Losses: Employment and output losses due to production
losses at operations that install and operate pollution control equipment. Losses
in production are a result of shortened postcompliance lifetimes.
• Type 3—First Year Shut-ins: Employment and output losses due to production
losses from operations that shut-in in the first year and do not install pollution
control equipment.
• Type 4—Delayed Investment: Employment and output losses associated with
delayed investment, i.e., where the need for pollution control expenditures delays
investment in oil and gas exploration and development.
Changes in output in the oil and gas industry affect national-level output and
employment. To calculate the effects of a change in oil and gas industry output on national-level
output across all industries under the assumptions of the alternative baseline, EPA uses the same
multiplier used in Chapter Seven, 1.9420 (RIMS II National Multipliers). This figure represents
the loss of an additional $0.94 across all industries for each $1 decrease in output in the oil and
gas industry. Similarly, to calculate national-level employment changes based on changes in oil
and gas industry output, EPA uses the BEA multiplier of 13.0 jobs per million dollars (RIMS II
National Multipliers), which reflects the change in national-level employment given a $1 million
10-49
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change in industry output. The methodology used in this chapter is identical to that discussed in
Chapter Seven.
At the national level, employment losses associated with the direct transfer of labor
resources away from production wells are matched by equivalent gains in employment to operate
injection wells. Additionally, on a national basis, losses from first-year shut-ins are offset by gains
elsewhere in the economy as the investment in production at these wells is reallocated to other
productive investments. Because the only measurable net employment changes are those
associated with output losses, EPA estimates only Type 2 (based on production losses from
premature well closures, as compared to baseline) and Type 4 losses (delayed investment losses).
Regional employment effects are characterized somewhat differently and are estimated in Section
10.5.2.
10.5,1,1 National Level Output Losses
National-level output losses due to production losses (Type 2) and investment delays
(Type 4) are presented in Tables 10-16 and 10-17 and summarized below:
Type 2 output losses—output losses for the U.S. economy are estimated at $26.6
million per year for Louisiana Open Bay dischargers. For Texas Individual Permit
applicants, EPA estimates output losses for the U.S. economy of $11.1 million per
year. Losses are estimated at $37.8 million per year for both groups combined.
Adding Major Pass and Cook Inlet impacts, EPA estimates $57.2 million per year
will be lost under the assumptions of the alternative baseline (see Table 10-16).
Type 4 output losses—Using the method discussed in Section 7.1.2 of this FEIA,
EPA estimates that delayed investment will result in reduced annualized returns
to the industry of $1.2 million in Louisiana and $0.3 million in Texas. These
losses are associated with a total reduction in U.S. output of $2.9 million per year
($2.4 million for Louisiana Open Bay dischargers and $0.5 million for Texas
Individual Permit applicants). For all groups (including Cook Inlet and Major
Pass dischargers), the loss is $4.4 million annually (see Table 10-17).
10-50
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TABLE 10-16
NATIONAL OUTPUT LOSSES ASSOCIATED WITH
POSTCOMPLIANCE PRODUCTION LOSSES
FOR THE ALTERNATIVE REGULATORY RASELINE UNDER THE SELECTED OPTIONS
(MAJORPASS FACILITIES, COOK INLET PLATFORMS, LOUISIANA OPEN BAY DISCHARGERS.
AND TEXAS INDIVIDUAL PERMIT APPLICANTSl
(19MS)
Louisiana [a]
Texas
Total Louisiana and Texas
Total Alternative Baseline
Annualized
production loss
(BOE) fbl
623,661
260,754
884.415
1,339,000
Annual ized
industry output
(revenues) lost
rsooo)
S13.720.5
S5.736.6
S19.457.1
S29.458.0
Final-demand
output
multiplier fcl
1.9420
1.9420
1.9420
1.9420
Annualized
national-level
output effects
(SOOO)
$26,645.3
SI 1.140.5
S37.785.8
S57.207.4
[a] Excluding Major Pass operators.
[b] Minus first-year shut-in losses of 722,673 PVBOE (102,892 BOE annually) for the Louisiana Open Bay
Dischargers and 606,719 PVBOE (86,383 BOE annually) for the Texas Individual Permit Applicants.
[c] Represents the total dollar change in output that occurs in all industries for each dollar change in output
delivered to final demand by the oil and gas industry.
Sources: Major Pass Dischargers Production Loss Model Runs, Cook Inlet Dischargers Production Loss Model
Runs, Louisiana Open Bay Dischargers Production Loss Model Runs, and Texas Individual Permit
Applicants Production Loss Model Runs (CBI data; in rulemaking record).
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by Industry Aggregation, for
Output, Earnings, and Employment. Regional Input-Output Modeling System (RIMS Q), Regional
Economic Analysis Division.
TABLE 10-17
NATIONAL OUTPUT LOSSES ASSOCIATED WITH
DELAYED PRODUCTION FOR THE ALTERNATIVE REGULATORY BASELINE
UNDER THE SELECTED OPTIONS
(MAJORPASS FACILITIES. COOK INLET PLATFORMS, LOUISIANA OPEN BAY DISCHARGERS,
AND TEXAS INDIVIDUAL PERMIT APPLICANTS)
(1955 J)
Louisiana [a]
Texas
Total Louisiana and Texas
Total Alternative Baseline
Annualized
industry output
(revenues) lost
(SOOO)
$1,210.7
S263.3
Sl.474.0
S2.251.4
Final-demand
output
multiolier Ib]
1.9420
1.9420
1.9420
1.9420
Annualized
national-level
output effects
($0001
52,35 1.2
S511.3
$2,862.5
S4.37Z2
[a] Represents the total dollar change in output that occurs in all industries for each
dollar change in output delivered to final demand by the oil and gas industry.
[b] Represents the total dollar change in output that occurs in all industries for each dollar change
in output delivered to final demand by the oil and gas industry.
Sources: Major Pass Dischargers Production Loss Model Runs, Cook Inlet Dischargers Production
Loss Model Runs, Louisiana Open Bay Dischargers Production Loss Model Runs,
and Texas Individual Permit Applicants Production Loss Model Runs (CBI data;
in rulemaking record).
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by
Industry Aggregation, for Output, Earnings, and Employment. Regional
Input-Output Modeling System (RIMS II), Regional Economic Analysis
Division.
10-51
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10.5.1.2 National-Level Employment Impacts
National-level employment losses due to production losses (Type 2) and investment
delays (Type 4) are presented in Tables 10-18 and 10-19 and summarized below:
Type 2 employment losses—EPA estimates national employment losses of 163
FTEs associated with Louisiana Open Bay dischargers and 68 FTEs associated
with Texas Individual Permit applicants (231 FTEs combined) due to production
losses. Adding in losses associated with Major Pass and Cook Inlet dischargers,
Type 2 national-level employment impacts under the assumptions of the
alternative baseline total 350 FTEs (see Table 10-18).
Type 4 employment losses—EPA estimates losses of 14 FTEs associated with
Louisiana Open Bay discharges, 3 FTEs associated with Texas Individual Permit
applicants (17 FTEs combined), and 27 FTEs associated with all groups due to
investment delays under the assumptions of the alternative baseline (see Table
10-19).
103.1.3 Total National-Level Output and Employment Impacts
EPA estimates total national-level output losses associated with Louisiana Open Bay
dischargers and Texas Individual Permit applicants to be $40.6 million. Adding these to Major
Pass and Cook Inlet impacts, EPA estimates that total output under the alternative regulatory
baseline is reduced by $61.6 million, which is 0.001 percent of estimated gross domestic product
(GDP) of $6.6 trillion and 0.1 percent of oil and gas industry's contribution to GDP in 1992.40
In addition, EPA estimates that 377 FTEs will be lost. This represents only 0.0003 percent of
total 1995 U.S. employment of 124.9 million persons41 (see Table 10-20 for a summary of these
losses).
^numbers inflated, but not otherwise adjusted, from 1992 to 1995. The most recent year for
which data were available on the oil and gas industry's contribution to GDP was 1992. See:
Tables Nos. 700 and 1173 in the Statistical Abstract of the United States. U.S. Department of
Commerce, Bureau of the Census, September 1995.
"communication between ERG and the Bureau of Labor Statistics (BLS), July 24,1996.
10-52
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TABLE 10-18
NATIONAL EMPLOYMENT LOSSES
ASSOCIATED WITH LOST OUTPUT (TYPE 2 LOSSES) FOR THE
ALTERNATIVE REGULATORY BASELLNE UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES, COOK INLET PLATFORMS. LOUISIANA OPEN BAY DISCHARGERS,
AND TEXAS INDIVIDUAL PERMIT APPLICANTS)
Louisiana [a]
Texas
Total Louisiana and Texas
Total Alternative Baseline
Annualized
industry-level
output effects
(SOOO 1995)
513,720.5
S5.736.6
519,457. 1
529,458.0
Annuulized
industry-level
output effects
(SOOO 1992) [b]
512,501.7
55.227.0
517,728.7
526.841.2
Final-demand
employment
multiplier [c|
13.0
13.0
13.0
13.0
Total annual
employment
losses
(FTEs)
163
68
231
350
[a] Excluding Major Pass operators.
[b] Output values deflated from 1995 dollars to 1992 dollars because the Bureau of Economic
Analysis employment multipliers are based on 1992 data.
[c] Represents the total change in number of jobs that occurs in all industries for each SI million change
in output delivered to final demand by the oil and gas industry.
Sources: Table 10-16 in this FEIA.
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by Industry
Aggregation, for Output, Earnings, and Employment. Regional Input-Output Modeling
System (RIMS II), Regional Economic Analysis Division.
TABLE 10-19
NATIONAL EMPLOYMENT LOSSES
ASSOCIATED WITH DELAYED PRODUCTION (TYPE 4 LOSSES) FOR THE
ALTERNATIVE REGULATORY BASELINE UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES, COOK INLET PLATFORMS, LOUISIANA OPEN BAY DISCHARGERS,
AND TEXAS INDIVIDUAL PERMIT APPLICANTS)
Louisiana [a]
Texas
Total Louisiana and Texas
Total Alternative Baseline
Annualized
industry-level
output effects
(SOOO 1995)
51,210.7
5263.3
Sl.474.0
52.251.4
Annualized
industry-level
output effects
(SOOO 1992) [bl
51,103.2
5239.9
51.343.1
52,051.4
Final-demand
employment
multiplier [c]
13.0
13.0
13.0
13.0
Total annual
employment
losses
(FTEs)
14
3
17
27
[a] Excluding Major Pass operators.
[b] Output values deflated from 1995 dollars to 1992 dollars because the Bureau of Economic
Analysis employment multipliers are based on 1992 data.
[c] Represents the total change in number of jobs that occurs in all industries for each 51 million change
in output delivered to final demand by the oil and gas industry.
Sources: Table 10-17 in this FEIA.
Bureau of Economic Analysis. 1996. Table A-2.4. - Total Multipliers, by Industry
Aggregation, for Output, Earnings, and Employment Regional Input-Output Modeling
System (RIMS II), Regional Economic Analysis Division.
10-53
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TABLE 10-20
SUMMARY OF NATIONAL EMPLOYMENT AND
OUTPUT LOSSES FOR THE ALTERNATIVE REGULATORY BASELINE
UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES, COOK INLET PLATFORMS, LOUISIANA OPEN BAY
DISCHARGERS, AND TEXAS INDIVIDUAL PERMIT APPLICANTS)
(1995 $)
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses [a]
Type 4 Losses fbl
Total Losses
Annualized
production
losses
(BOE)
1,339,000
i.339,000
Annualized
industry output
(revenue) losses
(SOOO)
$29,458.0
$2.251.4
$31.709.4
Annualized
national-level
output losses
($000)
$57,207.4
$4,372.2
$61.579.6
Annual
Reduction in
FTEs
350
27
377
[a] Type 1 and Type 3 losses are not calculated in this FEIA because any losses and gains
are assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
Sources: Tables 10-16,10-17,10-18, and 10-19 in this FEIA.
10-54
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10.5.2 Regional Employment Impacts
In this section, EPA evaluates the magnitude and significance of job losses on the
regional level (see Chapter Seven for a description of the methodology). EPA assumes that
Type 1 losses result in gains elsewhere in the regional economy as production employees are
shifted into operating injection well equipment. Thus there are no net employment changes due
to Type 1 losses. Type 2 and Type 4 losses are used to estimate employment losses in this
subsection as they were in Section 10.5.1. The only major difference in EPA's analysis of Type 2
and Type 4 losses at the regional level is that regional (state) multipliers are used in place of the
national-level multipliers. EPA assumes that investments associated with Type 4 losses would
have occurred in the region in the absence of the Coastal Guidelines, although this might not be
the case.
First-year shut-ins and firm failures (Type 3 losses) are also evaluated at the regional
level. On a national level, Type 3 losses are offset by gains elsewhere as investment is
reallocated to other productive investments in the economy, but EPA assumes that there are no
offsetting gains in the regional economy for Type 3 losses. EPA evaluates Type 2, Type 3, and
Type 4 losses in subsections below.
