&EPA
United States
Environmental Protection
Agency
Economic Analysis for Existing and New
Projects in the Coalbed Methane
Industry
EPA 820-R-13-006
July 29, 2013
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Table of Contents
Introduction 1
1 CBM Industry Overview 2
2 Data Sources, Universe, and Wastewater Management Alternatives 5
2.1 Data Sources 5
2.1.1 CBM Survey 5
2.1.2 Publicly Available Data 5
2.2 Analyzed CBM Projects and their Baseline Characteristics 6
2.2.1 Existing Projects 6
2.2.2 New Projects 8
2.3 Wastewater Management Technologies Considered 10
3 Economic Analysis - Existing Sources 11
3.1 Baseline Closure Analysis 12
3.1.1 Analysis Approach and Data Inputs 12
3.1.2 Baseline Analysis Results 16
3.2 Post-Requirements Analysis 17
3.2.1 Analysis Approach and Data Inputs 17
3.2.2 Post-Requirements Analysis Results 18
Immediate Project Closures 18
Production Years Lost at Remaining Projects 18
3.3 Uncertainties and Limitations 22
4 Economic Analysis - New Sources 23
4.1 Methodology, Data Sources, and Assumptions 24
4.1.1 Summary of the Project Economic Analysis 24
4.1.2 Price Projections 25
4.1.3 Estimating the Potential for Delay and Reduced CBM Gas Production Due to Treatment
Technology Costs 26
4.2 Analysis Results 27
4.2.1 Using 17-Percent Required Rate of Return (Hurdle Rate) 28
4.2.2 Using 7-Percent Required Rate of Return (Hurdle Rate) 30
4.3 Uncertainties and Limitations 33
Conclusion 35
Appendix A Developing Wellhead Price Forecasts 37
A.I Available Data 38
A.2 Price Adjustments 38
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A.2.1 Existing-Source Analysis 38
A.2.2 New-Source Analysis 40
A.3 Uncertainties and Limitations 43
References 45
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Index of Tables
Table 1-1. Total CBM Gas Production (Million Cubic Feet), 2007-2011 2
Table 2-1. Project Inputs Used in Existing Source Analysis 7
Table 2-2: Estimated Average Annual Gas and Water Decline Rates 8
Table 2-3. Model Project Characteristics3 9
Table 2-4. Wastewater Management Costs 10
Table 3-1: Production-Years and Natural Gas Production Foregone due to Wastewater Discharge
Requirements in Immediate Project Closures and in Projects that Remain in Productiona'b'°'d 20
Table 4-1: Compound Annual Growth Rates for Natural Gas Wellhead Prices , 2013- 2040 26
Table 4-2: Effect of Wastewater Discharge Requirements on New CBM Projects, Using 17 Percent
Hurdle Ratea 30
Table 4-3: Effect of Water Discharge Requirements on New CBM Projects, Using 7 Percent Hurdle Ratea
33
Table A.2-1: Year-Over-Year Percent Changes in Gas Wellhead Prices 39
Table A.2-2: Basin Specific Price Projections for the Reference Case (CAGRof 3.3%) 41
Table A.2-3: Basin Specific Price Projections for the Low Price Growth Case (CAGRof 3.0%) 42
Table A.2-4: Basin Specific Price Projections for the High Price Growth Case (CAGRof 3.4%) 43
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Economic Analysis of Treatment Technology Options for CBM Projects | pg iii
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Introduction
In 2007, EPA began a detailed study of the coalbed methane (CBM) extraction industry and collected
data on the industry through: (1) meetings with stakeholders, (2) site visits, and (3) the Detailed
Questionnaire Coalbed Methane Extraction Sector and the 2008 Coalbed Methane Industry Screener
(Detailed Questionnaire and Screener Questionnaire or CBM survey). The report, Coalbed Methane
Extraction: Detailed Study Report (Detailed Study Report) dated December 2010 presented EPA's initial
technical and economic industry profile and EPA's preliminary review of the information collected as
part of the detailed study. Based on this detailed study, EPA announced in the final 2010 Effluent
Guidelines Program Plan, its plan to develop effluent limitations guidelines and standards (ELGs) for the
CBM extraction industry. Following its announcement to undertake the rulemaking, EPA continued
analyzing the information collected from the CBM industry and also collected and analyzed more current
data. Some of EPA's findings have changed since EPA selected this industry for rulemaking. To update
the public on technical aspects, EPA developed the Technical Development Document for the Coalbed
Methane Extraction Industry dated March 2013 (Technical Development Document) (DCN CBM00669).
EPA used the information provided in the Technical Development Document to develop the economic
analysis described in this document.
This document describes the economic analysis that EPA conducted since initiating the CBM rulemaking,
including methodology, data, and results. EPA first assessed the status of the CBM industry as of 2008,
i.e., the year for which the CBM survey collected detailed data. In light of the significant reduction in gas
prices since 2008, EPA assessed which CBM projects operating in 2008 based on the CBM survey may
have shut down since the time of the survey, or would potentially shut down, as a result of unfavorable
economics in current conditions (baseline analysis). Following the baseline analysis, EPA analyzed the
potential economic impact of additional controls on wastewater discharges on project economics (post-
requirements analysis). EPA performed a similar analysis to assess current and future economic
conditions for new CBM projects1, and to evaluate whether new regulations would constitute a barrier to
entry for new projects.
This document is organized as follows:
> Section 1 provides a brief overview of the CBM industry
> Section 2 describes the data sources and specific data items used in the economic analysis, the
universe of analyzed existing and new projects, and wastewater management technologies
considered
> Section 3 discusses methodology and assumptions used to assess economic impact of wastewater
management requirements on existing CBM sources.
> Section 4 discusses methodology and assumptions used to assess economic impact of wastewater
management requirements on new CBM sources.
> Appendix A describes how EPA developed projections of natural-gas prices used in the economic
analysis.
> References lists data sources and other references used in EPA's economic analysis.
1 EPA defines a new source as a new CBM project, which can be as small as a single well or a lease with just a few wells, or
as large as over 1,000 wells on multiple leases.
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1 CBM Industry Overview
CBM is the natural gas contained in and removed from coal seams. Unconventional gas is natural gas
trapped in underground rocks which is hard to reach and/or extract using conventional methods from the
geological formation containing the gas. CBM extraction requires drilling wells into coal seams and
removing formation water to reduce hydrostatic pressure and to allow adsorbed CBM to be released from
the coal. The formation water removed from the coal seam is called produced water.
Typically, a CBM well will produce gas for between 5 and 15 years, although wells in some areas may
have a longer lifespan. CBM wells go through the following production stages:
> An early stage, during which large volumes of formation water are pumped from the seam to
reduce the underground pressure and encourage the release of natural gas from the coal seam;
> A stable stage, during which the amount of natural gas produced from the well increases as the
amount of formation water pumped from the coal seam decreases; and
> A late stage, during which the amount of gas produced declines and the amount of formation
water pumped from the coal seam remains low (De Bruin et al., 2001).
CBM operators typically plan and operate multiple-well projects, which are structured to achieve
economically efficient recovery of the CBM gas, accounting for such considerations as the well-spacing
that is needed to efficiently recover the resource in place. EPA defines a CBM project as a well, group of
wells, lease, group of leases, or some other recognized unit that is operated as an economic unit when
making production decisions. A project can be as small as a single well or a lease with just a few wells, or
as large as over 1,000 wells on multiple leases. All wells in a project may not be drilled at the same time;
therefore, a CBM project can have a longer lifespan than the longest-lived well in that project. EPA
identified 15 CBM basins producing gas in 2008. Section 3 of the Technical Development Document
provides additional background on CBM production.
Table 1-1 summarizes the total gas production from CBM formations in the United States between 2007
and 2011, as published by the Energy Information Administration (EIA) of the U.S. Department of
Energy (DOE) (U.S. DOE, 2013a)0. As shown in Table 1-1, CBM gas production peaked in 2008 at just
over 2 trillion cubic feet. This peak production year also coincides with the calendar year in which EPA
collected information in the Detailed Questionnaire (see Section 2.1.1). Table 1-1 also presents total
production of shale gas, which is also unconventional gas. As shown in Table 1-1, while CBM production
declined since 2008, production of shale gas increased significantly from 2007 to 2011.
Table 1-1. Total CBM Gas Production (Million Cubic Feet), 2007-2011
Industry
Coalbed Methane Wells
Shale Gas Wells
2007
1,999,748
1,990,145
2008
2,022,228
2,869,960
2009
2,010,171
3,958,315
2010
1,916,762
5,817,122
2011"
1,779,055
8,500,983
a. Data for 201 1 are estimated.
Source: U.S. DOE, 2013a
The substantial increase in gas production from shale formations coupled with a weak economy has led to
significant declines in natural gas prices. Figure 1-1 presents national average U.S. natural gas wellhead
prices for 2000 through 2012, and EIA-projected prices through 2040. Gas prices generally vary by state.
For example, Henry Hub, which is a major gas distribution hub and pricing point for gas futures in the
United States, is located in Louisiana. The higher the transportation cost to Henry Hub, the lower the
wellhead price received by the operators. Because transport costs from states located near Louisiana are
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Economic Analysis of Treatment Technology Options for CBM Projects | pg 2
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much lower than those from the Rocky Mountain area, the average wellhead price for states such as
Texas, Louisiana, and Alabama are higher than in the Montana or Wyoming. As shown in Figure 1-1, in
2008, average annual U.S. wellhead gas prices were at a historic high of $7.97 per Mcf. In 2009, the price
of gas fell by 54 percent, to $3.67 per Mcf. While EIA projects that gas prices will rise steadily over the
next few decades, EIA does not expect to prices to reach the 2008 price level (on an inflation-adjusted
basis) until 2040.
Figure 1-1: U.S. Natural Gas Prices 2000 to 2012 and Projected Prices through 2040
U.S. Natural Gas Prices and Projections
$9.00
$8.00
$7.00
U.S. Natural Gas Wellhead Prices (nominal dollars)
U.S. Projected Natural Gas Henry Hub Spot Prices
Year
Source: U.S. DOE red line (square)2013b and green line (triangle)2012b
Produced water (or wastewater) requires some form of management (e.g., use or disposal). CBM
operators often combine produced water from multiple wells, and occasionally multiple projects, into a
Produced Water Management System (PWMS). In some cases, operators transfer this wastewater to
another operator's PWMS for management and disposal. CBM well operators use a variety of methods to
manage, store, treat, and dispose of CBM produced water. Section 4 of the Technical Development
Document provides information on produced water management and treatment.
Generally, for purposes of this analysis, EPA classified wastewater management alternatives based on the
type of wastewater discharge as follows:
> Discharge - Either direct discharge to surface water or indirect discharge to publicly-owned
treatment works (POTW); or
> Zero discharge - Includes the following alternatives: underground injection,
evaporation/infiltration ponds, land application (for crop or non-crop production), livestock or
wildlife watering, or transferring the water off-site .
Generally, operators may manage the produced water from a single project by both discharge and zero-
discharge methods, either applied separately or in combination for the same project.
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As discussed in the Technical Development Document, EPA identified the following seven basins in
which direct discharge is practiced by at least one project (discharging basins) out of the 15 CBM basins
producing gas in 2008:
1. Appalachian;
2. Black Warrior;
3. Cahaba;
4. Green River;
5. Illinois;
6. Powder River; and
7. Raton.
The remaining eight basins use only zero-discharge methods for disposal. As a result, EPA focused the
economic analyses on these seven discharging basins because ELGs would only lead to possible
incremental costs for CBM projects that discharge some portion of their produced water. Even though the
analysis focused only on the seven basins in which some projects are not zero-discharge, EPA views the
analysis as nationally representative because the projects in the remaining basins already use one of the
technologies analyzed and therefore would face no incremental cost. EPA expects changes to industry
economics due to declining gas prices to have a similar effect on all CBM projects, both discharging
projects and those that use zero-discharge methods for managing produced water (both in discharging
basins and non-discharging basins). Drilling costs, gas production costs, and available produced water-
management methods and costs vary by basin; therefore, the overall financial impact of reduced gas
prices will also vary by basin. Because surface water discharge generally does not require transport of the
produced water, it entails lower private costs of disposal than zero-discharge methods. Because of the
generally higher costs for using zero-discharge methods for produced water discharge, EPA expects that
declining gas prices will have a similar adverse effect on the economics of CBM projects that use zero-
discharge methods for managing produced water (both in discharging basins and non-discharging basins),
to the effect estimated for discharging projects.
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2 Data Sources, Universe, and Wastewater Management Alternatives
This section describes the data sources and specific data items used in the economic analysis, the universe
of analyzed existing and new projects, and wastewater management technologies considered.
2.1 Data Sources
EPA used information reported in the Detailed Questionnaire, supplemented with data from publicly
available sources, to conduct the economic analysis for new and existing CBM projects. The following
subsections provide a brief description of these data sources. Additional information can be found in the
Detailed Study Report and Technical Development Document.
2.1.1 CBM Survey
In 2009, EPA distributed a Screener Questionnaire to all CBM operators that had three or more CBM
wells with production in 2006. The Screener Questionnaire requested that operators provide the following
information on all projects operating as of 2008: verification that the operator produced CBM in 2008;
identification of small businesses and number of projects operated; and, for each project, information on
numbers of wells, gas production, and produced water management methods.
Using information gathered through the Screener Questionnaire, EPA identified a representative sample
of over 200 CBM projects across the country. EPA distributed a Detailed Questionnaire to this sample,
requesting technical, financial, and economic data at the project level. The Detailed Questionnaire
collected information for calendar year 2008 and represented a 'snapshot' of the industry during this one-
year period. The one-year 2008 snapshot contains information for projects at various production stages.
EPA distributed the Detailed Questionnaire to all CBM projects that discharged except for some projects
in the Powder River Basin. Because the Powder River Basin had several operators with a large number of
projects, to reduce the burden on these operators, EPA selected a statistical sample of discharging
projects. The memorandum Development of Final Survey Weights for CBM Analyses (DCN CBM00653)
explains how EPA scaled the results of the project-level analysis to the industry level.
The majority of data reported in the Detailed Questionnaire were claimed Confidential Business
Information (CBI). Of the 87 operators responding to the Detailed Questionnaire, approximately 70
percent claimed the entire response CBI and all operators claimed some portion of their response to be
CBI. Therefore, EPA is not in a position to provide full data for individual projects, operators, or basins in
public documents. The memorandum Summary of Confidential Business Information Claims in the
Industry Responses to EPA 's Screener and Detailed Questionnaire and Data Available in the EPA
Docket (DCN CBM00661) provides information on the CBI claims and the information that can be
released to the public.
2.1.2 Publicly Available Data
Due to changes in the industry since 2008, EPA supplemented the data collected in the Detailed
Questionnaire with more current publicly available data. EPA reviewed the sources listed below to
identify changes to gas prices and operating status of analyzed existing CBM projects.
> U.S. DOE's EIA - Information on projected natural gas production, wellhead prices, and other
supplemental information (http: //www. eia. gov/).
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> State oil and gas websites - Gas and water production data used to evaluate changes in operating
status, from the following States:
• Colorado (Raton Basin)
• Wyoming (Powder River and Green River Basins)
• Pennsylvania (Appalachian Basin)
• West Virginia (Appalachian Basin)
• Alabama (Black Warrior and Cahaba Basins)
• Montana (Powder River Basin)
2.2 Analyzed CBM Projects and their Baseline Characteristics
Because the Detailed Questionnaire collected information at the project level, EPA conducted technical
and economic analyses at the level of a project. As detailed in Chapters 3 and 4 of this document, EPA's
economic analysis for both existing and new projects, assesses the economic viability of a project over its
estimated lifetime in the baseline and post-requirements scenarios. EPA used pre-tax operating income to
assess the economic viability of a project. This section describes specific data items EPA used to calculate
baseline pre-tax operating income for existing and new projects. It also describes the universe of existing
and new CBM projects for which the Agency conducted economic analysis.
2.2.1 Existing Projects
As discussed in the Technical Development Document, EPA identified 73 existing direct-discharge
projects based on the data received through the CBM survey for 20082. These are sampled projects that
reported directly discharging at least some portion of their produced water in 2008, but may also use other
disposal methods. EPA used the Detailed Questionnaire responses along with discharge monitoring report
data to determine the volume of produced water discharged. Section 5.1.1 of the Technical Development
Document and the memoranda Supporting Information for Existing Source Analysis (DCN CBM00664)
provide additional information on identifying the direct-discharge projects, the produced water volume
generated, and the produced water volume discharged directly to surface waters. As described in Section
3, EPA analyzed the 73 sampled projects and applied survey weights to scale the results to the entire
CBM industry consisting of 148 direct-discharge projects. See Development of Final Survey Weights for
CBM Analyses (DCN CBM00653).
EPA reviewed oil and gas websites for the states listed in Section 2.1.2 to determine whether the
operating status of any of these 73 direct-discharge projects had changed since 2008. Calendar year 2010
was the most recent year with complete data available at the time EPA conducted this review. EPA
reviewed information on operators in the six basins with data (Appalachian, Black Warrior, Cahaba,
Green River, Powder River, and Raton) to determine whether: (1) the operator was still producing CBM
and (2) the operator was still producing water. EPA did not review information for operators in the
Illinois Basin because the State of Illinois provides little information on oil and gas production. Based on
this review, EPA determined that seven (13 on a weighted basis) of the 73 direct-discharge projects were
no longer producing CBM or no longer producing water as of 2010. While these seven (13 on a weighted
basis) projects are a part of the analyzed universe of existing CBM projects, EPA did not develop
wastewater management costs for them, and treated them as baseline closures in the analysis (see Section
3). The memorandum Changes to CBM Operating Status Between 2008 and 2010 (DCN CBM00715)
provides additional details on EPA's review.
2 As explained in the Technical Development Document, EPA identified 74 projects based on questionnaire responses and
excluded one from further analysis.