10.53.1 Type 2 and Type 4 Regional Employment Losses
Using the Type 2 production losses shown in Table 10-16 above, and regional multipliers
for Louisiana and Texas, where appropriate, where appropriate, instead of national
multipliers,42 EPA calculates Type 2 losses of 100 FTEs for Louisiana and 46 FTEs for Texas,
for a total of 146 FTEs for both groups combined. EPA estimates annual Type 4 employment
losses of 9 FTEs in Louisiana and 2 FTEs in Texas using the output loss figures shown in Table
10-14 and regional multipliers, for a combined Type 4 loss of 11 FTEs (jobs) annually in the Gulf
as a result of this rule (see Tables 10-21 to 10-25).
42(state) multipliers are lower than national multipliers because a smaller portion of vendor
industries are located in each state.
10-55
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TABLE 10-21
SUMMARY OF REGIONAL EMPLOYMENT AND OUTPUT LOSSES FOR
THE LOUISIANA OPEN BAY DISCHARGERS
UNDER THE SELECTED OPTIONS
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses
Type 4 Losses fbl
Total Losses
Annualized
production
losses
(BOE)
623,661
623,661
Annualized
industry output
(revenue) losses
(SOOO 1995)
$13,720.5
$1,210.7
$14,931.2
Annualized
industry output
(revenue) losses
(SOOO 1989) fcl
$11,573.8
$1,021.3
$12,595.1
Annual
Reduction in
FTEs
100
11 to 30
9
120 to 139
[a] Type 1 losses are not calculated in this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Sources: EPA analyses described in text; Tables 10-16,10-17, 10-18, and 10-19 in this FEIA.
TABLE 10-22
SUMMARY OF REGIONAL EMPLOYMENT AND OUTPUT LOSSES FOR
THE TEXAS INDIVIDUAL PERMIT APPLICANTS
UNDER THE SELECTED OPTIONS
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses
Annualized
production
losses
(BOE)
260,754
260,754
Annualized
industry output
(revenue) losses
(SOOO 1995)
$5,736.6
$263.3
$5,999.9
Annualized
industry output
(revenue) losses
(SOOO 1989) fc]
$4,839.0
$222.1
$5.061.1
Annual
Reduction in
FTEs
46
6 to 9
2
54 to 57
[a] Type 1 losses are not calculated in this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Sources: EPA analyses described in text; Tables 10-16,10-17,10-18, and 10-19 in this FEIA.
10-56
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TABLE 10-23
SUMMARY OF REGIONAL EMPLOYMENT AND OUTPUT LOSSES FOR
THE LOUISIANA OPEN BAY DISCHARGERS AND
THE TEXAS INDIVIDUAL PERMIT APPLICANTS
UNDER THE SELECTED OPTIONS
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses
Type 4 Losses fb|
Total Losses
Annualizcd
production
losses
(BOE)
-
884,415
-
•_
884.415
Annualized
industry output
(revenue) losses
(SOOO 1995)
-
519,457.1
-
$1,474.0
520,93 1.1
Annualized
industry output
(revenue) losses
(SOOO 1989) [c|
-
$16,412.8
-
$1,243.4
$17.656.2
Annual
Reduction in
FTEs
-
146
17 to 39
11
174 to 196
[a] Type 1 losses are not calculated in this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Sources: EPA analyses described in text, Tables 10-16,10-17,10-18, 10-19,10-21, and
10-22 in this FEIA.
TABLE 10-24
SUMMARY OF REGIONAL EMPLOYMENT AND OUTPUT LOSSES FOR
THE GULF OF MEXICO UNDER THE SELECTED OPTIONS
(LOUISIANA OPEN BAY DISCHARGERS, TEXAS INDIVIDUAL PERMIT APPLICANTS,
AND MAJOR PASS FACILITIES)
Type 1 Losses [a]
Type 2 Losses
Type 3 Losses
Type 4 Losses (bl
Total Losses
Annualized
production
losses
(BOE)
1,186^58
1,186358
Annualized
industry output
(revenue) losses
(SOOO 1995)
$26,099.9
$2,144.5
$28244.4
Annualized
industry output
(revenue) losses
(SOOO 1989) [c]
$22,016.3
$1,809.0
$23.825.2
Annual
Reduction in
FTEs
194
17 to 39
16
227 to 249
[a] Type 1 losses are not calculated in -this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Sources: EPA analyses described in text; Tables 10-16,10-17,10-18,10-19,10-21, and
10-22 in this FEIA.
10-57
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TABLE 10-25
SUMMARY OF REGIONAL EMPLOYMENT AND
OUTPUT LOSSES FOR THE ALTERNATIVE REGULATORY BASELINE
UNDER THE SELECTED OPTIONS
(MAJOR PASS FACILITIES, COOK INLET PLATFORMS, LOUISIANA OPEN BAY
DISCHARGERS. AND TEXAS INDIVIDUAL PERMIT APPLICANTS)
Type 1 Losses [aj
Type 2 Losses
Type 3 Losses
Type 4 Losses f bl
Total Losses
Annualized
production
losses
(BOE)
—
1,339,000
—
..
1,339,000
Annualized
industry output
(revenue) losses
($000 1995)
~
$29,458.0
—
$2.251.4
$31,709.4
Annualized
industry output
(revenue) losses
($000 1989) fcl
—
$24,849.0
—
$1.899.1
$26,748.1
Annual
Reduction in
FTEs
—
205
17 to 39
17
239 to 261
[a] Type 1 losses are not calculated in this FEIA because any losses and gains are
assumed to offset each other on the national level.
[b] Type 4 production losses are not calculated.
[c] Output values deflated from 1995 dollars to 1989 dollars because the Bureau of
Economic Analysis regional employment multipliers use 1989 dollars.
Sources: EPA analyses described in text; Tables 10-16,10-17,10-18,10-19, 10-21, and
10-22 in this FEIA.
10-58
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10.53.2 Type 3 Regional Employment Losses
10.5.2.2.1 Primary Employment Losses
Baseline Losses
Independent of the Coastal Guidelines, 481 jobs are estimated to be lost among the
Louisiana Open Bay and Texas Individual Permit operators (43 in Louisiana and 438 in Texas)
as a result of baseline well shut-ins and firm failures. These job losses are associated with 37
baseline shut-in wells in Louisiana and 367 in Texas, as well as 12 baseline firm failures in Texas
(zero in Louisiana).43 A loss of 481 jobs represents a 34 percent reduction in existing
employment within the Louisiana Open Bay and Texas Individual Permit groups (estimated at
699 FTEs in Louisiana and 699 FTEs in Texas44), without the Coastal Guidelines. Adjusted
baseline employment is therefore 656 FTEs in the Louisiana Open Bay group and 261 FTEs in
the Texas Individual Permit group, for a total of 917 FTEs. When Major Pass and Cook Inlet
dischargers are counted (406 FTEs), total alternative baseline employment is 1,754 (1,313 in the
Gulf and 431 in Cook Inlet).
Postcompliance Employment Losses
Under zero-discharge requirements, 47 wells among the Louisiana Open Bay dischargers
and 47 wells among the Texas Individual Permit applicants, each with associated employment of
55 FTEs, are expected to shut in during the first year. As discussed in Chapter Seven, these 110
FTEs would have been baseline losses at some point in the near future because, on average, the
wells that shut in in the first year postcompliance shut in in Year 5 in Texas and Year 11 in
43job losses are associated with baseline well shut-ins. The firms that in baseline are very
small firms with no employment (all labor is provided by contract). For each firm-failure, EPA
assumes that only the owner becomes unemployed, for a total of 12 jobs lost. Employment lost
due to well shut-ins is calculated on the basis of the estimated 1.16 FTEs needed to serve a well.
""These numbers capture only production employment. Other firm employment cannot be
estimated for these operating segments.
10-59
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Louisiana under the assumptions of the alternative baseline (without the Coastal Guidelines).
The actual loss in FTEs under the alternative baseline is therefore the difference between the
loss in FTEs in Year 1 and the loss in Year 5 or 11, which can be computed as
Loss in Year 1 - Present Value of Loss in Year 5 (Texas) or 11 (Louisiana)
under the assumption that earnings can be discounted and FTEs can be represented by these
earnings. Thus, EPA estimates the present value Type 3 employment losses to be 29 FTEs in
Louisiana and 16 FTEs in Texas. Annualized, these losses amount to 4 FTEs in Louisiana and 2
FTEs in Texas.
Additionally, as discussed in Section 10.4, a maximum of 0 to 3 firms in Texas and from 0
to one firm in Louisiana are expected to fail as a result of the Coastal Guidelines. These
potentially failing firms are estimated to employ a total of 53 FTEs.45 Annualizing these losses
over 10 years, EPA estimates a maximum of 8 FTEs in annual direct losses in Louisiana and
Texas due to firm failure. Total annual Type 3 losses, combining first-year shut-ins and firm
failures, are 4 to 11 FTEs in Louisiana and 2 to 3 FTEs (with rounding) in Texas (see Tables 10-
18 and 10-19). The respective reduction in employment is 0.6 to 1.7 percent of adjusted
baseline employment (656 FTEs) for the Louisiana Open Bay dischargers and 0.8 to 1.1 percent
of baseline employment (261 FTEs), among the Texas Individual Permit applicants, or at most,
1.1 percent of employment among the Louisiana Open Bay dischargers and the Texas Individual
Permit applicants and at most 1.0 percent of alternative baseline employment among all Gulf
operators*5 (1,313 FTEs), including Major Pass dischargers.
41The failing Texas firm actually reports 0 employees in the Section 308 Survey. This
result can occur if production operations are handled by a contractor. EPA assumes that there is
one owner who subsequently becomes unemployed for each of the three firms that are
represented by this firm. The one Louisiana firm reports 50 nonproduction personnel.
baseline FTE losses are accounted for.
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10.5.2.2.2 Secondary Employment Losses
Based on the primary losses of 4 to 11 FTEs in Louisiana and 2 to 3 FTEs in Texas and
using the regional (state) employment multipliers,47 EPA estimates total (direct, indirect, and
induced) Type 3 annual employment losses relative to the alternative baseline to be 11 to 30
FTEs in Louisiana and 6 to 9 FTEs in Texas (for a total of 17 to 39 FTEs in the Gulf), (see
Chapter Seven of this FEIA and Tables 10-21 through 10-25 for summaries of regional Type 3
employment losses).
10.5.2.3 Toted Regional Employment Lasses Under the Assumptions of the Alternative
Regulatory Baseline (Types 2, 3, and 4 Lasses)
Based on primary and secondary losses due to first-year shut-ins and firm failures,
production losses, and delayed investment, EPA estimates a local annual job loss of 120 to 139
FTEs for Louisiana Open Bay dischargers, and 54 to 57 FTEs associated with Texas Individual
Permit applicants (see Tables 10-19 and 10-20 for a summary of these impacts). EPA estimates
that when these losses are combined with Major Pass up to 249 FTEs will be lost per year in the
Gulf coastal area and 12 FTEs will be lost per year in Cook Inlet as noted in Chapter Seven.
10.53 Community-Level Impacts
After summing all losses (Type 2, Type 3, and Type 4 losses) for each of the affected
groups and using the maximum estimated employment loss,48 EPA estimates that community-
level impacts on the counties, parishes, and boroughs of concern are not significant, since, as
discussed below, the unemployment rates in these areas do not change substantially.
47,
for Louisiana and 3.0173 for Texas (RIMS II Handbook).
"^These estimates overstate community losses, since the multipliers used to develop these
estimates project losses in employment for the entire state of Louisiana, not just in the parishes
of concern.
10-61
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Louisiana—A maximum of 139 FTEs will be lost in Louisiana annually (Open Bay
dischargers only), and the current employment in the parishes in Louisiana49
expected to bear the greatest impact is 619,158 employed persons (see
Table 10-23).50 EPA estimates that these losses represent a 0.02 percent change
in employment in the affected areas of Louisiana, (unemployment rate changes
from 6.23 percent to 6.25 percent). When impacts from the Major Pass
dischargers are added to these losses, EPA estimates that a maximum of 192
FTEs will be lost in the same parishes of concern. These losses represent a 0.03
percent change in employment in the affected areas of Louisiana (unemployment
rate changes from 6.23 percent to 6.26 percent).
Texas—A maximum of 57 FTEs will be lost in Texas annually, and the current
employment in the counties in Texas (see Table 10-26) expected to bear the
greatest impact is 2,095,730 employed persons. EPA estimates that these losses
represent a 0.003 percent change in employment in the affected areas of Texas,
(unemployment rate changes from 6.425 percent to 6.427 percent).
Gulf of Mexico—When impacts from Texas Individual Permit applicants and
Louisiana Open Bay dischargers are added together, EPA estimates that a
maximum of 196 FTEs will be lost in the same parishes and counties of concern
annually. These losses represent a 0.007 percent change in employment in the
affected counties and parishes of Louisiana and Texas, (unemployment rate
changes from 6.38 percent to 6.39 percent). When impacts from the Major Pass
dischargers are added to these losses, EPA estimates that a maximum of 249
FTEs will be lost annually in the Gulf area parishes and counties of concern. The
total losses represent a 0.007 percent change in employment in the affected areas
of Louisiana and Texas, (unemployment rate changes from 6.38 percent to 6.39
percent).