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As discussed in Section 3, EPA's existing-source analysis assesses the economic viability of existing
CBM projects over their lifetime, accounting for projected changes in natural gas prices and other factors
that influence project economics. EPA used 2008 as the base year for this analysis because 2008 is the
base year for the CBM survey, and is therefore the year with the most detailed information about project
economics. For each analyzed project, EPA calculated project revenue, earnings, gas production operating
costs, and water management operating costs for the produced water management method for calendar
year 2008 using data collected through the CBM survey. Table 2-1 shows the Detailed Questionnaire data
elements used to develop baseline financial project characteristics.
Table 2-1. Project Inputs Used in Existing Source Analysis
Project-Level Input
Gross revenue - All money received in
2008 for the gas sold. Project gas
production sold (Mcf) multiplied by the
project average wellhead price ($/Mcf).
Net Revenue - Gross revenue for gas sold
minus royalties (mineral rights owner share
of production revenue), severance taxes
(state share of production revenue), and ad
valorem taxes (local/county share of
production revenue).
Gas production operating and maintenance
(O&M) costs.
Produced water management O&M costs
for current method - Includes revenue
received by operator for treating produced
water from another operator and all water
transport costs.
Detailed Questionnaire Data
Elements Required
2008 gas sold
2008 average wellhead gas price
2008 royalty rate
2008 severance payment and
severance tax percentage
2008 ad valorem payment and ad
valorem tax percentage
2008 total gas production O&M
costs
2008 produced water management
system (PWMS) O&M cost (2008
O&M cost for operating the PWMS)
2008 total revenue from operating
PWMS
2008 transport O&M costs (O&M
costs for gathering and transporting
the produced water to the PWMS)
2008 trucking O&M cost (O&M for
transporting water by truck to the
PWMS)
Detailed Questionnaire Question
Question B3-60
Question B 3 -62: Requested minimum,
average, and maximum wellhead price
received for the project.
Question B3-65
Question B3-66
Question B3-67
Question B3-50
Question C2-7a
Question C2-7b
Question C2-8c
Question C2-8d(v)
As discussed in Section 3. 1.1, to assess the cost impact of wastewater management and discharge options, EPA estimated
project economics for years after 2008 to evaluate project economics over the lifetime of a project. To do that, EPA used the
following data items from the Detailed Questionnaire in addition to data items above: 2008 amount of water produced
(Question C2-3); 2008 discharged water (volume of produced water from PWMS to destination) (Question C3-2); and
percentage of O&M costs that would have been incurred during a temporary shutdown of the project (Question B3-51).
To assess project economics over the lifetime of a project, EPA also estimated typical gas and water
decline rates for each discharging basin using information from the Detailed Questionnaire. Questions
B3-98 and B3-99 of the Detailed Questionnaire requested projected gas (MMBtu/yr) and water (bbls/yr)
production data for 2009 through 2013. While EPA received limited complete responses to these
questions, EPA used this data to estimate gas and water declines over the five-year because it is the best
available data. Table 2-2 reports estimated gas and water decline rates for the eastern (IL, PA, VA, WY,
AL) and western (WY, MT, CO) states. While EPA determined and used gas and water decline rates for
each discharging basin, EPA reports here only the regional averages to protect CBI claims.
Further, because future project revenue depends on future gas prices, EPA developed gas-price
projections to use in the economic analysis. Appendix A provides additional information on these
projections. As described in Section 3, EPA applied the estimated basin-specific gas and water decline
rates to the initial 2008 gas and water production, and used projected gas prices to estimate revenue over
the lifetime of the CBM project.
Section 3 describes the existing-source analysis, including analysis methodology and findings.
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Economic Analysis of Treatment Technology Options for CBM Projects | pg 7
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Table 2-2: Estimated Average Annual Gas and Water Decline Rates
Region
Eastern U.S. basins
Western U.S. basins
Gas
7.4%
11.2%
Water
6.5%
13.1%
2.2.2 New Projects
As detailed in Section 4, EPA's new-source analysis relies on model projects and assesses the economic
viability of new projects, whether beginning at present or in future years, accounting for projected
changes in natural gas prices and other factors that influence CBM development decisions. EPA assumed
that, similar to existing CBM projects, new sources in the seven discharging basins would use surface
discharge, and that new sources in zero-discharge basins would use zero-discharge approaches to manage
produced water. EPA did not evaluate basins in which development activity began after 2012. EPA
expects that development prospects in the undeveloped basins would be less favorable than those for
basins with existing production, because of lower production potential, higher drilling costs, and/or lack
of existing infrastructure to pipe gas to centralized gas transmission hubs. To the extent that the analysis
finds challenges in new project development in the basins with existing production, EPA expects that
these challenges would be at least as great in basins without current production. EPA therefore concluded
that analysis of the basins with existing development provides an initial indication of the potential effect
of new source regulations.
For the new-source analysis, EPA developed model projects specifically for five of seven discharging
basins: Appalachian, Black Warrior, Green River, Powder River, and Raton. EPA did not have
information to develop model projects for the Illinois basin. Because the Illinois basin has limited CBM
development as of 2008, EPA expects future development in this basin will also be limited. For this
analysis, EPA assumed the Illinois basin is similar to the Appalachian Basin, based on the basins being
roughly contiguous, with similar geology, and with potentially similar cost structures and access to water
management methods. In addition, EPA did not develop a separate model project for the Cahaba Basin,
but assumed that the Cahaba Basin is similar to the Black Warrior Basin, again based on proximity,
similarity of geology, and access to similar water management methods. These assumptions are based on
best professional judgment. Section 3.3 of the Technical Development Document provides details on coal
basins with potential for CBM development.
A model project represents a typical new project(s) for the basin in terms of the profile of drilling, gas and
wastewater production, and drilling and production costs. The model projects thus provide a basis for
assessing how treatment technology requirements would affect project economics - in particular, whether
treatment technology requirements could constitute a barrier to development3 of projects that would
otherwise be economically viable. Additional details on the development of model projects, including a
discussion of the basins included in EPA's new-source analysis, are included in the memorandum
Supporting Information for New Source Model Projects and the supporting CBI spreadsheet (DCN
CBM00666 and CBM00666.A1).
EPA defined model projects using the input parameters listed in Table 2-3 primarily based on information
reported in the Detailed Questionnaire for existing projects. EPA developed one set of model projects
(primary model projects, designated APP1, BW1, GR1, PRB1, and Raton 1) using information received
In analyses of effluent guidelines pertaining to industrial facilities, EPA uses the term Barrier to Entry in assessing the
impact of new source requirements on the construction and operation of new facilities - i.e., entry of new facilities/discharge
sources into the industry. This analysis, which focuses on new project/source development, is based on the same economic
impact concept, except that the terminology Barrier to Development better reflects the considerations of a CBM operator in
evaluating whether to develop a new project opportunity.
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through the Detailed Questionnaire only. EPA developed secondary models for three basins - the
Appalachian (APP2), Black Warrior (BW2) and Powder River (PRB2) - using publicly available data
supplemented with Detailed Questionnaire data.
For the primary model projects, EPA calculated the average value for each input parameter for each basin
using information available in the Detailed Questionnaire. The input parameter values vary by basin due
to variations in basin geology and proximity to gas infrastructure. EPA compiled input parameter
averages from EIA and publicly available SEC filings to develop the secondary model project for
comparison to the parameter values obtained from the Detailed Questionnaire. If information was not
available from public data sources for the basin, EPA used the Detailed Questionnaire average to
supplement the secondary model project scenario. Table 2-3 shows the range of input parameter values
used in the new projects analysis. EPA used basin-specific values for each model project in the new-
source analysis; however, because survey respondents claimed most data collected in the Detailed
Questionnaire as CBI, EPA does not report here the basin-specific values, which were derived from data
claimed as CBI. The values presented in Table 2-3 represent the ranges across all five basins for both the
primary and secondary model project scenarios. Table 2-3 also lists the Detailed Questionnaire question
number, with field name noted parenthetically, that underlie the primary model project data items. The
Supporting Information for New Source Model Projects (DCN CBM00666) provides additional
information on the development of the model project assumptions.
EPA used the model project characteristics along with the gas and water decline rates described in Section
2.2.7 and the gas price projections described in Appendix A to analyze the potential effects of waste water
management technology costs on new sources. Section 4 describes the new-source analysis, including
analysis methodology and findings.
Table 2-3. Model Project Characteristics3
Input Parameter
Wells per project (# wells)
Initial gas production
(MCF/day/well)
Initial water production
(bbl/day/well)
Land cost ($/well)
Drilling cost ($/well)
Lease cost ($/well)
Gas production operating
cost ($/MCF)
Water production operating
cost ($/bbl of produced
water)
Fixed gas production cost
($/well)
Fixed water management
operating cost ($/well)
Range of Values
48-400
33-112
13-600
$380-$200,000
$58,000-$853,000
$7,830-$ 164,000
$0.41-$1.99
$0.00-$0.45
$978-$17,400
$0-$356
Primary Model Project - Detailed
Questionnaire Question
CBM Survey Question A- 1 (wells in
project) and Screener data
CBM Survey Question B-59 (total gas)
CBM Survey Question B-63 (total water)
CBM Survey Questions B-20 (lease
acquisition sum) and B-22 (lump sum to
secure lease)
CBM Survey Questions B-47 (total cost of
well drilling) and B-48 (total number of
wells drilled)
CBM Survey Questions B-23 (one-time
outlays for project development, before
2008) and B-49 (total outlay on project
development, 2008)
CBM Survey Questions B-50 (total O&M
costs for gas production - 2008) and B-59
(total gas)
CBM Survey Questions C2-7 (total O&M
costs for water management - 2008) and C2-
3 (total water managed)
Assumed 5 percent of total gas production
operating cost
Assumed 5 percent of total water production
operating cost
Secondary Model
Project
U.S. DOE, 2010; U.S.