Alaska—As noted in Chapter Seven, for Kenai Peninsula Borough, Alaska, EPA
estimates that the employment losses in the affected area of Alaska leads to a
0.05 percent change in the unemployment rate in this area. While this is not a
significant change, if EPA had selected Option #3 for produced water/TWC (zero
discharge all, including Cook Inlet), the unemployment rate in this area would
have changed by 0.6 percent (from 12.7 percent to 13.3 percent). EPA concludes
that the impact of Option #3 to Kenai Peninsula Borough is significant. The
Kenai would be disproportionately affected because the Peninsula is significantly
dependent on oil and gas production, particularly when compared to the Gulf of
Mexico area, where the coastal oil and gas industry is spread out over a large
number of counties and parishes (see Chapter Seven).
""Parishes included only if adjacent to Gulf of Mexico (including bays); includes the four
parishes considered affected by Major Pass discharger impacts.
^Counties included only if adjacent to the Gulf of Mexico (including bays).
10-62
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TABLE 10-26
EMPLOYMENT IN COUNTIES AND PARISHES
POTENTIALLY AFFECTED UNDER THE
ALTERNATIVE BASELINE ASSUMPTIONS
(1991)
Civilian Unemployment
Labor Force Rate
Texas
Cameron
Willacy
Kenedy
Kleberg
Nueces
San Patrick)
Refugio
Aransas
Calhoun
Jackson
Matagorda
Galveston
Brazoria
Harris
Chambers
Jefferson
Orange
Totals
Louisiana
Cameron
Vermillion
Iberia
St. Mary
Terrebonne
Lafourche
St. Charles
Jefferson
Plaquemines
St. Bernard
Orleans
Totals
109,146
6,963
315
14,669
139,626
25,561
3,513
7,849
9,900
5,517
16,584
112,190
93,541
1,532,757
7,625
114,796
39,064
2,239,616
4,284
17,822
27,450
25,033
38,921
32,767
19,277
229,498
9,194
30,981
225,071
660,298
12.5%
15.7%
0.3%
6.4%
7.7%
9.1%
4.0%
4.2%
5.7%
4.6%
10.7%
7.0%
5.6%
5.7%
5.3%
6.7%
9.0%
6.4% [a]
5.5%
8.9%
7.1%
8.1%
6.9%
6.3%
6.5%
5.6%
6.4%
7.0%
6.1%
6.2% [al
Employed
Population
95,503
5,870
314
13,730
128,875
23,235
3,372
7,519
9,336
5,263
14,810
104,337
88,303
1,445,390
7,221
107,105
35,548
2,095,730
4,048
16,236
25,501
23,005
36,235
30,703
18,024
216,646
8,606
28,812
211,342
619,158
[a] Weighted average.
Source: Bureau of Labor Statistics data, as reported by the U.S. Census
Bureau at Internet address:
http://vvww.census.gov/datamap/www/index.html
10-63
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Because of the Kenai Peninsula Borough's relative sensitivity and the Gulfs relative
insensitivity to employment impacts on the local coastal oil and gas industry, EPA concludes that
employment impacts (along with the results of analyses in Chapter Five) contribute to a finding
of economic inachievability for zero discharge of produced water in Cook Inlet, but a finding of
economic achievability for zero discharge of produced water in the Gulf of Mexico coastal area.
10.6 OTHER IMPACTS
EPA estimates that the Coastal Guidelines will have no significant effect on trade or
inflation under the alternative baseline, for the same reasons that there were no impacts under
the current regulatory baseline. NSPS impacts are not an issue among the Louisiana Open Bay
and Texas Individual Permit groups, since these groups consist of specific operations that are
currently discharging. Thus the impacts from NSPS requirements are the same as those
discussed in Chapter Nine for the current regulatory baseline. Chapter Eleven presents the
regulatory flexibility analysis for both baselines.
10-64
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CHAPTER ELEVEN
REGULATORY FLEXIBILITY ANALYSIS
11.1 INTRODUCTION
The Regulatory Flexibility Act (RFA) was recently amended by the Small Business
Regulatory Enforcement Fairness Act (SBREFA) of 1996, which has important implications for
the implementation of rules that affect small business. The RFA requires the federal
government to consider the impacts of proposed regulations on small entities (as defined in 13
CFR Part 121) during the rulemaking process. The RFA acknowledges that small entities have
limited resources and makes the regulating federal agency responsible for avoiding burdening
such entities unnecessarily.
The Administrator has certified that this rule will not have a significant effect on a
substantial number of small entities and thus a Regulatory Flexibility Analysis is not required.
Nevertheless, EPA has prepared a regulatory flexibility analysis equivalent to that required by the
RFA as amended by SBREFA. Section 11.2 follows the steps of the Agency guidance as defined
by the RFA to identify significant impacts on small firms and to determine whether a regulatory
flexibility analysis should be presented. Section 11.3 presents a final regulatory flexibility analysis
as required for a final rule.
11.2 INITIAL ASSESSMENT
The following subsections generally follow the steps of an initial assessment as current
EPA guidance suggests.
11-1
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11.2.1 Is the Rule Subject to Notice-and-Comment Rulemaking Requirements?
The Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil
and Gas Extraction Point Source Category is subject to notice-and-comment ruleraaking
requirements.
11.2.2 Profile of Affected Entities
EPA prepared a profile of the regulated universe of entities in the PEIA (Chapter
Three), which is supplemented in Chapter Three of this FEIA by the profile of the Major Pass
dischargers. A total of 435 regulated entities (firms)1 were estimated in the PEIA. An
additional two entities (both Major Pass dischargers) were not surveyed and are added to this
group for a total of 437 regulated entities (firms). The profiles distinguish characteristics of
small entities versus large entities in the coastal oil and gas industry, where possible without
compromising confidential business data.
11.23 Will the Rule Affect Small Entities?
The Small Business Administration (SBA) defines a small entity in the oil and gas
industry as one with 500 or fewer employees. Based on this definition and Section 308 Survey
data, as outlined in the PEIA and supplemented in the FEIA (see Chapter Three in both
reports), EPA estimates that as of 1992, a total of 373 small firms would be potentially regulated
by the Coastal Guidelines (approximately 85 percent of the coastal oil and gas industry, under
both the current regulatory baseline and the alternative regulatory baseline). Most of these firms
are currently subject to the rule's requirements (see below). Financial profiles of a sampling of
these small firms are presented in Chapters Three and Ten, as well as in the PEIA (see PEIA,
1This figure does not include operators in some areas where zero discharge is being met by
all firms, i.e., approximately 20 operators in California and the Gulf of Mexico outside Louisiana
and Texas, who were not surveyed in the Section 308 Survey, and North Slope operators, who
were surveyed but not analyzed in this FEIA.
11-2
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Section 9.4). EPA has determined that the rule will affect some small coastal oil and gas firms
under both baselines.
11.2.4 Will the Rule Have an Adverse Economic Impact on Small Entities?
EPA has determined that the majority of small entities regulated by the rule will incur no
compliance costs, since they are already subject to zero discharge requirements. However, the
Agency has identified, under the current regulatory baseline, three small firms in the Major Pass
discharger group that will incur compliance costs as a result of the Coastal Guidelines. Under
the alternative regulatory baseline,2 the Agency has identified 59 small firms (56 plus the 3 small
Major Pass discharging firms) that will incur compliance costs. Thus under both regulatory
baselines, the Agency has identified some small firms that will be adversely (although not
necessarily significantly) affected by the Coastal Guidelines.
11.2.5 Analysis of Significant Impact
Rather than conduct an Initial Assessment, EPA has performed a full regulatory
flexibility analysis.
REGULATORY FLEXIBILITY ANALYSIS
Section 604 of the RFA requires that a final regulatory flexibility analysis (FRFA)
accompanying a final rule must:
• state the need for and objectives of the rule.
2For Texas Individual Permit Applicants and Louisiana Open Bay dischargers, EPA assumes
under the alternative regulatory baseline that the facilities operated by these groups now subject
to zero discharge would be able to obtain authorization to continue discharging unless prohibited
by the Coastal Guidelines, although EPA believes this is unlikely.
11-3
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summarize the significant issues raised by public comments on the initial
regulatory flexibility analysis (IRFA) and the Agency's assessment of those issues,
and describe any changes in the rule resulting from public comments.
describe the steps the agency has taken 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.
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.
113.1 Need for and Objectives of the Rule
This 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 is setting Effluent Limitations Guidelines and Standards for the
control of discharge of pollutants for the coastal subcategory of the Oil and Gas Extraction Point
Source category. The regulations also are being proposed-pursuant to a Consent Decree entered
in NJRDC et at v. Reilfy (D.D.C. No. 89-2980, January 31,1992), and are consistent with EPA's
latest Effluent Guidelines Plan under Section 304(m) of the CWA (see 61 FR 52582, October 7,
1996).
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(b)(l) and 304(b)(l) authorize EPA to issue BPT effluent
limitations guidelines. The existing effluent limitations guidelines, which were issued on April 13,
11-4
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1979 (44 FR 22069), are based on the achievement of BPT for control of conventional pollutants.
Section 304(b)(4) authorizes EPA to issue BCT guidelines for conventional pollutants; Sections
301(b)(2)(E) and 304(b)(2) authorize EPA to issue BAT guidelines to control nonconventional
and toxic pollutants; Section 306 authorizes EPA to issue NSPS for all pollutants; and Sections
304(g) and 307(b) authorize EPA to issue PSES and PSNS for all pollutants.
11-3.2 Summary of Impacts on Small Businesses as a Result of the Effluent Guidelines
Effluent limitations guidelines and standards are not directly implemented, but form the
"floor" for NPDES permit writers in issuing effluent limitations in permits. Thus, the
requirements of this rule will be implemented through NPDES permits issued by the state (if it
has NPDES permit authority) or EPA. The Clean Water Act section 301 requires that no
discharge may take place without a permit; this rule does not affect the requirement to apply for
and obtain a permit.
The overwhelming majority of entities covered by this rule are already subject to NPDES
permits requiring zero discharge. This rule will have no impact on entities already subject to
zero discharge in NPDES permits. However, dischargers into the major passes of the Mississippi
that do not yet have an NPDES permit will need to either send their produced water to a facility
for commercial injection or inject onsite. Injection would require a Class II Underground
Injection Control Permit pursuant to the Safe Drinking Water Act, 42 U.S.C. 300f et seq.; 40
C.F.R. Part 144. The type of skills that would be required for such a permit application are
similar to those that are required for an NPDES application. Furthermore, the applicant would
need to have an understanding of the oil and gas facility's operations (e.g., current and projected
volume of produced water), and the technical requirements for Class II injection wells (e.g., well
siting and UIC permitting requirements, which involve an understanding of well integrity issues).
These skills are a part of or are transferable from skills necessary to produce oil and gas at
existing operations. Many of the operators use injection of produced water for waterflooding or
for disposal at other production locations.3 Some recordkeeping and reporting requirements will
3Major Pass Dischargers Data Submittals (CBI data; in rulemaking record).
11-5
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be reduced because if firms meet zero discharge, they will no longer be required to obtain an
NPDES permit or to,keep monitoring reports to show that they are meeting discharge
limitations.
Current Regulatory Baseline
As described in Chapter Six of this FEIA, EPA has determined that under the current
regulatory baseline, three small firms will be adversely affected by the Coastal Guidelines (i.e.,
they are expected to incur compliance costs). As discussed in Chapter Six, however, on the basis
of cash flow analysis, both for the first year and over a 10-year period, EPA determined that
none of these firms would be likely to fail, and in fact, that the impact of pollution control costs
on cash flow is relatively small.4 EPA also determined that the capital-raising ability of the
small firms that provided financial data was sufficient to meet the requirements of the Effluent
Guidelines. The small firm that did not provide financial data reported to EPA that compliance
costs of this rule would not materially affect the company's finances.5 Furthermore, all three
firms are not substantially different from the numerous other small firms in the coastal region
that currently or will soon inject produced water (see Chapters Three and Ten).
Also of concern in this regulatory flexibility analysis is the impact of the Coastal
Guidelines on small communities. Although the rule does not regulate small communities, it
may indirectly affect small communities due to decreased royalties recieved by the state or local
government. Some of the losses in royalties may have an impact on the parishes of concern in
Louisiana under the current regulatory baseline (Cook Inlet platforms are in state waters, thus
impacts on boroughs are not an issue). Most of the royalty owners affected by losses in the
Major Passes are federal and state government, since the majority of production is in offshore
waters. However, EPA does not know exactly how royalties might be distributed to local
governments. EPA assumes for this analysis, that 50 percent of royalty losses will affect the four
4Cash Flow Analysis of Major Pass Dischargers (CBI data; in rulemaking record). Exact
results not reported to protect business confidentiality.
5Major Pass Dischargers Data Submittals (CBI data; in rulemaking record).
11-6
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parishes in Louisiana in coastal subcategory areas (Jefferson, population 457,738; Plaquemines
(population 25,877; St. Bernard, population 67,002; and Orleans, population 489,595).'
Assuming 50 percent of royalty losses will affect these parishes is highly conservative given that
the majority of Major Pass discharger production is from state and federal offshore waters.7
Since the SBA defines small community as having a population of 50,000 or less, only
Plaquemines Parish is considered a small community.
The total royalty loss associated with Major Pass dischargers is $6.5 million over the
approximately 10-year life of these operations, which is only 0.8 percent of total royalties
generated by these operations (see Table 5-5). Annualized, this loss is $0.9 million per year.
EPA distributed 50 percent of this loss ($0.5 million) on the basis of population, yielding a loss
of $0.44 per person in the four parishes. EPA thus estimated that Plaquemines Parish might lose
$11,437 annually as a result of Coastal Guidelines. On a per person basis, the $0.44 per person
loss is 0.004 percent of the parish's per capita income of $11,262.8 EPA guidance for
performing regulatory flexibility analyses on communities suggests the use of the regulatory cost
to the community as a percentage of per capita income in the affected community as a measure
of the significance of impact on the community. Note that even if 100 percent of the royalty
losses affected the parishes of concern, the impacts would be very small. EPA thus concludes
that the impact on the parish is negligible.
Alternative Regulatory Baseline
Including the three small firms in the current regulatory baseline, EPA's alternative
regulatory baseline includes a total of 59 small firms that are expected to incur compliance costs
as a result of achieving zero discharge of produced water, or 16 percent of 371 total small firms
'Bureau of Labor Statistics data (1992 data, as reported by the U.S. Census Bureau at
Internet Address: http://blue.census.gov/datamap/www/index.html).
7Major Pass Dischargers Data Submittals (CBI data; in CBI rulemaking record).
"Bureau of Labor Statistics data (1989 data inflated to 1995, as reported by the U.S. Census
Bureau at Internet Address: http://blue.census.gov/datamap/www/index.html).
11-7
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estimated to be operating coastal subcategory wells in the Gulf Coastal area. The small firms
that may incur compliance costs under the alternative regulatory baseline are similar to, and may
actually be better off financially than, the entire regulated coastal universe of small firms (see
Chapter Ten).
Tables 10rl2 and 10-13 in Chapter Ten present the results of analyses using a benchmark
of a 5 percent change in working capital and equity to identify potentially significantly affected
firms. A total of 12 out of 22 firms for which EPA had received financial information in the
Section 308 Survey (estimated to represent approximately 28 of the 56 firms, or 50 percent) had
changes in both working capital and equity of more than 5 percent (or were estimated to have a
less than 5 percent change in equity but reported negative working capital, or were estimated to
have a very large change in working capital).
Upon further investigation, however, EPA found that most (10) of these firms either
would fail in baseline, would plug and abandon their coastal operations in the baseline because
of negative earnings among those operations, would plug and abandon or sell their operations
because of the very small contribution the operations made to their overall earnings, or would
meet zero discharge requirements but show adequate returns on assets and equity (see Table 10-
13 in Chapter Ten).
EPA identified two firms that might or might not face sizeable impacts (see Table 10-12
in Chapter Ten of this FEIA). Due to lack of information, however, it is impossible for EPA to
determine the magnitude of the impacts because EPA believes these firms might be the
operators, not the owners, of the wells in question. Thus their revenues might not reflect the
revenues of the affected production facilities and these firms might not bear the costs of
pollution control. To be conservative, EPA assumes these two firms would be severely affected
(i.e., they would fail) because there is no information to indicate the contrary. Additionally, no
other firms among those analyzed under the current regulatory baseline are expected to fail even
with the additional produced water cost for a Major Pass discharger under the assumptions of
the alternative baseline (costs are approximately 20 percent higher for this discharger under the
alternative regulatory baseline). EPA estimates that the two firms identified as possible firm
failures represent 4 out of the 59 small firms estimated to be affected by compliance costs (7
11-8
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percent of these firms) in the alternative baseline. The actual impact of the regulation must be
measured against the total number of small firms that are regulated by the Coastal Guidelines
but that are meeting the requirements of the rule. EPA estimates that 356 small firms will be
regulated by the Coastal Guidelines once baseline firm failures are accounted for.9 Thus the
Coastal Guidelines will have a substantial effect on only 1 percent (four firms) out of all
regulated small firms. EPA considers the difference between 0 percent of large firms and 1
percent of small firms experiencing substantial impacts to be small, given that 85 percent of all
firms in the Gulf coastal region are estimated to be small (see Section 11.2.3 above). The
Agency concludes that the rule does not disproportionately affect small firms.
The skills needed to meet the requirements of the Coastal Guidelines are the same as
those discussed above for Major Pass operators. Again, many of the operators have direct
experience with similar operations (such as waterflooding or injection for disposal at other
locations) since most of them also operate onshore wells.10 Recordkeeping skills would be
similar to those required for NPDES permitting and some recordkeeping requirements would be
reduced since monitoring reports would not be required under zero discharge.
EPA also considered impacts on small communities (counties and parishes) in Texas and
Louisiana resulting from losses in royalties. As in the current regulatory baseline, EPA assumed
that the counties and parishes of concern (see Table 11-1) would lose 50 percent of the
annualized royalty losses attributed to the Coastal Guidelines although this percentage is high,
since the states and individuals are also royalty owners in these areas (actual royalties may be in
the 5- to 10-percent range, although EPA does not know the exact percentage of royalties that
might be received by local governments). EPA used the same method as under the current
regulatory baseline, distributing the annualized losses by population in the affected counties and
parishes. As Table 11-1 shows, the loss per person in Texas counties of concern is $0.12, given
an annualized loss of $0.5 million (which is associated with a 6.2 percent loss of total royalties
'In the PEIA (Chapter Nine), EPA estimated that out of an estimated 371 small firms, 354
small firms would be regulated post-baseline based on the Section 308 Survey results and after
the results of baseline closures were considered. Added to this are two of the three Major Pass
small firms not in the Survey universe, for a total of 356 small firms.
10Section 308 Survey Questionnaires (CBI data; in rulemaking record).
11-9
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generated by the Texas Individual Permit Applicants; see Table 10-5). Out of the 9 small
counties, the greatest impact is in Willacy County, where the per capita income is $7,201; royalty
losses on a per-person basis are 0.002 percent of per capita income in this county. Again,
royalties lost as a percentage of per capita income is used as a measure of impact as suggested by
recent EPA guidance.
In Louisiana, the greatest impacts are associated with the four parishes assumed affected
by impacts on Major Pass dischargers (which are associated with royalty losses of $6.5 million
over the life of the project or 0.8 percent of all royalties as generated; see Table 10-7), since
these four parishes are also assumed to be affected by impacts on Louisiana Open Bay
dischargers (which are associated with royalty losses of $17.7 million over the life of the project
or 10.2 percent of total royalties generated; see Table 10-5). The only small community in this
group is Plaquemines Parish, which EPA estimates will be affected by an estimated $33,754 loss
in royalty payments per year (see Table 11-1), or $1.30 per person in the parish ($0.44 of which
is attributable to impacts on Major Pass dischargers and $0.86, to impacts on Open Bay
dischargers). This per-capita loss is 0.012 percent of income in the parish. The other two
counties in the affected areas of Louisiana considered small in this analysis are estimated to
experience losses in royalties totaling $7,870 in Cameron Parish ($0.86 per capita or 0.007
percent of income) and $38,268 in St. Charles Parish ($0.86 per capita or 0.006 percent of
income). Note that even if 100 percent of the royalties were lost by the affected counties and
parishes, impacts would still be very small.
EPA concludes that impacts on small counties and parishes in Texas and Louisiana under
the assumptions of the alternative baseline are negligible.
11.3.3 Issues Addressed in Public Comments and EPA's Responses
EPA received comments that the rule should not require firms discharging produced
water to open bays in Louisiana (assuming the state changes its law requiring zero discharge) and
firms in Texas (predominately small firms) that had applied for individual permits to meet zero
discharge requirements because the economic impact might be severe for these small firms.
11-10
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TABLE 11-1
IMPACT ON COUNTIES AND PARISHES
POTENTIALLY AFFECTED UNDER THE
ALTERNATIVE BASELINE ASSUMPTIONS
Total Per Capita
Population fal Income fbl
Texas
Cameron
Willacy
Kenedy
Kleberg
Nueces
San Patricio
Refugio
Aransas
Calhoun
Jackson
Matagorda
Galveston
Brazoria
Harris
Chambers
Jefferson
Orange
Totals
Louisiana
Cameron
Vermillion
Iberia
StMary
Terrebonne
Lafourche
St Charles
Jefferson
Plaquemines
St Bernard
Orleans
Totals
278,687
18,278
439
30,377
300,815
60,600
7,839
19,188
20,106
12,937
37,946
203,857
2,971,755
228,084
20,543
243,257
83,080
4,537,788
9,125
50,326
69,631
58,018
99,796
86,723
44,372
457,738
25,877
67,002
489,595
1,458,203
$8,447
$7,201
$10,921
$11,357
$13,510
$11,173
$12,443
$13,507
$12,298
$12,122
$13,484
$16,588
$15,966
$18,022
$14,484
$14,638
$13,625
$12,553
$10,375
$11,222
$10,405
$11,268
$10,966
$14,108
$15,228
$11,262
$12,462
$13,481
Cost per Cost per Cost as % of Per
County Person Capita Income
$32,698
$2,145
$52
$3,564
$35,295
$7,110
$920
$2,251
$2,359
$1,518
$4,452
$23,919
$348,678
$26,761
$2,410
$28,541
$9,748
$532,421
$7,870
$43,403
$60,053
$50,037
$86,069
$74,794
$38,268
$550,389
$31,115
$80,564
$588,694
$1,611,256
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.12
$0.86
$0.86
$0.86
$0.86
$0.86
$0.86
$0.86
$1.20
$1.20
$1.20
$1.20
0.001%
0.002%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.001%
0.007%
0.008%
0.008%
0.008%
0.008%
0.008%
0.006%
0.008%
0.011%
0.010%
0.009%
[a] 1992 data.
[b] 1989 data inflated to 1995.
Source: Bureau of Labor Statistics data, as reported by the U.S. Census
Bureau at Internet address:
http:7ftlue.census.gov/datamap/www/rndex.htinl
10/30/96COUNTEMP.WK4
11-11
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These comments have been addressed in detail in Chapter Ten of this FEIA, in the
Comment/Response Document,11 and in the discussion in Section 11.3.2 regarding effects on
firms under the alternative baseline assumptions. EPA thoroughly investigated the possibility
that 56 additional small firms might be adversely affected by the Coastal Guidelines. As part of
this investigation, EPA has undertaken a detailed financial analysis of the small firms for which it
obtained financial data. A summary of the results of this analysis are presented above in Section
11.3.2, in Section Ten of this FEIA, and in the Comment/Response Document for the Final Rule
and the record for this rule.
EPA also received comments from one small Major Pass discharger that presented its
own assessment of impact. EPA carefully reviewed all the data received from the firm, which
showed the firm to be financially healthy and growing prodigiously. Even the results of several
sensitivity analyses using substantially higher compliance costs than EPA anticipates the firm will
actually experience showed no major impacts on production.12 While acknowledging that the
firm will experience impacts, possibly in the form of slower growth, EPA does not expect the
impacts to be of a magnitude to cause firm failure.
Finally, EPA received a comment noting that small firms might have difficulty raising the
necessary capital to meet zero discharge requirements. EPA has analyzed cash flow and returns,
and where data were available, credit lines and capital expenditure budgets, all of which are
methods used to judge whether the firms in question are likely to be able to raise the capital they
need to meet zero discharge requirements (see Chapters Six and Ten of this FEIA). Where
EPA was uncertain whether a firm could raise the capital needed, it estimated a firm failure.
Thus, none of these comments changed EPA's conclusions that the Coastal Guidelines
will not have a significant impact on a substantial number of small firms: significant impacts are
"U.S. EPA Responses to Public Comments on the Effluent Limitations Guidelines and New
Source Performance Standards for the Coastal Subcategory of the Oil and Gas Extraction Point
Source Category, October 1996.
"Compliance Cost Sensitivity Analysis of a Major Pass Discharger (CBI data; in rulemaking
record).
11-12
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limited to 1 percent of small firms subject to the Coastal Guidelines, and nearly all small firms
should be able to raise the necessary capital to comply with the rule.
113.4 Significant Alternatives to the Rule
EPA's selected option for produced water/TWC (Option #2), which requires all coastal
firms, aside from those in Cook Inlet, to meet zero discharge from their coastal oil and gas
operations was selected because it is technologically available, economically achievable, and has
acceptable nonwater quality environmental impacts.