DOE, 2002; Vail and
Conrad, 2003
U.S. DOE, 2010;
Petroleum Association of
WY, 2005
U.S. DOE, 2002; Ladlee,
2011; Lewis, 2004
U.S. DOE, 2002; SEC
filings
U.S. DOE, 2010
U.S. DOE, 2010; U.S.
DOE, 2002
U.S. DOE, 2002
U.S. DOE, 2010
a. Dollar values were converted to 2010 dollars using a GDP adjustment.
b. Fixed water management cost is included in fixed gas production cost reported in U.S. DOE 2010.
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Economic Analysis of Treatment Technology Options for CBM Projects | pg 9
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2.3 Wastewater Management Technologies Considered
The Clean Water Act provides for development of different levels of pollutant control for existing and
new sources, and specifies the factors to be considered in developing those levels of control.4 Therefore,
EPA analyzed the impact of potential wastewater discharge requirements on existing sources and new
sources separately.
Under both the existing- and new-source analyses, EPA looked at economic viability of a given project
without any new discharge requirements (baseline analysis) and with new discharge requirements (post
requirements). For this analysis, EPA did not identify and formally select technology options for
consideration. Rather, EPA included two technology options for consideration: one that would be the
basis for numerical discharge limitations (ion exchange, abbreviated as IX) and one that would be the
basis of zero-discharge limitations (underground injection or UI). EPA based costs for ion exchange on
the ion exchange system used by operators in the Powder River Basin, and publicly available ion
exchange cost data. As explained in the Technical Development Document, this system may not be
appropriate for TDS levels in CBM produced water in all basins evaluated. Nevertheless, EPA applied the
ion exchange costs to projects in all basins to determine whether the projects are economically capable of
implementing a technology with a similar or higher cost than ion exchange (e.g., reverse osmosis).EPA
evaluated UI because it eliminates all discharges to surface water and is currently used for CBM produced
wastewater disposal in the majority of basins. Table 2-4 presents the IX costs for TDS removal prior to
surface discharge and UI costs to eliminate the discharge of produced water. Note, unlike many industries
that EPA has analyzed for development of effluent limitation guidelines, the CBM industry is different in
that EPA expects that wastewater management technology and associated costs will be the same for both
existing and new projects. This is due to the nature of the technologies and how they are applied to a
project, regardless of whether the project is existing or new. For details on IX treatment and UI disposal
methods, see Section 4 of the Technical Development Document.
Table 2-4. Wastewater Management Costs
Water Management Method
Ion Exchange
Underground Injection
Region
All basins
Eastern U.S. basins
Western U.S. basins
Costs ($/barrel of produced water)
$0.50
$4.10
$0.54
4 See EPA's Effluent Limitations Guidelines website for additional information
(http: //water, epa. go v/scitech/wastetech/guide/index. cfm).
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3 Economic Analysis - Existing Sources
As described earlier, because the Detailed Questionnaire requested data at the project level, EPA
conducted economic analysis at the level of the project. Specifically, EPA assessed the impact of the costs
associated with potential wastewater discharge requirements on economic viability of analyzed existing
CBM projects in two steps:
> First, EPA assessed which projects may have closed due to deteriorating project economics (in
particular, because of declining gas prices) since the time of the survey, or that would potentially
close under current conditions (baseline analysis).
> Second, EPA assessed the impact of wastewater discharge requirements - based on IX and UI -
on projects that were found viable in the baseline analysis (post-requirements analysis).
The Agency conducted this analysis looking at project performance and economics over each project's
potential production life, based on estimated changes overtime in production levels, project costs, and
natural gas prices. This is called a net present value approach. Companies use net-present value analysis
to understand how much value an investment or project adds to the firm. The analysis discounts future
revenue and costs over the production life of a project back to the present. Accounting for future natural
gas prices is important in assessing project economic performance, given that natural gas prices, while
recently in a down-trend, are expected to increase over the next several decades. Projects that appear to
have unfavorable economics in the near term may look economically viable when viewed over a longer
time horizon because of expected increases in gas prices. The analysis uses the 2008 data reported in the
CBM survey as the starting point and estimates project economics over a 35-year period beginning in
2008. EPA used a 35-year production period in order to capture the potential CBM production period for
a project. Wells typically have a shorter life than 35 years, but projects may have a longer life because
they could have multiple wells that may not be drilled all at once.
To account for year-over-year changes in project economics, EPA relied on various assumptions about
changes in gas and water production levels, production costs, and natural gas prices. These assumptions
are inherently subject to uncertainty; nevertheless, EPA believes that this analysis provides important
insight into the potential impact of CBM wastewater treatment or disposal requirements.
EPA's assessment of economic impact focused on the following questions:
> Baseline analysis: Under current conditions without national limits for unconventional oil and
gas, will continued production from an existing CBM project be economically viable, given
estimated future CBM gas production, natural gas wellhead prices, and production costs?
> Post-requirements analysis: For projects assessed as economically viable in the baseline, would
they remain viable considering the change in project economics in the face of wastewater
discharge requirements - looking over the potential life of the project? Would wastewater
discharge requirements reduce the project's life (including the possibility that the project would
be immediately uneconomical), compared to the baseline? If so, by how many years, and with
what change in total CBM gas production?
EPA also conducted a static single-year analysis of economic viability assessing project economics in
2008 based only on the data reported in the CBM survey. The single-year analysis involved fewer
assumptions about future production, costs, and prices than the multiple-year, projection-based analysis,
but does not account for expected increases in natural gas prices. Accordingly, EPA judges this single-
year analysis not to be as analytically sound as the multiple-year, projection-based analysis. Nevertheless,
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Economic Analysis of Treatment Technology Options for CBM Projects | pg 11
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the findings from the single-year analysis are consistent with those generated using the multiple-year,
projection-based analysis discussed in this document.
Table 2-1 in Section 2.2.1 provides information on the CBM survey data items used in this analysis.
3.1 Baseline Closure Analysis
3.1.1 Analysis Approach and Data Inputs
This step assesses the baseline economics of existing projects and identifies those projects that are either:
> Not economically viable before consideration of the wastewater discharge requirements, when
viewed over their potential production life. These projects are immediate baseline closures; EPA
removed these projects from the subsequent post-requirements analysis.
> Economically viable before consideration of the wastewater discharge requirements, when
viewed over their potential production life. EPA retained these projects in the subsequent post-
requirements analysis.
As discussed in Section 2.2.1 EPA conducted this analysis for 148 direct-discharge projects (on a
weighted basis) across seven discharging basins - Appalachian, Black Warrior, Cahaba, Green River,
Illinois, Powder, and Raton - using 2008 as the base analysis year.5 As described earlier in this document,
because 2008 is the base year for the CBM survey, 2008 is the analysis year with the most detailed
information about project economics. EPA used pre-tax operating income (net revenue less operating
costs, as defined below) as the financial measure to assess CBM project economics.6
As described above, this analysis accounts for future gas-extraction and water-production profiles,
expected changes in wellhead natural gas prices, and resulting changes in project economics. Increasing
gas prices, along with a changing profile in gas and water production overtime, could change project
economics from that indicated by a single-year analysis, especially one based on a low point in the
market.7
EPA based this analysis on the project's pre-tax cash flow and maximization of the discounted net present
value (NPV) of cash flow, using required rates of return (hurdle rates) as described below. EPA assessed
projects with negative pre-tax operating income as immediate baseline closures, and excluded these
projects from the post-requirements analysis. EPA assessed projects with positive 2008 pre-tax operating
income as baseline passes and carried them forward for the post-requirements analysis (Section 3.2).
As discussed in Section 2.2.1, EPA found that of the 148 direct-discharge projects, 13 were no longer
operating as of 2010. EPA decided keep these 13 projects in the analyzed universe of existing projects,
because they responded to the CBM questionnaire as being in production at 2008, but to treat them as
immediate baseline closures independent of any analysis. For the remaining 135 projects, EPA first
calculated 2008 operating income, using data provided in the CBM survey and described in Section 2.2.1,
by subtracting operating costs from net revenue, which EPA estimated as follows:
5 For details on development of weights, see memorandum "Development of Final Survey Weights for CBM Analyses"
(DCN CBM00653).
6 Pre-tax refers to income taxes - i.e., taxes that are paid on the basis of the project's pre-tax income. Subsequent discussion
refers to certain wow-income taxes - severance tax and ad valorem tax - which are paid on the basis of the gross value of gas
production. This analysis does account for these non-income tax items, which are part of the calculation of pre-tax operating
income/cash flow.
7 In particular, if water production, and thus related treatment costs, decline more rapidly than CBM gas production.
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> Net revenue: To calculate net revenue, EPA first calculated gross revenue as the product of gas
sold and average wellhead gas price. EPA then calculated net revenue by subtracting 'off-the-top'
production payments - royalty payment, severance tax, and ad valorem tax - from gross revenue.