As stated in the Preamble to the rule, this rule generally codifies in the Code of Federal
Regulations existing permit requirements that have been developed on a "Best Professional
Judgment Basis" under Section 402(a)(l) of the Clean Water Act. These permits have generally
already established zero discharge for drilling fluids and drill cuttings and for produced water,
except for certain dischargers to the major passes of the Mississippi. Under Sections 304 and
307 of the Clean Water Act, EPA is to consider a number of factors in establishing effluent
limitations guidelines and standards, including whether the requirements are technologically and
economically achievable and whether they have acceptable nonwater quality environmental
impacts. EPA has found that zero discharge meets these criteria for those facilities that are
currently subject to zero discharge permits and for those facilities that currently do not have an
NPDES permit. As discussed in the Preamble and the Development Document for the rule
considering information in the rulemaking record indicating technological and economic
achievability and acceptable nonwater quality environmental impacts, along with the evidence in
the record showing that many similarly situated facilities are already achieving zero discharge,
EPA did not believe that an alternative allowing discharge in the Gulf of Mexico would provide a
level playing field among dischargers and nondischargers or meet the objectives of the Clean
Water Act.
Because EPA is aware that numerous operators in Texas have applied for individual
permits authorizing discharge of produced water, and that the DOE has questioned whether
discharges to Louisiana open bays should continue to be allowed (despite state law prohibiting
this discharge beyond January 1997), EPA undertook a very detailed review of the economic
11-13
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impacts on these facilities under the assumption that the state law could change and that
individual permits would be granted despite the general permits prohibiting discharge. This
analysis indicates that the firms that are or will be achieving zero discharge are not substantially
different than the discharging, firms EPA analyzed under either the regulatory or the alternative
baselines, and, in fact, the small Louisiana Open Bay and Texas Individual Permit Applicant
dischargers might be slightly stronger financially than the small Section 308 Survey operators as a
whole (see Chapter Ten). EPA does not believe it should take any actions that would enable a
select few small firms associated with Major Pass, Texas Individual Permit Applicants, or
Louisiana Open Bay dischargers to achieve a competitive advantage over these other,
nondischarging small firms in the region that are complying with federal law.
Having considered these impacts under the alternative baseline and finding that zero
discharge is technically and economically achievable for these dischargers, with acceptable
nonwater quality environmental impacts, along with evidence showing that many similarly
situated facilities are already achieving zero discharge, EPA does not believe that an alternative
allowing discharge in the Gulf of Mexico would provide a level playing field among dischargers
and nondischargers or meet the objectives of the Clean Water Act.
11-14
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APPENDIX A
ECONOMIC ASSUMPTIONS USED IN THE PRODUCTION LOSS MODEL
EPA based die economic and financial accounting assumptions used in the economic model on
common oil industry financing methods and procedures.1*2*3 Tax computations in die model reflect the Tax
Reform Act of 1986 (Public Law 99-514).
A.1 MODEL PARAMETERS
A. 1.1 Corporate Income Tax Rates
EPA assumes that the projects analyzed using the production loss model are incremental to the
other activities of the company and that the company has at least $100,000 of net income in addition to the
projects being analyzed. Therefore, the taxable net income from these projects is marginally taxed at the
federal corporate rate of 34 percent.4 In addition, EPA assumes that any net losses in the initial years of a
project (before production comes on line) can be applied to reduce die taxable income of other projects
owned by die same operator, so that an effective tax shield of 34 percent of die loss is realized. In other
words, the yearly net cash outflow under such circumstances is 100 percent minus 34 percent, or 66
percent of die year's loss. These assumptions are appropriate given die customary size and level of
Johnston, Daniel. 1992. Oil Company Financial Analysis in Nontechnical Language. PennWell
Publishing, Tulsa, OK.
Research Institute of America. 1995. The Complete Internal Revenue Code. Research Institute of
America, New York, NY.
3Houghton, James L. 1987. Arthur Young's Oil and Gas Federal Income Taxation. Commerce
Clearing House, Inc., Tulsa, OK.
*A handful of Major Pass operators indicated that they were subject to a corporate tax rate of 35
percent. This is die marginal tax rate applied to corporations with taxable income exceeding $10 million.
In these cases, EPA used die rate reported by die operator (Major Pass Dischargers Data Submittals [CBI
data; in rulemaking record]).
A-l
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activities of firms undertaking oil exploration and production. The basis for federal income is gross
revenues minus royalty payments, severance taxes, depletion and depreciation allowances, expensed
capital investments, state income taxes, and operating costs.
Operators in Louisiana state waters (i.e., the Major Pass and Louisiana Open Bay dischargers) are
subject to state, as well as federal, corporate income taxes. The marginal state income tax rate for these
operators is 8 percent, which assumes mat they have over $200,000 in net income from their combined
enterprises.5 State income taxes, and the state income tax shield generated by any net losses during the
initial years of the project, are treated in the model in the same manner as federal income taxes. Income
taxes paid to states are subtracted from net taxable income to calculate the basis for federal income tax.
A.1.2 Severance Taxes
Operations located in state waters are subject to state severance taxes. Texas state severance tax
rates are 4.6 percent on oil and 7.45 percent on gas. Louisiana imposes severance taxes of 12.5 percent
on oil and $0.07 per Mcf on gas.6 Some Major Pass operators reported severance tax rates less than the
standard ones for Louisiana because they are eligible for various exemptions and tax abatement programs.7
EPA used the rate reported by the operators in analyzing these projects.
The Alaska severance tax structure consists of nominal rates mat are then adjusted downward to
effective tax rates on the basis of a ratio referred to as the Economic Limit Factor (ELF). The nominal tax
rates on oil are 12.25 percent of gross revenues for the first 5 years of production and 15 percent
thereafter. The nominal tax rate on gas is 10 percent. The ELF varies depending on field size, well
productivity, and whether oil or gas is being produced.8
5Commerce Clearing House, Inc. 1994. State Tax Handbook. Commerce Clearing House, Inc.,
Tulsa, OK.
7Major Pass Dischargers Data Submittals (CBI data; in rulemaldng record).
'Logsdon, Charles. 1996. Personal communication between Charles Logsdon, Alaska Department of
Revenue, and Cathy Scholz, ERG, dated August 14, 1996, regarding oil and gas taxes in Alaska.
A-2
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For oil, the ELF is applied only if it is positive. The oil ELF formula is:
/ •snn \ i"00^
ELF = 1 - . 30° H AD
where
PPW = Average oil production per well per day in the field
AD = Average daily production from die field
For the first five years of production: Oil Severance Taxes = Gross revenues x 12.25% x ELF
After the first five years of production: Oil Severance Taxes = Gross Revenues x 15% x ELF
The oil ELF used to be subject to negotiation between the oil company and the Alaska Department
of Revenues. Now, die formula used to calculate the ELF simply shelters small fields from paying
severance taxes. If a field produces less than 300 barrels per day (bpd) per well, the ELF reaches zero.
Furthermore, a new oil field would need to pay tax only if it has 100 million barrels hi reserves and
produces 50,000 bpd when it comes on line. EPA's contact at the Alaska Department of Revenue reported
lhat, given these shelters, fields hi Cook Inlet have not paid oil severance taxes for several years.9
Although the Cook Inlet operators do not pay oil severance tax, they are subject to a production
tax surcharge of $0.05 per barrel. Revenues from this tax are allocated to the Hazardous Release Fund,
which is devoted to environmental clean-up efforts. The economic model for the oil-producing Cook Inlet
platforms therefore includes only a $0.05 per barrel levy; neither the severance tax nor the oil ELF are
applied.
9Logsdon, Charles. 1996. Personal communication between Charles Logsdon, Alaska Department of
Revenue, and Cathy Scholz, ERG, dated August 14, 1996, regarding oil and gas taxes hi Alaska.
A-3
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The ELF for gas differs slightly from that for oil. It does not shelter small fields from paying
taxes and, as a result, gas producers hi Cook Inlet, Alaska, do pay severance taxes. The ELF formula for
gas is as follows:
PPW
where
PPW =
Average gas production per well per day in the field
Gas severance taxes are calculated as follows:
Gas Severance Taxes = Gross Revenues * 10.00% x ELF
The gas ELF is also applied as long as it is positive.
10
The basis for severance tax calculations hi Louisiana, Texas, and Alaska is gross revenues minus
exempt revenues, where royalty payments to state governments are considered exempt revenues.
A.1.3 Royalty Rates
Operators of oil- and gas-producing properties are usually required to pay production royalties to
the lessors or owners of the land. Lessors and owners include the federal government for OCS leases,
state governments for leases located hi state waters, and the state and private owners for leases on land.
In many instances, the royalty rate is a floating rate that varies from year to year, based on a
complex calculation keyed to the amount or mix of production. For the projects modeled, EPA assumed
that an average fixed rate based on the owning company's data yields the best approximation of royalty
payments. The Agency calculated the value of royalty payments for Cook Inlet platforms and Major Pass
10Logsdon, Charles. 19%. Personal communication between Charles Logsdon, Alaska Department of
Revenue, and Cathy Scholz, ERG, dated August 14, 1996, regarding oil and gas taxes hi Alaska.
A-4
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dischargers using owner-supplied information on average royalty rates and estimates of the value of annual
production generated by the model.11'12 Royalty rates for the Louisiana Open Bay and Texas Individual
Permit wells were obtained through the Section 308 Survey. For wells that did not report royalty rates,
EPA substituted the average reported rate among the Louisiana Open Bay dischargers and Texas Individual
Permit applicants.
A.1.4 Depreciation
The Tax Reform Act of 1986 modified the Accelerated Cost Recovery System (ACRS) for
property placed in service after December 31, 1986. Under the modified system, most oil and gas
equipment is classified as 7-year property. The recovery method for this class is the double declining
balance.13 The schedule used to write off capitalized costs in the model is as follows:
Year 1 14.29% of costs
Year 2 24.4996 of costs
Year 3 17.49% of costs
Year 4 12.49% of costs
YearS 8.93% of costs
Year 6 8.92% of costs
Year? 8.93% of costs
YearS 4.46% of costs
EPA defines year 1 in the above table as the first year in which me equipment is placed in service.
According to the relevant accounting principles, this is the first year in which the equipment produces oil
or gas.
"Major Pass Dischargers Data Submittals (CBI data; in rulemaking record).
"Section 308 Survey data.
13Snook, S.B., and WJ. Magnuson, Jr. 1986. The Tax Reform Act's Hidden Impact on Oil and Gas.
The Adviser. December, pp. 777-783.
A-5
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The value of the deduction for depreciation is reduced by inflation. To maintain die constant-
dollar basis of model calculations, EPA adjusted the value of the depreciation deduction downwards in
later years by the inflation rate.
A.l.4.1 Basis for Depreciation
The Tax Reform Act of 1986 repealed the Investment Tax Credit.1*'15 This means that the initial
basis for depreciation is 100 percent of the total capitalized costs.
A.1.5 Oil Depletion Allowance
The Internal Revenue Code allows oil and gas operators to take a deduction from income for
depletion of oil and gas properties. The depletion of wasting assets such as mineral resources is analogous
to depreciation of fixed assets, except that it is based directly on the removal or sale of a portion of total
recoverable reserves (i.e., the asset is reduced directly, rather man through accumulation over several
years, as is done hi depreciation of fixed assets).
In the case of resources removed from a leased property, depletion must be apportioned between
the lessor and the lessee. For oil and gas operators, the operator's share of the total allowable depletion is
equal to 1 minus the royalty rate.
The oil depletion allowance may be calculated on either a cost basis or a percentage basis.
Integrated (major) oil and gas producers are only entitled to a depletion allowance calculated on a cost
basis, but independents are entitled to the higher of either cost or percentage depletion. A flag hi the EPA
model identifies major and independent operators and determines how depletion will be calculated.
"Snook, S.B., and W.J. Magnuson, Jr. 1986. The Tax Reform Act's Hidden Impact on Oil and Gas.
The Adviser. December, pp. 777-783.
"Coopers and Lybrand. 1986. Tax Reform Act of 1986: Analysis. New York, NY.
-------
A.l.5.1 Depletion—Cost Basis
Cost depletion is based on units of production and is used to recover leasehold expenses over the
producing lifetime of die well. As noted above, majors are required to calculate depletion on a cost basis,
but independents may choose between cost- and percentage-basis depletion, depending on which value is
higher.
The formula for cost depletion is as follows:
Total annual depletion = (C - D - S) *
(I)
where:
C = Leasehold costs (bonus bid and geological and geophysical expenses)
D = Accumulated depreciation taken in prior years
S = Salvage value of equipment
P = Barrels of oil produced during the year
R = Recoverable reserves remaining at me beginning of the year (includes P)
Salvage amounts (S) are not subtracted in the EPA model because it is assumed mat the after-tax cost of
removing the infrastructure and retiring the well at the end of its economic life is approximately equal to
its salvage value and mat the salvage value, therefore, has no impact, positive or negative, on cash flow.
The initial basis for calculating cost depletion in EPA's model consists of the bonus bid and the
geological and geophysical expenses. This basis is adjusted downwards to account for depletion taken hi
each period. The portion of the adjusted basis taken as depletion hi any given period is the units sold
during the period divided by the total recoverable units at me start of me period. For simplicity, EPA
assumes mat all units produced hi a period are sold hi the same period.
A-7
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The value of cost basis depletion is reduced in later years by inflation. Thus, the value used by
EPA in calculating annual cash flow is an inflation-adjusted value. The nonadjusted value is used to
calculate the basis for depletion in subsequent years.
Currently, EPA's model commences during the productive phase of the oil and gas projects being
analyzed. Consequently, the leasehold costs are considered sunk costs and will generally be zero; these
costs would be incurred prior to the productive phase of the project. If leasehold costs are zero, cost
depletion will also be zero. EPA's assumption that cost depletion is zero will tend to cause an
underestimation of earnings and, therefore, an underestimation of the productivity of the projects
calculating depletion on a cost-basis. Only integrated (major) oil and gas operators, who must use cost
depletion, are affected by the omission of the depletion allowance. In consequence, all Cook Inlet
operators and some Gulf of Mexico operators have $0 annual depletion. The underestimation of
productivity for these operators is offset, however, by the fact that the sunk costs themselves are not
factored into the analysis.
A.I.5.2 Depletion—Percentage Basis
Percentage depletion is based on revenues from oil and gas, net of oil and gas royalties. Sections
613 and 613a of the Internal Revenue Code contain die rules for percentage depletion.
Only independent operators are permitted to calculate depletion on a percentage basis. The
depletion rate for these operators is 15 percent of gross income (excluding rents or royalties) from each
leased property. The Cook Inlet/Major Pass model calculates percentage depletion amounts for each
operator's individual leases and sums these amounts to develop a figure for each operator's total depletion.
The Louisiana Open Bay/Texas Individual Permit model assumes that each well is a separate lease.
A maximum number of barrels of oil or Mcf of gas can be depleted at the full IS percent per lease
per day in a given year. This is referred to as the "depletable quantity." Currently, the depletable quantity
is 1,000 bbls of oil or 6,000 Mcf gas production per lease per day. For simplicity, EPA converts Mcf gas
into BOE and then calculates depletion based on the 1,000 bbl limit.
A-8
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When production on a given lease is less than or equal to die depletable quantity of 1,000 BOB per day,
depletion is calculated as follows:
Depletion = (Gross Oil and Gas Revenues - Oil and Gas Royalties) * 0.15
When production on a given lease exceeds the depletable quantity of 1,000 BOB per day, die following
formula is used:
Depletion = (Gross Oil and Gas Revenues - Oil and Gas Royalties) * 0.15 I
BOEPD
Depletion is adjusted by die ratio of die depletable quantity (1,000 BOB) to actual production.
The maximum allowable percentage depletion deduction is 65 percent of die operator's total taxable
income for die year before depletion. Any depletion amount disallowed on this basis may be carried over
and applied in die subsequent year, subject to die same 65 percent limitation.
A.1.6 Inflation Rate
The effective value of depreciation and cost-basis-depletion deductions is reduced by inflation since
die expenditures occur in year(s) prior to die deduction. EPA calculates a value for "adjusted depreciation"
as follows:
Adjusted depreciation _ Depreciation in year X
mvearX (1 + inflation rate)Ye«x
An "adjusted cost-basis-depletion" value is calculated in a similar manner.
The inflation rate of 3 percent is die average rate for inflation over die past several years.16
"Statistical Abstract of the United States (average from 1992 to 1995).
A-9
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A.1.7 Discount Rate
The discount rate used in this analysis represents the opportunity cost of capital for investments in
oil and gas production.
For Cook Inlet, EPA discounts annual project cash flows to the present using an 8 percent discount
rate. The 8 percent discount rate is both the rate used hi the Offshore EIA17 and the average reported by
all Section 308 Survey respondents (Section 308 Questionnaires; CBI data hi rulemaking record).
For the Major Pass dischargers, EPA discounts annual project cash flows using a 7 percent
discount rate. This is the production-weighted average for die Major Pass projects that reported a discount
rate to EPA.
For Louisiana Open Bay dischargers and Texas Individual Permit applicants, EPA uses a
company-specific nominal discount rate taken from the Section 308 Survey. The nominal discount rate is
decreased by the inflation factor (described hi A. 1.7) to obtain the real discount rate. For respondents who
were missing data or who indicated a nominal discount rate of less than 4 percent or greater man 20
percent, EPA substituted the average nominal discount rate for operators hi these regions, as reported hi
the Section 308 Survey. The Agency assumes that rates higher than 20 percent are "hurdle rates" rather
than discount rates. The "hurdle rate" is the minimum rate of return required for a company to undertake
prospective projects.
"U.S. EPA. 1993. Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards
of Performance for the Offshore Oil and Gas Industry. Washington, D.C. January.
A-10
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APPENDIX B
EPA ECONOMIC MODEL FOR COASTAL PETROLEUM
PRODUCTION IN COOK INLET, ALASKA,
AND THE MAJOR PASSES OF THE MISSISSIPPI RIVER
B.1 INTRODUCTION
The EPA model for Cook Inlet platforms and Major Pass dischargers simulates die costs and
petroleum production dynamics expected at the platform or facility level in the development and operation
of a coastal oil and gas project. Data to define a platform or facility and its petroleum reservoir are
entered into die 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 10-year drilling period and specific drilling planned during that period.
Furthermore, inputs for a wide variety of variables that define the development and production project can
be user-specified. These inputs include drilling schedules, operating costs, initial petroleum production,
production decline rates, tax rate schedules, and wellhead prices.
The model calculates costs and production performance for each year of the project's estimated
lifetime. 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 proposed pollution control regulations.
B.I.I Modd Phases
The project life of a coastal operation producing oil and/or gas is divided into five phases: 1) from
lease bid to the start of exploration, 2) from die start of exploration to me start of delineation, 3) from die
B-l
-------
start of delineation to die start of development, 4) from the start of development to the start of production,
and 5) production.
The Cook Met/Major Pass model evaluates operations mat have, for the most part, completed the
first four phases and are hi the fifth phase. In some cases, mere may be 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). For multiple-well platforms and facilities, the impetus to increase declining
production is considerable if the operation can maintain profitability. The EPA model is capable of
handling such situations.
The projects modeled are assumed to operate as long as they are profitable, up to 30 years.
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 these periods. Since all the projects examined
using the Cook Met/Major Pass model 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 and
recompleted wells while production from other wells continues). Sunk costs are not incorporated hi
project evaluation. 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.
B.l.2.1 Cash Flows-Categorization
The model deals with a number of basic cash flows (or resource transfers) hi the development and
production phases. The basic cash flows are as follows:
B-2
-------
Development Phase:
Production Phase:
Well drilling costs—costs of drilling a recompletion or new production
well.
Incremental drilling costs—additional costs of drilling due to new or
revised regulation concerning drilling fluids and drill cuttings.
Revenues from oil and gas production—production levels multiplied by
price forecasts.
O&M costs—costs of operating and maintaining the well.
Incremental O&M costs—additional costs due to new or revised
regulations concerning produced water or drilling wastes.
Incremental capital costs—additional costs due to new equipment required
for additional pollution control of produced water or drilling wastes.
B.2 STEP-BY-STEP DESCRIPTION OF THE MODEL
This section provides a sequential overview of how the model operates, starting with the
production phase and ending with die shut down of die project eitiier after 30 years of production or when
die project becomes unprofitable. The inputs, calculations, and outputs for a sample oil and gas platform
are used in Figure B-l to illustrate die model's algoriduns.
The following discussion is based on me computer printout attached to tiiis appendix.
Identification numbers for specific lines are given in die left-hand margin. Table B-l provides a list of
user-specified inputs. All dollar values (e.g., costs and revenues) are expressed in
-------
TABLE B-l
EXOGENOUS VARIABLES USED IN THE COOK INLET/MAJOR PASS
PRODUCTION LOSS MODEL
Line
Number
2
3
5
8
27
28
30
32
33
34
35
37
38
39
42
43
44
45
47
48
49
50
51
52
Parameter
Real discount rate
Inflation rate
Percent of costs considered expansible intangible drilling costs
Pollution control capital costs
1997 estimated oil production
1997 estimated gas production
Oil and gas production decline rate
Oil royalty rate
Gas royalty rate
Federal corporate tax rate
State corporate tax rate
Depreciation schedule
Severance tax rate— oil
Severance tax rate— gas
Years at peak production
Git-peak production rate (bbl/day)
Gas— peak production rate (MM cf/day)
Total number of production wells drilled or recompleted
Wellhead price per barrel— oil
Wellhead price per Mcf— gas
Days of production per year
Total operating costs
Annual pollution control equipment operating cost (produced water)
Pollution control operating cost (drilling wastes)
B-4
-------
Line 3 is die inflation rate. This parameter is used to reduce the value of die deductions for
depreciation and cost-basis depletion in future years (see Appendix A).
Unas 4 and 5 contain information relevant to the calculation of project taxes. The flag in line 4
indicates whether the operation being modeled is an integrated (major) or independent company. As
discussed in Appendix A, 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 intangible drilling costs in the year
in which they are incurred. Intangible drilling costs are estimated, on the average, to represent 60 percent
of die costs of production wells and their infrastructure.1A3 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.2.1 Development Phase
During die development phase, die 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.
1American Petroleum Institute. 1986. 1984 Survey on Oil and Gas Expenditures. Washington, D.C.
October.
2U.S. Department of Commerce, Bureau of the Census. 1983. Annual Survey of Oil and Gas, 1981,
Current Industrial Reports, MA-13k(81)-l.
3U.S. Department of Commerce, Bureau of the Census. 1982. Annual Survey of Oil and Gas, 1980,
Current Industrial Reports, MA-13k(80)-l, March.
B-5
-------
The costs of platform production equipment and other infrastructure are entered in line 7. In the
Cook Inlet/Major Pass model, the value on line 7 is 0 because platform costs have already been incurred
and are considered sunk costs. Additional costs for the construction and installation of pollution control
equipment are entered separately in line 8. EPA assumes that pollution control capital costs are incurred
in year 1.
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
and recompleted wells into estimates of total annual expenses and revenues. Lines 9 through 13 show the
number of new and recompleted wells planned and die costs associated with drilling these wells. The
drilling cost for a well depends on die depth drilled, environmental requirements, and regional costs for
parts and labor.
The development phase in the model is structured to accommodate die drilling of production wells
according to the drilling schedules provided by die operator. Separate entries for die drilling cost per well
and die number of wells drilled each year appear in lines IS dirough 20.
Lines 21 through 23 calculate die costs incurred each year from die drilling of production wells
and the construction of production and pollution control facilities. The total annual capital development
costs are given in line 24.
Expensed development costs, line 25, are die product of total drilling costs (line 24) and die
percent of drilling costs eligible for expensing (line 5). All costs not eligible for expensing are capitalized
and treated as depreciable assets for tax purposes. Note, hi particular, pollution control costs (even
drilling of injection wells) are not eligible for expensing as per tax code requirements. Capitalized
development costs appear in line 16.
B.2.2 Production Phase
In the production phase of die project, a variety of financial and engineering variables interact to
form the well's economic history. Oil and gas production figures for 1997 are given in lines 27 and 28.
B-6
-------
Line 30 provides the production decline rate for oil and gas. The EPA 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 die second year, (0.92)2 or 0.846 barrel in the third year, and so on.
The EPA model is capable of handling cost escalation (see line 31). In mis report, EPA is
considering costs in real terms, and thus no escalation is assumed.
The royalty rates paid to the lessor of the land are provided hi lines 32 and 33. Federal and state
corporate tax rates are listed hi lines 34 and 35. Line 37 is the depreciation schedule for capitalized oil and
gas equipment. State severance taxes on oil and gas are given hi lines 38 and 39, respectively. Note the
flag for calculating severance taxes for Alaska, since these must be adjusted by the Economic Limit Factor
(ELF); see previous discussion of the ELF in Appendix A.
Basic information describing the production phase of the project is listed hi lines 40 through 53.
The number of years mat a well produces at its peak rate is given in lira 42. The per well peak production
rates for oil and gas are given hi lines 43 and 44, respectively. These rates apply to wells drilled or
recompleted and brought on line hi the model years. Once these wells cease producing at peak rates,
production volumes decline annually according to the decline rate hi line 30. The operator's future
drilling plans are summarized hi lines 45 and 46.
The wellhead prices for oil and gas are entered on lines 47 and 48. These values are hi 1995
dollars.
Line 49 indicates the number of days per year that a platform or facility produces. EPA assumes
that the platforms and facilities hi the production loss model operate continuously.
Annual operating costs are entered on line SO, while lines 51 through S3 contain the incremental
operating costs incurred hi complying with pollution control regulations for water and drilling waste
disposal. Note mat drilling wastes are generated by both the recompletion of existing wells and the drilling
of new wells.
B-7
-------
B.2.2.1 Production Volume Calculations
The next several lines in the model calculate annual production volumes for oil and gas, based on
the initial production rates given in lines 27 and 28, the decline rate in line 30, and die operator's future
drilling plans. Line 54 contains the number of producing wells brought into service each year. Line55r
the total barrels of oil produced per day, is the sum of current production (from 1997, declined at the
appropriate rate) and production from the new wells brought into service each year. MMcf of gas per day
(line 59) is calculated in the same manner. The annual oil and gas production numbers in lines 57 an^l (j/Q
are the estimated daily production numbers multiplied by the number of days of production per year (line
5&, repeated from line 49).
In general, production for a group of wells going into service in the same year is calculated as
follows:
-.j . Barrels ^ .