EPA used severance tax and ad valorem payments as they are reported in the CBM survey, and
calculated royalty payments as the product of (1) gas produced, (2) average wellhead gas price,
and (3) royalty rate.
> Operating costs: The Agency calculated operating costs as the sum of total gas production O&M
costs and total Produced Water Management System (PWMS) O&M costs. EPA calculated
PWMS O&M costs as the sum of costs for (1) operating the PWMS, and (2) gathering and
transporting produced water from CBM wells to the PWMS, less revenue, if any, from processing
produced water from other projects, for a fee.
EPA then developed an operating cash-flow profile, by year, for each analyzed project, based on (1)
quantity of CBM gas produced and sold by the project, (2) water produced, (3) project net revenue,
accounting for reductions from gross revenue and changes in gas wellhead prices, and (4) operating costs.
EPA calculated the NPV of future cash flows over all potential durations of the project. For example, if
the project has the technical potential to continue production for 20 years beyond 2008, EPA calculated
the NPV for each duration from the first year (2009) through 20 years (2028). EPA then identified the
year in which NPV is maximized, and determined whether the maximum NPV is positive. If the project
would not achieve a positive NPV over any of these durations, EPA assumed that the project would shut
down in the first analysis year, i.e., 2008, and assessed the project as an immediate baseline closure* If
the project's maximum NPV is positive, EPA assessed the project as a baseline pass, and recorded the
year in which maximum NPV is achieved (assumed to be the last year of production) and the quantity of
CBM gas produced through that year. EPA later used these values to measure the impact of wastewater
discharge requirements in terms of lost production years and gas produced. EPA carried these projects
forward to the post-requirements analysis (Section 3.2).
EPA conducted this analysis as follows:
> Defining analysis timeframe: Because the CBM survey provided only limited data on projects'
remaining production life,9 EPA analyzed potential gas and water production over a uniform 35-
year time period beginning in 2008, regardless of the age of the project.
> Projecting gas production (Mcf): To estimate gas produced in each year following 2008, EPA
developed and used gas-production decline rates by basin. Table 2-2 shows the eastern and
western U.S. average gas and water decline data. As described in Section 2.2.1, EPA provides
This analysis does not account for the previous outlays incurred by a project - e.g., project acquisition costs, development
costs - and, in particular, doesn't ask whether the project is meeting the target rate of return on which the developer may
have based the decision to undertake the CBM gas project. For this analysis, the Agency treated those costs as 'sunk' and
examined only whether the project appears economically attractive on a current and forward-looking basis. Previous outlays
could influence the forward-looking analysis because of the tax treatment of those outlays (e.g., depletion and depreciation);
however, to capture these effects would require performing the analysis on an after-tax basis. EPA assessed an after-tax
analysis as being not possible in the short-term, as this analysis would require additional data that would be very difficult or
even impossible to obtain, and/or assumptions that would be very difficult to develop and defend. Moreover, EPA was not
confident that the analysis would yield substantially different results if performed on an after-tax basis.
The CBM survey asked respondents to report remaining production life of a given project at 2008; however, of the 66
projects, only 19 projects (29 percent) provided this information.
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only the regional averages to protect the CBI claims, although average decline rates were
calculated for each of the five basins analyzed in the model.10
> Projecting gas sales (Mcf): To estimate the amount of gas sold for years after 2008, EPA
assumed that projects will sell the same percentage of total gas produced,11 as indicated in the
CBM survey for 2008 (calculated as gas sold/gas produced), and multiplied this percentage by
total estimated gas production for each year.
> Projecting amount of produced water (bbl): Similar to the gas production analysis, to estimate the
amount of produced water after 2008, EPA developed and used an average water production
decline rate by basin (see Section 2.2.1).
> Projecting amount of produced water discharged from PWMS to surface water (bbl): To estimate
the amount of produced water that is discharged from PWMS to surface water (discharged water)
after 2008, EPA assumed that projects will discharge the same percentage of total water produced
based as reported in the CBM survey for 2008 (calculated as water discharged/water
produced).12'13 EPA multiplied this percentage by total estimated water production for each
year.14
> Projecting natural gas wellhead prices: To estimate gas wellhead prices after 2008, EPA applied
year-over-year percentage changes in wellhead prices (see Table A. 2-1 in Appendix A) to the
average gas wellhead price reported in the CBM survey for 2008 (see discussion in Section 2.1.1
and Table 2-1). EPA developed year-over-year percentage changes from gas-price projections in
the Annual Energy Outlook (AEO) published by EIA. To reflect the uncertainty in price
projections, EPA considered three price growth cases in this analysis: reference case, high price
growth case, and low price growth case (for details see Appendix A).
> Projecting operating income: EPA calculated operating income for each year after 2008 by
subtracting operating costs from net revenue estimated as follows:
• Projecting net revenue: EPA estimated net revenue for each year following 2008 as gross
revenue less 'off the top' production payments - royalty payments, severance tax, and ad
valorem tax - estimated for a given year. The Agency estimated these components on an
annual basis as follows:
D Gross revenue: EPA calculated gross revenue as the product of (1) gas sold and (2)
wellhead gas price estimated for each year following 2008.
EPA also tried to estimate project-specific decline rates using information on remaining technically recoverable reserves or,
if not available, remaining proved reserves, and the project life for technically recoverable reserves, all from the CBM
survey. However, information on project life was only available for 19 projects (29 percent of all projects). Further, EPA
observed a possible inconsistency between the units in which technically recoverable reserves and remaining proved
reserves were reported for some projects, and thus decided against using this approach.
Some gas may be used onsite.
Before using the volume of produced water discharged from PWMS to surface water reported in the CBM survey in these
calculations, EPA adjusted the reported values to account for any transfers between projects. For details see memorandum
"Supporting Information for Existing Source Analysis" (DCN CBM00664).
EPA recognizes the uncertainty in this assumption, but lacks information to support a different assumption.
The total water produced may exceed the water discharged to surface water because projects may use multiple disposal
methods (e.g., surface discharge and livestock watering). The wastewater-treatment technology would only affect the
portion of water discharged to surface waters.
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D Royalty payment: EPA calculated royalty payment as the product of (1) the royalty rate
reported in the CBM survey,15 (2) estimated year-specific wellhead gas price, and (3)
estimated year-specific gas produced.
D Severance tax: For the 38 unweighted projects (58 percent of the analyzed 66 projects)
for which the CBM survey reports severance tax rate, EPA used the reported rate. For the
remaining 28 unweighted projects, the Agency estimated the severance tax rate by
dividing severance tax payment by gross revenue, both of which are reported in the CBM
survey for 2008. The Agency calculated severance tax payments for years after 2008 as a
product of (1) the reported/estimated severance tax rate and (2) gross revenue.
D Ad valorem tax: For the 38 unweighted projects (58 percent) for which the CBM survey
reports ad valorem tax rate, EPA used the reported rate. For the remaining 28 unweighted
projects, the Agency calculated ad valorem tax rate by dividing the ad valorem tax
payment by revenue, both of which are reported in the CBM survey for 2008. The
Agency calculated ad valorem payment for years after 2008 as the product of (1)
reported/estimated ad valorem tax rate and (2) gross revenue.
Projecting operating costs: EPA estimated operating costs on an annual basis as follows:16
D Produced Water Management System (PWMS) O&M costs: For this analysis, EPA
assumed that PWMS O&M costs include no fixed component; consequently, all PWMS
O&M costs are assumed to vary linearly with the amount of produced water.17 To
estimate total PWMS O&M costs after 2008, EPA assumed that unit O&M cost per bbl is
constant and calculated this unit cost using 2008 values. The Agency multiplied this unit
cost by the amount of produced water.
D Gas production O&M: Gas production O&M costs consist of fixed and variable O&M
costs. Fixed O&M costs do not vary with the amount of gas produced. To calculate the
fixed cost value, the Agency multiplied (1) the fixed O&M cost percentage18 by (2) 2008
total gas production O&M costs.19 EPA assumed that fixed O&M cost would remain
constant in subsequent years. EPA subtracted this fixed cost value from reported total gas
production O&M to calculate the variable O&M cost in 2008. To estimate variable gas
production O&M costs in subsequent years, EPA assumed that unit variable O&M cost
per Mcf is constant overtime; EPA calculated this unit cost by dividing estimated 2008
variable gas production O&M costs by the amount of gas produced in 2008. To estimate
variable gas production O&M costs for years, the Agency multiplied this unit cost by the
estimated gas production quantity.
15 EPA assumed the royalty rate to be constant over the project live, which is usually true.
16 EPA assumed no change, on an inflation-adjusted, constant dollar basis, in operating cost values over time. While it is
possible that gas production and PWMS management costs will increase, it is equally possible that improvement in gas-
extraction and water-management technology will lower those costs, again after adjusting for general inflation. Because
EPA had no basis for estimating the direction or magnitude of these changes, the Agency assumed that these costs would
remain constant on an inflation-adjusted basis.
17 To the extent that PWMS O&M costs include a fixed component, the PWMS O&M costs estimated after 2008 would be
underestimated.
18 The share of O&M costs that would continue during a temporary shutdown of the project, as reported in the CBM survey.
19 For one project, percentage of 2008 fixed O&M costs is not reported; consequently, for this project EPA used average
percentage estimated for the basin where this project is located, based on percentages reported for other projects in that
basin.
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> Project profitability: For calculating a project's NPV, EPA tallied project cash flows on a year-
by-year basis as described above, on an as-incurred basis, with production continuing for as long
as 35 years. EPA assumed that project developers produce gas until the year of maximum NPV
and that this is the last year of gas production.20 The Agency assumed that a project will shut
down immediately if NPV is negative over all possible production life periods. To calculate NPV,
EPA used 17-percent and 7-percent as target rates of return (or hurdle rates).21 Target rates of
return generally vary by project stage and are generally higher during project development. Risks
such as resource and technical risk, or price and cost risks are greater, before the operator knows
production per well, how many wells will be drilled, production costs, and resource/water mix,
etc. However, as projects progress through development and production, target rates typically
decline to reflect greater certainty of resource recovery and project economics. Because (1) the
analyzed CBM projects are at varying stages of development and (2) the survey responses did not
provide information on development stage, EPA did not assign stage-specific rates for analyzing
individual projects. Instead, EPA used a range of rates - 17 percent and 7 percent - to bracket
project economics, on both a baseline and post-requirements basis. The 17-percent rate is the
midpoint of a range (12-22 percent) that EPA presented in the CBM survey questionnaire as
possible rates of return sought by CBM project developers. Some survey respondents agreed that
this range reasonably reflects rates of return sought by CBM project developers. Also, EPA
received communications from developers suggesting that 17 percent is a reasonable estimate of
the inflation-adjusted rate of return that developers seek to achieve in committing financial
resources to undertake CBM projects. The 7-percent rate reflects the long-term opportunity cost
of capital to U.S. industry, in real or constant dollar terms, as documented by the Office of
Management and Budget in Circular A-4.22 To the extent that the 17-percent target rate of return
is more indicative of earlier stages of project development, it provides a higher range value for
required return on investment. The 7-percent rate would be more indicative of the lower resource
and economic uncertainty during a project's later production years, and provides a lower range
value for required return on investment for use in the project NPV calculations.
3.1.2 Baseline Analysis Results
From the analysis outlined above, EPA found that 23 of the 135 analyzed projects would close
immediately, (i.e., in the first analysis year, 2008) in the baseline regardless of the gas-price case or
required rate of return used.23 Together with the 13 projects that were non-operational as of 2010
20 Generally, at this point, the project will have achieved its maximum NPV and subsequent production will generate negative
cash flows and declining NPV. However, future gas price increases, coupled with changes in water production relative to
changes in gas production, following the maximum-NPV year, may cause operating income to increase and become positive
in future years. It is possible that if these projects continued to produce natural gas beyond the last year of the analysis
period, their NPV would be maximized later, in a year after the end of the analysis period, in which case these projects
would likely "operate" during the entire analysis period. It is also possible that prices will rise more slowly than projected, in
which case, projects would shut down sooner than the maximum-NPV year estimated here. The estimates here reflect EPA's
best information.
21 Hurdle rate is the minimum rate of return on a project or investment required by an operator/investor.
22 The difference between 17-percent and 7-percent would also reflect differences in the risk characteristics specific to the
CBM project (geotechnical and economic/financial risks) as compared to the risks associated with overall economic activity
in the U.S. economy. The difference could also reflect the business characteristics of the enterprises engaged in CBM gas
development - for example, if the enterprises tend to be smaller and of lower investment grade than the profile of businesses
in the general economy.
23 As stated above, EPA also performed this analysis for 2008 only, using data reported in the CBM survey and found the same
23 projects as baseline closures. The finding of no difference in immediate closure results and potential project life based
only on the single year of 2008 may be interpreted as follows: When a project is not viable in the first analysis year (i.e.,
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according to State oil and gas websites, baseline closure projects represent 25 percent of total weighted
project counts. For the remaining 112 projects - i.e., baseline pass projects - EPA recorded the year in
which maximum NPV is achieved (assumed to be the last year of production) and the quantity of CBM
produced through that year. EPA carried these projects forward to the post-requirements analysis (Section
3.2).
Further, looking beyond the baseline year, from the analysis outlined above, EPA also found that an
additional 43 percent of projects would remain operating after 2008 but are likely to have shut down by
2012, based on the decline in natural gas prices and other estimated project changes since 2008. However,
as stated above, because EPA assessed these projects as baseline passes relative to the 2008 analysis year,
EPA kept these projects in the post-requirements analysis. EPA kept these projects in the analysis to test
whether the CBM wastewater discharge requirements would cause the projects to close earlier than the
year estimated in the baseline analysis and thus lead to losses in natural gas production.
3.2 Post-Requirements Analysis
3.2.1 Analysis Approach and Data Inputs
To analyze the impact of CBM wastewater discharge requirements on projects that are economically
viable in the baseline (2008), EPA conducted the post-requirements analysis for the remaining 112
projects using the same methodology as described in Section 3.1.
For this analysis, EPA adjusted the profile of future cash flows to account for year-over-year estimates of
IX and UI costs. EPA then recalculated the NPV of project cash flows over the potential project durations
to determine the maximum NPV, and whether the maximum NPV value is positive. If the project would
not achieve a positive NPV over any of these durations, EPA assumed this project would close
immediately in 2008, the first year analyzed, and recorded this project as an immediate post-requirements
closure. For projects with a maximum NPV that is positive (post-requirements pass), EPA recorded the
maximum-NPV year, and the total production of CBM gas through that year. Specifically, for each of the
post-requirements pass projects, the Agency compared the maximum-NPV year in the post-requirements
analysis to the maximum-NPV year in the baseline analysis and assessed whether a given project would
stop gas production earlier. An earlier shut-down of a project as the result of wastewater discharge
requirements would result in a smaller amount of CBM gas produced.
EPA calculated IX treatment and UI disposal costs for years after 2008 based on the amount of
discharged water estimated for those years. The Agency then subtracted the resulting treatment costs from
baseline operating income.
As key output metrics for this analysis, EPA calculated (1) the change in total CBM gas production
between baseline and post-requirements cases, (2) the change in the number of project-years, and (3)
average number of production years lost per affected project.24'25
2008), the financial benefit of higher gas prices later in the analysis period coupled with declining costs for water
management (relative to gas production) does not improve project economics sufficiently to support future production. The
long-term viability of these projects is further undermined by large drops in gas prices during the earlier years of the analysis
period (55 percent in 2009 and 38 percent in 2012). In general, water production declines more rapidly than gas production,
leading to lower water management costs per unit of gas produced over the life of the project. For year-over-year changes in
gas prices during the analysis period, see Appendix A.
24 Project-years represent the sum of lost years of gas production across all projects.
25 As is the case in the pre-requirements analysis, some projects return to positive operating income in years after the
maximum NPV year, and operating income remains positive through the analysis period. However, even though NPV
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3.2.2 Post-Requirements Analysis Results
Immediate Project Closures
EPA found the same number of projects to be immediate post-requirements closures, regardless of the
gas-price case or required rate of return used in the analysis. This finding means that when projects are so
substantially affected by the addition of CBM wastewater discharge requirements that they might shut
down immediately, that changes in gas prices or the required rate of return, within the ranges used in this
analysis, are not able to offset the substantial adverse impact of discharge requirements on project
economics. Under the IX treatment requirement, 27 projects (24 percent) shut down. As reported in Table
3-1, EPA estimates that immediate termination of these projects would result in relatively small losses of
project-years (average of two to three years per project) and natural gas production (less than 1 percent of
baseline). The burden from additional treatment technology costs causes only a small reduction in project
life or gas production for those projects that are found to terminate immediately. Given the relatively
small losses in production years and gas quantity, this means that these projects would have shut down
shortly after 2008 regardless of treatment technology costs - based on their baseline financial situation.
Generally, the impacts of requirements based on UI disposal, which is more expensive than requirements
based on IX treatment, are greater than those estimated for IX treatment. Thirty projects (27 percent) shut
down immediately. Similar to the finding for the IX treatment analysis, EPA estimates that immediate
termination of these projects would result in relatively small losses of project-years (average of two to
three years per project), and natural gas (less than 1 percent of baseline). Again, these findings mean that
these projects would shut down soon after 2008, regardless of wastewater treatment or disposal costs.
In the same way as found in the analysis of immediate project-closures in the baseline (Section 3.1.2), the
findings for immediate closures are the same for both the multiple year analysis approach, presented here,
and the alternative single-year analysis, which EPA also performed. Again, this means that when a project
is already not economically viable in the first analysis year, the financial benefit from higher gas prices
later in the analysis period and improved project economics due to lower water production management
costs are not sufficient to support future production.