Annual Production = 7??, „ x per Day x Decline Rate* x Dumber
of Wells of Days
where a = year of production - number of years at peak production
For projects with new wells going into service in different years, die equation is expanded in the following
manner:
Daily Production Year 2=3 wells x 500 bopd
= 1,500 bopd
Year 3 = (3 x 500 x 0.92)
B-8
-------
If additional wells were drilled in year 4,
Year 4 = fc x 500 x Q.922) + (3 x 500)
= 1,270 + 1,500 bopd
= 1,770 bopd
and so form.
The price per barrel is repeated in line 58 for convenience in cross-checking the gross revenues
from oil production (line 62). Lines 61 and 63 list the wellhead price per Mcf of gas and gross revenues
from gas production.
B.2.2.2 Income Statement
Lines 61 through 94 comprise an income and cash flow statement that is repeated annually for a
30-year project lifetime (see also lines 103 through 135 and lines 144 through 176). Since most projects
become uneconomical during this 30-year timeframe, line 85 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 117153 86 through 94.
Lines 62 and 63 list revenues from oil and gas production. Total gross revenues for the year are
given in lineJ54. Royalty payments (lines 65 and 66; see lines 32 and 33 for royalty rates) are calculated
on the basis of gross revenues. Severance taxes are then calculated on die basis of gross revenues minus
royalty payments nines 67 and 68; see lines 38 and 39 for severance tax rates). Note that die production
loss model is capable of calculating the ELF applied to severance taxes in Alaska (see Appendix A for a
more complete discussion of Alaska's severance tax regulations). Since the sample project here is
assumed to produce oil only and the oil ELF in Cook Inlet currently is negative (and thus is not applied),
both the oil and gas ELFs are set to zero.
B-9
-------
Net revenues, line 69, are calculated as:
Net Revenues = Total Gross Revenues - Royalty Payments - Severance Taxes
Thus, for year 1:
Net Revenues = $11,617 - $1,452 - $37
= $10,128
Operating costs are given in lines 70 and 71. Line 70 lists the operating costs estimated for the
platform or facility itself. Incremental operating costs for compliance with pollution control regulations
appear in line 71. The latter figure reflects incremental costs due to both produced water and drilling
waste requirements.
Operating earnings (line 721 are defined as net revenues (line 69) minus operating costs (line 70)
minus pollution control operating costs (line 71). For year 2 of the project:
Operating Earnings = Net Revenues - Operating Costs - Pollution Control Operating Costs
= $16,914 - $5,606 - $455 = $10,853
Lines 73 and 74 divide capital costs into two categories for use in calculating the project's taxable
income. Line 73 contains the capital costs mat can be expensed (hi mis case, IDCs, or costs for drilling
new and recompleted wells multiplied by the percentage hi line 5). EPA assumes that oil and gas
companies expense the maximum allowable portion of their capital costs. Line 74 contains the capital
costs that must be capitalized, including pollution control capital costs and nonexpensible development
drilling costs.
The adjusted depreciation allowance hi line 75 is calculated on the basis of the capitalized costs hi
fine 74 and the accelerated depreciation schedule hi line 37. In model year 1, for example, the unadjusted
depreciation allowance is the product of $2,500 (capitalized costs) and the depreciation rate for the
appropriate year (e.g., $2,500 x 14.29% = $357 for the first year of operation for the project [year 1]).
Because the model's values are given hi constant dollars, the figure of $357 must then be adjusted for
B-10
-------
inflation, using the rate in line 3, as follows: $357 -s- (1 + inflation rate)Y
-------
Project cash flows from operations, line K2T are determined by adding costs expensed for tax
purposes, depreciation, and depletion back into earnings after taxes. The net cash flow from operations
for year 2 is $2,382 + $5,621 + $1,623 = $9,626.
Whether or not the project continues to operate is determined on me basis of operating earnings
(line 72). 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 82) will
also be 0. The model prints a " 1" hi line 85 for years in which the project operates and a "0" for years in
which the project does not operate.
In the event mat the project is shut down, certain variables must be recalculated to reflect that oil
and gas are no longer being produced and sold. Lines 86 through 94 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 mat the project is part of a larger, ongoing
company and mat such deductions can be used to adjust taxable income from the company's other
operations.
The income statement for the second and third decades of operation are found
135 and lines 144 through 176, respectively.
s 103 throuh
B.2.3 Summary Statistics
To summarize the project's economics, all costs and revenues associated with the project from
year 1 to its end are put hi present value terms as of the base year, as well as totaled; see lines 177 through
202.
The present value (PV) of total company costs (line_12Q) is the sum of the present values of the
parameters listed hi Table B-2. This parameter provides a measure of the present value of net company
resources expended hi the development and operation of a petroleum project. Entries marked with a "plus"
B-12
-------
in toe column contribute to corporate costs. Surplus depreciation lowers corporate costs and is therefore
marked with a "minus.11
Total company costs for oil are the present values for oil royalties and severance taxes and the oil
portion of the remaining costs (see line_12i). These costs are apportioned by the ratio of oil revenues to
total revenues. An analogous procedure is followed to obtain die total company costs for gas (see line
122).
The capital and die annual operation and maintenance costs for incremental pollution control of
produced water effluents and drilling wastes are given in terms of present value and are annualized at 7
percent over 10 years. The annualized cost is given in line 104. Since capital expenditures for pollution
control equipment generate a tax shield for die company, me net impact of these expenditures on an
operation is equal to the total pollution control capital costs minus die tax shield from depreciation. The
annualized cost widi me depreciation tax shield taken into account is given in line 195.
Oil and gas production is also discounted and stated hi present value equivalent terms (see lines
197 through 199). Corporate costs per barrel, corporate costs per Mcf, and total corporate costs per BOE
are obtained by dividing the present value of die company costs by die present value equivalent of
production (see 200 through 202).
The present value of social costs nines 203 dirougfa 205) provides a measure of die value of net
social resources expended hi die development and operation of coastal petroleum projects. The difference
between company cost and social cost is that die social cost ignores die effects of transfers that do not use
social resources. The items included hi social cost are listed in Table B-2. Social cost per unit of
production is obtained by dividing die social cost by die present value equivalent of production (lines 206
through 208).
B-13
-------
TABLE B-2
COST AND CASH FLOW USES IN THE COOK INLET PRODUCTION LOSS MODEL
Cost or Cash Flow Item
Total capitalized development costs
PV of capital investment cash flows
PV of pollution control costs - operations
PV of pollution control costs - capital
PV of royalties
PV of severance taxes
PV of operating costs
PV of income taxes
PV of surplus depreciation
PV of all investment costs
Company
Cost
+
+
+
-f
+
+
+
_
Social
Cost
+
+
+
Depre-
ciation
+
+
B-14
-------
The net present value of the project, line 209, is calculated as:
Net Present Value = PV of Cash Inflows - PV of Cash Outflows
= PV of Cash Flows from Operations
- PV of Investment Cash Flows
- PV of Leasehold Costs
+ PV of Surplus Depreciation
A positive net present value is indicative of a profitable project at the assumed discount rate (i.e., the
project analyzed generates more revenue than would be generated by investing the capital in another
project with an expected rate of return equal to the assumed discount rate).
The internal rate of return (line 210) equates the present value of capital in the exploration and
development of die project with the present value of the operating cash flows. An internal rate of return
higher man the discount rate is indicative of a profitable project.
The net present value and the internal rate of return are inverse methods of evaluating the
profitability of a project. In calculating the net present value, the discount rate is fixed and the net present
value may vary. In calculating the internal rate of return, the net present value is set to zero and the
discount rate is allowed to fluctuate.
The number of years that the project operates is shown hi line 211. This number reflects the total
number of years that the project operates with a positive cash flow.
B-15
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APPENDIX C
LOUISIANA OPEN BAY AND TEXAS INDIVIDUAL PERMIT
PRODUCTION LOSS MODEL
C.1 INTRODUCTION
This appendix describes in greater detail the production loss model used to estimate impacts to die
Louisiana Open Bay dischargers and Texas Individual Permit applicants. Since the model operates on the
same principles as the model described hi Appendix B, some sections refer to Appendix B for more
information.
The Open Bay/Individual Permit production loss model simulates die costs and petroleum
production dynamics expected hi the operation of die Louisiana Open Bay dischargers' and Texas
Individual Permit applicants' coastal wells. Data to define each well are entered into the model. The
model is structured to be flexible and is capable of using user-specified inputs for a number of variables.
Inputs include, but are not limited to, operating costs, initial petroleum production, production decline
rates, tax rate schedules, and wellhead prices.
The model analyzes the per well data through a series of internal algorithms developed to calculate
die economic and engineering characteristics of each well. Outputs from die model include: production
volume, project economics, and summary statistics on both an annual and an aggregate basis. EPA uses
these annual values and summary statistics to evaluate die incremental effects of pollution control
regulations on each well.
C.1.1 Model Phases
The Louisiana Open Bay and Texas Individual Permit wells analyzed hi die production loss model
are currently producing wells that discharge produced water. Since these wells are evaluated as individual
entities, they have completed die first four phases of an oil and gas project's life as described hi Section
C-l
-------
B.I.I. The production loss model therefore focuses on only die fifth phase, the production phase, hi
estimating the possible effects of die Coastal Guidelines.
The wells in this analysis channel their production to treatment facilities mat may accept produced
water and petroleum from more than one well. The lifetime of the treatment facility is not dependent on
the liftime of an individual well hi this analysis since additional wells may be served by the facility or new
wells may be drilled and served by the treatment facility in the future. Any well closures estimated using
the production loss model therefore do not necessarily reflect the fate of die treatment facility.
C.1.2 Overview of the Economic Model
During the production phase of the well, there are a number of cash flows to consider, including
revenue flows from oil and'gas production, operation and maintenance costs for operating the well, and
incremental costs (both capital and O&M) that stem from new or revised regulations concerning produced
water.
C.l.2.1 Produced Water Assumptions
For all projects, water production is calculated as a function of total fluid production. In other
words, the well is assumed to produce a constant volume of fluid during its lifetime, but the proportion of
fluid that is water will increase as the well ages. To evaluate water production as a function of total fluid
production, EPA needs to estimate several parameters:
• Relationship of oil decline and water increase
• Decline rate of oil production
• Watercut (i.e., percentage of water hi the produced fluid)
EPA assumes that oil production declines at an exponential rate. This is discussed hi Appendix B.
As oil production declines, water production increases, maintaining a constant volume of fluid. Figure C-l
C-2
-------
Constant Total Flow
o
z>
Q
O
OC
0.
Produced Water
TIME
Figure C-l. OiI:Water relationship over time (exponential decline).
C-3
-------
illustrates the oil and water production relationship over time. EPA estimates watercut data by calculating
die ratio of daily water production to daily water and oil production from the Section 308 Survey data.
Since incremental regulatory costs are determined on a per barrel of produced water basis, the
annual costs for produced water disposal increase annually.
C.2 STEP-BY-STEP DESCRIPTION OF THE MODEL
The following is a sequential overview of how the Open Bay/Individual Permit production loss
model operates. The model begins hi the production phase and ends with the shutdown of the well either
after 30 years or when the well becomes unprofitable to operate. Inputs, calculations, and outputs for a
sample oil- and gas-producing well are used to illustrate the model's algorithms.
This discussion is based on Figure C-2, the computer printout attached to the end of mis appendix.
Identification numbers for specific lines are given in the left-hand margin. Table C-l lists user-specified
inputs. All dollar values are expressed in thousands of 1995 dollars, except for per-barrel costs, which are
expressed in untruncated 1995 dollars. Because of rounding, values on the spreadsheet may differ in the
final digit from numbers presented in the text.
C.2.1 General Model Data
Ones 1 and 2 identify the individual well being analyzed. Summary financial rates applied
throughout the model follow. Line 3 is the real discount rate (i.e., the cost of capital). This value is
specific to the well and is determined from oil and gas operator responses to the Section 308 Survey.
Since the value contained hi the Survey data is the nominal discount rate, EPA calculates the real discount
rate using the inflation rate presented hi line 4. In cases where the discount rate was missing or an
operator supplied a discount rate mat appeared to be a hurdle rate (values greater than 20 percent) or mat
had an extremely low value (less than 4 percent), EPA substituted the average nominal rate for operators
who reported a discount rate.
C-4
-------
TABLE C-l
EXOGENOUS VARIABLES USED IN THE GULF OF MEXICO
PRODUCTION LOSS MODEL
Line
Number
3
4
5
6
7
8
9
10
11
13
14
15
17
18
21
22
23
24
25
Parameter
Real discount rate
Inflation rate
Water:oil or watengas ratio
Oil and gas production decline rate
Cost escalator
Royalty rate
Corporate structure (major or independent)
Federal corporate income tax rate
State corporate income tax rate
Depreciation schedule
Severance lax rate— oil
Severance tax rate— gas
Oil— initial production rate (bbl/day)
Gas— initial production rate (MMcf/day)
Wellhead price per barrel— oil
Wellhead price per Mcf— gas
Total operating costs
Pollution control annual cost (per barrel of water)
Days of production per year
C-5
-------
In the production phase of a well, a variety of financial and engineering variables interact to form
the well's economic history. Line 5 provides the water to oil or water to gas ratio for the well. As
discussed previously in mis appendix, mis rate is important in determining the future water production of
the well and adjusting the incremental operating costs appropriately. Line 6 provides the production
decline rate for oil and gas. The EPA model incorporates an exponential function for production decline
(i.e., a constant proportion of the remaining reserves is produced each year). The decline rate predicted
for coastal wells in the Gulf of Mexico region is 15 percent. In other words, each year, a well produces
15 percent less oil and/or gas.