Production Years Lost at Remaining Projects
With IX treatment, EPA estimates that some of the 85 post-requirements pass projects would stop gas
production earlier than they would have absent the IX treatment (see Table 3-1). The gas losses due to
shorter project life are larger than those estimated for the immediate project closures. At the 17-percent
required rate of return, EPA estimates that 29 to 37 projects would shut down earlier than they would
have in the baseline, depending on the gas-price case; these projects represent 26 to 33 percent of all
baseline pass projects. On average, EPA estimates that each of these projects would lose 10 to 11 years of
gas production relative to the baseline estimates of production life, resulting in a total gas loss of between
205 and 376 million Mcf (between 4 percent and 8 percent of the total baseline gas quantity). The losses
in project-years and production are greatest under the low price growth case, and smallest under the high
price growth case, with the estimates for the reference case falling in between. The estimated losses
increase in moving from the higher to lower price cases because the lower price cases leave less operating
margin for absorbing treatment technology costs, and thus greater potential for adverse impact.
With UI disposal, some of the remaining 82 projects that EPA did not assess as immediate post-
requirements closures also stop production earlier due to disposal requirements. The total gas losses from
increases in those years, it never exceeds the maximum NPV achieved in the earlier year. These projects might reach a
higher NPV, and continue production, if production were possible and analyzed beyond the last year of the analysis period.
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shorter production lives of these projects are larger than the losses estimated for the IX treatment. At the
17-percent required rate of return, EPA estimates that between 44 and 49 projects would shut down
earlier than in the baseline, depending on the gas-price case; these projects represent 39 to 44 percent of
all baseline pass projects. Each of these projects would lose, on average, between 15 and 17 years of gas
production, resulting in a total gas loss of between 1,691 and 1,853 million Mcf (between 34 percent and
38 percent of baseline gas quantity). As with the IX treatment technology, losses in project-years and gas
production increase in moving from the high price growth, to reference, and low price growth cases.
For both the IX and UI, the impact findings vary less between the 7-percent and 17-percent required rate
of return cases than across the gas-price cases. Where the impact results differ more than minimally, the
losses are generally higher under the 17-percent rate than under the 7-percent rate. This finding indicates
that IX treatment or UI disposal is likely to have a similar adverse effect on existing CBM projects
regardless of their development stage and associated required rate of return on investment.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 19
-------
Table 3-1: Production-Years and Natural Gas Production Foregone due to Wastewater Discharge Requirements in Immediate Project
Closures and in Projects that Remain in Productiona'b'°'d
Analysis Case
and Impact
Metric
Technology Basis: Ion Exchange (IX)
Using 17 Percent Hurdle Rate
Unweighted
Value
%of
Total
Weighted
1 % of
Value | Total
Using 7 Percent Hurdle Rate
Unweighted
Value
%of
Total
Weighted
1 % of
Value | Total
Technology Basis: Underground Injection (UI)
Using 17 Percent Hurdle Rate
Unweighted
Value
%of
Total
Weighted
1 % of
Value | Total
Using 7 Percent Hurdle Rate
Unweighted
Value
%of
Total
Weighted
1 % of
Value | Total
High Price Growth Case
Due to Immediate Project Closures"
Gas Quantity
Project- Years
# of Projects
Years/Project
2.6
7
4
2
0.1%
0.6%
6.8%
8.7%
8.8
89
27
3
Due to Production Years Lost at Remaining I
Gas Quantity
Project- Years
# of Projects
Years/Project
155.0
185
18
10
3.4%
15.6%
30.5%
51.2%
204.8
298
29
10
0.2%
5.4%
24.3%
22.3%
2.6
7
4
2
0.1%
0.6%
6.8%
8.7%
8.8
89
27
3
0.2%
5.4%
24.3%
22.3%
18.7
11
6
2
0.4%
0.9%
10.2%
9.1%
25.5
94
30
3
0.5%
5.7%
26.9%
21.2%
18.7
11
6
2
0.4%
0.9%
10.2%
9.1%
25.5
94
30
3
0.5%
5.7%
26.9%
21.2%
'rejects
4.2%
18.1%
26.2%
69.1%
84.4
127
18
7
1.9%
10.7%
30.5%
35.2%
111.1
184
29
6
2.3%
11.2%
26.2%
42.7%
1,565.7
560
31
18
34.5%
47.3%
52.5%
90.0%
1,691.2
730
44
17
34.4%
44.3%
39.3%
112.9%
1,454.6
462
30
15
32.1%
39.0%
50.8%
76.7%
1,539.5
595
43
14
31.3%
3672%
3874%
942%
Reference Case
Due to Immediate Project Closures"
Gas Quantity
Project- Years
# of Projects
Years/Project
2.6
7
4
2
0.1%
0.6%
6.8%
8.9%
8.8
89
27
3
0.2%
5".5%
24.3%
22.8%
2.6
7
4
2
0.1%
0.6%
6.8%
8.9%
8.8
89
27
3
0.2%
5.5%
24.3%
22.8%
18.7
11
6
2
0.4%
0.9%
10.2%
9.3%
25.5
94
30
3
0.5%
5.9%
26.9%
21.7%
18.7
11
6
2
0.4%
0.9%
10.2%
9.3%
25.5
94
30
3
0.5%
579%
2679%
21.7%
Due to Production Years Lost at Remaining Projects
Gas Quantity
Project- Years
# of Projects
Years/Project
248.9
251
22
11
5.5%
21.6%
37.3%
57.8%
338.5
398
37
11
6.9%
24.7%
32.9%
75.0%
151.5
166
21
8
3.4%
14.3%
35.6%
40.1%
218.1
291
36
8
4.4%
18.1%
32.0%
56.4%
1,717.1
586
33
18
38.0%
50.3%
55.9%
90.0%
1,841.8
753
49
15
37.6%
46.8%
44.2%
105.8%
1,566.4
499
31
16
34.6%
42.9%
52.5%
81.6%
1,668.1
644
47
14
34.0%
40.0%
42.4%
94.3%
Low Price Growth Case
Due to Immediate Project Closures"
Gas Quantity
Project- Years
# of Projects
Years/Project
2.6
7
4
2
0.1%
0.6%
6.8%
9.1%
8.8
89
27
3
0.2%
5".7%
24.3%
23.6%
2.6
7
4
2
0.1%
0.6%
6.8%
9".'!%
8.8
89
27
3
0.2%
5.7%
24.3%
23.6%
18.7
11
6
2
0.4%
1.0%
10.2%
9.5%
25.5
94
30
3
0.5%
6.0%
26.9%
22.4%
18.7
11
6
2
0.4%
1.0%
10.2%
9.5%
25.5
94
30
3
0.5%
6"0%
2679%
22.4%
Due to Production Years Lost at Remaining Projects
Gas Quantity
Project- Years
# of Projects
Years/Project
287.3
272
22
12
6.4%
23.9%
37.3%
64.2%
375.8
413
37
11
7.7%
26.4%
32.9%
80.3%
275.5
241
21
11
6.1%
2L2%
3576%
59.6%
364.0
382
36
11
7.5%
24.5%
32.0%
76.3%
1,729.1
581
33
18
38.4%
51.1%
55.9%
91.4%
1,852.7
742
49
15
37.9%
47.5%
44.2%
107.5%f
1,729.1
581
33
18
38.4%
51.1%
55.9%
91.4%
1,852.7
742
49
15
37.9%
473"%
442%
107.5%f
Augusts, 2013
Economic Analysis of Treatment Technology Options forCBM Projects | pg 20
-------
a. % of Total values are calculated relative to baseline.
3. Gas quantity is measured in million Mcf.
c. Project-years is the sum of lost gas-production years across all projects.
d. Years/project is average number of gas-production years lost per project.
3. Slight differences in percent-change values result from differences in the baseline values against which the percent-change values are calculated. The differences in baseline values result from the change
in project economics, depending on the gas-price case and the required rate of return used, and consequently, in the length of project life and the amount of gas produced during this life.
f. Results from weighting of individual projects.
Source: U.S. EPA Analysis, 2013
Augusts, 2013 Economic Analysis of Treatment Technology Options forCBM Projects | pg 21
-------
3.3 Uncertainties and Limitations
This analysis involves several uncertainties and limitations, each of which can lead to over- or under-
estimation of impacts. Key uncertainties and limitations for the economic analysis26 include:
> The analysis does not account for the previous outlays incurred for a project - e.g., project
acquisition costs, development costs - and does not capture the subsequent tax treatment of those
outlays (e.g., depletion and depreciation). Omission of these tax considerations may over- or
under-state the propensity for earlier project termination.
> The analysis uses generic basin-level gas and water decline rates, which may differ from project-
specific decline rates. This divergence may over- or under-state the impact of wastewater
discharge requirements.
> The actual gas prices received by each project may differ from those estimated for and used in
this analysis, which may over- or under-state the impact of wastewater discharge requirements.
> This analysis does not account for the possibility of additional wells being drilled at existing
projects, which may over- or under-state the impact of wastewater discharge requirements. It is
possible that additional wells would have improved project economics, depending on the
productivity of those wells.
> This analysis does not include CBM projects that may have begun gas production since the time
of the CBM survey, which may lead to underestimation of the baseline universe of existing
projects.
> The individual project analyses do not begin from estimates of remaining technically recoverable
gas reserves or remaining proved reserves, but use information on production at 2008 (as reported
in survey responses) together with basin-specific decline rates, to estimate total potential gas
production and the profile of production over time, from a project. These assumptions, which
very likely differ from the actual recovery potential and production profile of the actual projects,
may over- or under-state the impact of wastewater discharge requirements.