The EPA model is capable of handling cost escalation (see line_2). In mis report, we are
considering costs in real terms, and thus no escalation is assumed.
Lines 9 through 13 list values important hi calculating federal and state tax impacts of pollution
control regulations. Line 9 indicates whether a firm is a major or independent oil producer (i.e., the
firm's corporate structure). As discussed hi Appendix A, the corporate structure is a factor hi the
calculation of the adjusted depletion allowance shown in line 51 and discussed below. Line 10 is the
Federal corporate income tax rate. Line 1 1 is the state corporate tax rate. The state tax rate
changes depending on the state hi which the well is located. For Louisiana, the state corporate tax rate is 8
percent; in Texas, there is no corporate tax on oil and gas.1 Lines 12 and 13 contain the depreciation
schedule for capitalized expenditures on oil and gas equipment. Since the Louisiana Open Bay dischargers
and Texas Individual Permit applicants are analyzed on the well level, expenditures on well
drillmg/recompletion are not included in the model, and the depreciation schedule is not referenced.
Pollution control capital costs, which would generally be depreciated, are instead annualized and
incorporated into the model on a per barrel of produced water basis (discussed later hi mis section).
In addition to taxes, oil and gas operators generally pay royalty and severance taxes. The royalty
rate paid to the lessor of the land is provided hi line 8. This value is a well-specific rate determined from
Survey data. If, in the Survey, the operator reported a royalty rate above 80 percent, EPA adjusted the
rate to 16.6 percent for oil or 16.9 percent for gas. Royalty rates higher than 80 percent are considered
unrealistic, possibly reflecting an operator's working interest share rather than a royalty rate, or resulting
'Commerce Clearing House. 1994. State Tax Handbook. Commerce Clearing House, Inc., Tulsa, OK.
C-6
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from an error in die reporting of royalties in the Survey data.2 State severance taxes on oil and gas are
given in lines 14 and 15 3 Note that the model is capable of calculating die Economic Limit Factor for
Alaska severance taxes. The standard state severance tax rates are used for Louisiana and Texas.
Basic production information used in the model is listed hi lines tfi through 25. The number of
years that a well produces at its initial rate is given hi line 16. Lines 17 and 18 contain die wall's
production rates for oil and gas hi die first year modeled. These numbers are based on well-specific
Section 308 Survey data. Production volumes decline annually hi the model as per die production decline
rate hi line 6.
Wellhead prices per barrel of oil and per Mcf of gas are given hi lines 21 and 11. These values
are inflated to 1995 dollars from Section 308 Survey data.
The operating cost for die well is shown hi line 23. EPA estimated die operating cost per well by
dividing die total operating costs for each individual operator's coastal oil and gas operations, reported hi
die Survey, by die number of coastal wells operated, also reported hi die Survey data. The resulting value
is an average operating cost for a coastal well operated by die Survey respondent. No data were collected
on die annual operating costs for specific wells hi die Section 308 Survey.
The incremental pollution control costs for produced water are given hi line 24. This figure
represents the amount (per barrel of produced water) by which disposal costs will increase because of die
regulation. The per barrel cost is obtained by dividing die estimated annual pollution control costs for a
given facility by die current volume of produced water for that facility. Annual pollution control costs, hi
turn, are determined by annualizing capital costs for pollution control equipment at 7 percent over 10 years
and adding die resultant figure to annual O&M costs. This assumption regarding incremental pollution
control costs is equivalent to die assumption diat die treatment/separation facility is operated such that all
wells must pay tiieir own way. In reality, some wells might not support themselves, but these wells are not
^e Survey asked respondents for total wellhead price and wellhead price net of royalties. The royalty
rate was calculated based on die difference between these two figures. Thus, if a respondent inadvertently
submitted royalties per barrel instead of wellhead price net of royalties, die royalty rate calculated for die
respondent would have been incorrectly estimated at around 80 to 90 percent.
'Commerce Clearing House. 1994. State Tax Handbook. Commerce Clearing House, Inc., Tulsa, OK.
C-7
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shut in because the overall project is more economical with mem producing. It is thus somewhat
conservative to treat pollution control costs in mis manner. Annualizing pollution control capital costs,
moreover, reduces the well's tax shield because the costs are distributed evenly over 10 years, whereas
depreciation allows a producer to reduce tax burdens to a greater extent in me early years of the project.
Tax burdens to the producer are thus overstated in a present value sense.
The model calculates the total incremental cost to the individual well by multiplying the value hi
line 24 by the barrels of water produced each year. Assuming fluid production is constant, the incremental
costs increase each, year as water production increases.
Line 25 shows the number of days per year me well operates. EPA assumes mat the wells in the
production loss model operate continuously.
C.2.L1 Production Volume Calculations
Lines 26 through 35 calculate annual production volumes for oil, gas, and water, based on the
initial production rates given in lines 17 and 18 and the decline rate hi line 6. Production volumes can be
modeled every year for up to 30 years (see also lines 67 through 75 and lines 107 through 115). Lme.26
lists the number of producing wells in service. In the Louisiana Open Bay/Texas Individual Permit model,
this value is always 1 in year 1 because only single wells are analyzed. Line 27 indicates the barrels of oil
per day produced by the well. This figure is multiplied by the number of days of production per year (the
value in line 26 repeated in line 28) to calculate the number of barrels of oil produced annually (line_22).
Annual oil production, hi turn, is multiplied by line 30T the price per barrel of oil (repeated from line 21),
to calculate the revenues generated from mat production. Line 31 shows the barrels of water produced per
day. EPA assumes that the total volume of fluid (oil and water) pumped remains constant, although oil
production declines. Line 32 calculates the sum of the two fluids to check that total fluid is constant.
Lines 33 through 35 calculate the total volume of gas generated per year (note mat the zeroes hi
line 33 are rounded values: the well actually produces approximately 100 Mcf per day hi model year 1).
Total gas revenues are calculated based on the price of gas hi line 35.
C-8
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C.2.2 Income Statement
TJnes 36 through 5.6. comprise an income and cash flow statement that is repeated annually for a
30-year project lifetime (see also lines 76 through 96 and lines 116 through 135). Since some projects
become uneconomical during this 30-year period, line 57 checks for negative net cash flow, which, hi this
model, is primarily driven by operating earnings. When cash flow is negative, EPA assumes the project
shuts down and actual production, revenues, and cash flows are reset to zero hi lines 58 through 64.
Lines 36 and 37 list revenues from oil and gas production. Total gross revenues are given hi line
3&. Royalty payments (lines 39 and 40; see line 10 for the royalty rate) are calculated on the basis of gross
oil and gas revenues. Severance taxes are men calculated on the basis of gross revenues minus royalty
payments (lines 41 and 42; see lines 13 and 14 for severance tax rates).
Net revenues (line 43) represent:
Net Revenues = Total Gross Revenues
Oil Royalty Payments - Gas Royalty Payments
Oil Severance Taxes - Gas Severance Taxes
Thus, for Year 1 for the model well, net revenues are:
Net Revenues = $1,697 - $274 - $9 - $205 - $2
= $1,207
Operating costs are given hi lines 44 and 46. Line 44 lists the operating cost estimated for the well
itself. Incremental operating costs for pollution control appear hi line 45, and are the product of the per-
barrel of produced water cost, the number of days of operation, and the pollution control costs. As
discussed in Appendix A, pollution control costs hi the Open Bay/Individual Permit model reflect the costs
of the pollution control equipment annualized at 7 percent over 10 years, combined with yearly operating
costs.
Operating earnings (line 49) are defined as net revenues (line 43) minus operating costs (line 44)
minus pollution control operating costs (line 46). For Year 1 of the project:
C-9
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Operating Earnings = Net revenues - Operating costs - Pollution control operating costs
= $1,207 - $40 - $19 = $1,148
Depreciation and amortization would normally be subtracted from operating earnings (line 49) to
calculate earnings before interest and ODA in line SO. Because capital costs are included in the per barrel
pollution control costs discussed above rather than considered separately in the Open Bay/Individual Permit
model, both depreciation and amortization are zero and line 50 equals line 49.
As discussed in Appendix A, the depletion allowance (line SI) is a means of treating annual oil and
gas production as a wasting asset for tax purposes. It can be calculated on either a cost or a percentage
basis. Depletion for major producers is zero because there are no leasehold costs included and major
producers deplete on a cost basis. Independent producers deplete on a percentage basis and therefore have
a value for the oil depletion allowance.
Earnings before interest and taxes (EBIT) hi line 52 is defined as earnings before interest and
ODA (line 50) minus the adjusted oil depletion allowance (line 51).
The figure in line 52 serves basis for the calculation of state taxes, shown in ling_54. Federal taxes
(line S3) are men calculated on the difference between EBIT and state taxes. Earnings after taxes are
given, in line SS.
Project cash flows, line S6T are estimated by adding noncash expenses, depreciation, and depletion
back into earnings after taxes. The net cash flow for year 1 is $697, since bom depreciation and depletion
are zero.
The cash flows forecasted for the project may or may not be sufficient to justify continued
operation. Since the capital costs are allocated on a per-barrel cost, it is likely mat in the later stages of a
well's production the revenue from oil and gas production will be insufficient to cover the increasing
operating costs for produced water disposal. If net cash flow is equal to or less man zero in any given
year, the project is assumed to shut down. The model prints a "1" in lineS7 for years In which the project
operates and a "0" for years in which the project does not operate.
C-10
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la die event that the project is shut down, certain variables must be recalculated to reflect die fact
that oil and gas are no longer being produced and sold. Unas 58 through 64 restate production volumes,
revenues, and cash flow in die event of a shutdown; that is, production and revenues are set to zero after
the project shuts down. Depreciation is also recalculated; the final year's capital expenditures are set to
zero, and any depreciation remaining from previous capital expenditures is assumed to be taken as a tax
deduction against fee operator's income from other enterprises. Unexpended capitalized costs and surplus
depreciation are summarized in lines 65 and 66 .
The production information for the second and third decades of operation are found in lines 67
through 75 and lines 107 through 115T respectively. The corresponding income statements are shown in
lines 76 through 106 and lines 116 through 143.
C.2.3 Summary Statistics
To summarize the project's economics, all costs and revenues associated with the project from
year 1 to its end are put in present value terms as of the base year, as well as totaled; see lines 144 flirnugh
183.
The present value of total company costs (linfi_157_) is the sum of the present values of die
parameters listed hi lines 146 through 156, subtracting PV of surplus depreciation (line 145). This
parameter provides a measure of the present value of net company resources expended La operation of the
petroleum project.
Total company costs for oil are die present values for oil royalties and severance taxes and die oil
portion of die remaining costs (see line 158). These costs are apportioned by die ratio of oil revenues to
total revenues. An analogous procedure is followed to obtain die total company cost for gas (see line 15Q).
The capital and die annual O&M costs for incremental pollution control of produced water
effluents are given hi terms of present value and are annualized over die economic lifetime of die well.
The annualized cost is given hi line 160. This is die annualized cost of die present value of die pollution
control costs that were incorporated into die model on a per-barrel of produced water basis.
C-ll
-------
Hie capital and the annual O&M costs for incremental pollution control of produced water
effluents are given in terms of present value and are annualized over the economic lifetime of the well.
The annualized cost is given in line 160- This is the annualized cost of the present value of the pollution
control costs mat were incorporated into the model on a per-barrel of produced water basis.
Oil and gas production is also discounted so mat they can be stated in present value equivalent
terms (see lines 167 through 170). Corporate costs per barrel and corporate costs per Mcf are obtained by
dividing the present value of the company costs by the present value equivalent of production (see lines 171
through 174).
The present value of social costs (lines 175 through 177) provides a measure of the value of net
social resources expended hi the development and operation of coastal petroleum projects. The difference
between company cost and social cost is mat the social cost ignores the effects of transfers mat do not use
social resources. The items included hi social cost are operating costs and investment costs. Social cost
per unit of production is obtained by dividing the social cost by the present value equivalent of production
nines 178 through 181).
The number of years the project operates is shown hi line 182. This number reflects the total
number of years that well operates with a positive cash flow.
The net present value of the project, line 183r is calculated as:
Net Present Value = PV of Cash Inflows - PV of Cash Outflows
= PV of Operating Cash Flows
- PV of Expensed Investment Cash Flows
- PV of Capitalized Costs
- PV of Leasehold Costs
+ PV of Surplus Depreciation
A positive net present value is indicative of a profitable project at the assumed discount rate; mat is, the
project analyzed generates more revenue man would be generated by investing the capital hi another
project with an expected rate of return equal to the assumed discount rate.
C-12
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