> The estimates of project costs and treatment technology costs assume no change in the underlying
unit cost values on an inflation-adjusted basis - that is, costs are assumed to change in line with
general inflation and past experience has shown that costs for technologies such as IX come down
over time as operators become more familiar with its operation and performance and application
of the technology increases. If costs change in the future in a way that differs from general
inflation - whether at a higher or lower rate - then the analysis of project economics may over- or
under-state the impact of wastewater discharge requirements.
26 See the Technical Development Document for the Coalbed Methane Extraction Industry (DCN CBM00669) for additional
details and assumptions regarding ion exchange and underground injection.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 22
-------
4 Economic Analysis - New Sources
As discussed in Section 2.2.2, the Detailed Questionnaire is the main source of data EPA used to develop
model projects for the new source analysis. Because the Detailed Questionnaire obtained data at the
project level, EPA conducted the new-source analysis at the level of the project. For the new-source
analysis, EPA considered a project to be a group of wells that are planned, developed, and operated as a
single economic production unit. The group of wells could be developed on a single lease or group of
leases. To support its determinations concerning the development of ELGs for the new-source segment of
CBM industry, EPA analyzed the effect of wastewater management technology options on the economics
of new CBM projects. For this analysis, EPA relied on model projects that reflect resource and economic
characteristics in the principal CBM production basins throughout the United States. Similar to the
existing-source analysis (Section 3), EPA considered the IX treatment option and the UI disposal option
(see Table 2-4 for unit costs).
EPA's analysis of economic impact first assessed the economic viability of new projects independent of
discharge requirements (baseline analysis). Because of the substantial decline in natural gas prices
observed during the past few years, most of the model projects considered in this analysis would not be
economically attractive for development in 2012, or even in the near future. However, with natural gas
prices expected to increase in the future, production from these CBM basins will generally return to being
economically attractive at some time in the future.27 Nevertheless, the analysis indicates that, in some
basins, a considerable number of years will need to pass (with associated increase in natural gas prices)
before new projects would be viable. EPA then assessed the effect of wastewater discharge costs on the
economics of CBM gas production (post-requirements analysis). This analysis looked at the potential for
treatment technology and disposal costs to delay further the year in which it would be economical for
CBM project developers to undertake a model project, and to affect the quantity of CBM gas that would
be economically recovered from a given project. Delay and reduction in resource recovery provide
important measures of the cost to society from treatment technology or disposal requirements. In addition,
as described above, these adverse impacts - in particular, additional delay in the timing of economically
viable production - constitute a potential Barrier to Development of new projects, which EPA considered
in assessing whether to implement additional discharge requirements for new CBM projects.
Specifically, this analysis asked the following questions for the pre-treatment (baseline) and post-
treatment, i.e., accounting for wastewater treatment and disposal costs, (post-requirements) cases:
> Baseline analysis:
• Independent of potential wastewater discharge requirements, what initial price level is needed
to achieve economically viable development of CBM projects?
• In what year would that initial price level occur? What quantity of CBM gas would be
economically recovered?
> Post-requirements analysis:
• What initial price level is needed to achieve economically attractive development of CBM
projects after imposition of ELG requirements?
27 Given the uncertainty in future natural gas prices, EPA used alternative projections of wellhead gas prices to assess how
CBM project economics would change over time (see Appendix A).
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 23
-------
• By how many years would economically attractive development be delayed by the imposition
of ELG requirements? What is the change in production quantity of CBM gas?
Section 4.1 reviews methodology, data sources, and assumptions for this analysis; Section 4.2 reviews the
findings from the analysis.
4.1 Methodology, Data Sources, and Assumptions
4.1.1 Summary of the Project Economic Analysis
EPA developed a general model for analyzing production economics for each of the model projects
discussed in Section 2.2.2. This model accounts for development costs, gas production and revenue,
wastewater production, and costs of producing gas and wastewater treatment. EPA developed and
implemented this framework independent of the specific regulatory program considerations of this
analysis. EPA then used this framework, along with projections of natural gas prices and the cost of
treatment technology options, to examine potential effects of wastewater discharge requirements on
project delay and total gas production.
The elements of the economic analysis for new projects are similar to those described above for existing
projects, with the key distinction that the analysis for new projects starts at the beginning of a project,
whereas the analysis for existing projects starts with the project's production levels, revenue and costs at
the time of the CBM survey. Important elements for the new project analysis are as follows:
> EPA based the project economic analysis on pre-tax cash flow and the discounted NPV of that
cash flow, using required rates of return as described below.28 Being strictly a pre-tax cash
analysis, the analysis does not account for income tax payments or for related tax considerations,
such as depreciation and depletion. For example, the project economic analysis accounts for
initial development costs and outlays for development wells only in the years that they are
incurred, and these outlays do not generate any depreciation and/or depletion tax effects that
would affect after-tax cash flow in subsequent years. While an after-tax analysis might provide a
more precise understanding of project cash flows and related production decisions, EPA
determined that the findings from the pre-tax analytic approach would not differ materially from
the findings from the after-tax analysis. Moreover, an after-tax analysis would require additional
assumptions about tax rates and the applicability of certain tax provisions, based on the size of the
producing entity.
> In general, projects generate negative cash flow in their early years, while development wells are
still being drilled, and the cash outlay for these wells exceeds the revenue received for gas
production. Later, projects generate positive cash flow - if production revenue, net of certain
production payments, exceeds production costs - following completion of these substantial cash
outlays during the development period. Once a project's cash flow has become positive,
developers are assumed to produce gas until the year in which the project's NPV is maximized.
This year generally coincides with the last year - after the initial development period - in which a
project's operating cash flow is positive. At this point, the project will have achieved its
maximum NPV and subsequent production will generate negative cash flow and declining NPV.
28 Pre-tax refers to income taxes - i.e., taxes that are paid on the basis of the project's pre-tax income. Subsequent discussion
refers to certain wow-income taxes - severance tax and ad valorem tax - which are paid on the basis of the gross value of gas
production. This analysis does account for these non-income tax items, which are part of the calculation of pre-tax operating
income/cash flow.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 24
-------
> Operating cash flow during the production years is defined as gross revenue, less payments on the
gross quantity or value of production, and less production costs.
• A project's gross revenue in any year is calculated simply as the quantity of gas production
times the wellhead price for gas in that year.
• Gas production incurs certain payments on the gross quantity or value of production -
royalty, severance tax, and ad valorem tax - which are charged against the gross wellhead
value of gas production. These payments are subtracted from the gross value of gas
production to yield a project's net revenue in any year. Based on information from the CBM
survey, EPA assumed a uniform production payment percentage of 28 percent. This includes
severance tax of 6 percent, royalty of 16 percent, and ad valorem tax of 6 percent. EPA
calculated these payments based on the gross value of production in a given year.
• Production costs include both the costs of producing the CBM gas and managing the
produced water. This analysis calculates production costs based on fixed unit cost values so
that production costs vary only with the quantities of gas and water production in a given
year. In addition, for years in which development wells are being drilled, the cost of these
development wells is subtracted away from the project's operating cash flow in that year.
> For calculating a project's NPV, EPA tallied project cash flows on a year-by-year basis. Initial
project development costs are recorded in the first year29; operating cash flow, and drilling costs
are recorded beginning in the second year of the project analysis, and continue for as long as
drilling is underway. Production may continue for as long as 35 years. The project analysis finds
the year in which a project reaches its maximum NPV, accounting for the project operating and
economic information outlined in the preceding discussion.30 The analysis assumes this year to be
the last production year for a given project.
> EPA calculated a project's NPV using the same require rates of return - 17 percent and 7
percent - as used in the analysis of existing CBM projects. See the project profitability discussion
in Section 3.1.1, for information on EPA's choice of hurdle rates for use in this analysis.
4.1.2 Price Projections
The purpose of this analysis is to understand the baseline economics of CBM gas production across the
various CBM basins, and to see how those economics would change if projects incurred the costs for
wastewater treatment technology, as outlined above. The potential for adverse impact due to wastewater
discharge requirements constitutes a Barrier to Development, which EPA used as a key consideration in
assessing whether to develop discharge regulations applicable to new CBM sources.
A key consideration in this analysis is the expected prices for natural gas produced in various locations
across the United States. As noted above, in recent years, natural gas prices have been considerably below
the peak in 2008. As a result, some of the model projects would not be economically viable for
development at current prices. However, with natural gas prices expected to increase, in both nominal and
29 In reality, initial development outlays may occur over several years as a developer assembles development rights and
acquires permits and capital for undertaking the project. For this analysis, EPA recorded these outlays as though they all
occur in a single year.
30 Distinct from the existing source analysis, the new sources analysis recognizes the possibility that a project may experience
years of negative cash flow that are followed by years with positive cash flow, in finding the year in which NPV is
maximized.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 25
-------
constant dollar terms, in future years, these projects will likely offer economically viable development
opportunities at some time in the future. Accordingly, this analysis accounts for the expected increase in
natural gas prices over time, and examines (1) when the various model projects would become
economical to develop and (2) the quantity of CBM gas that each of the model projects would produce.
To support this analysis, EPA developed and used natural gas price projections, based on analyses from
AEO publications and natural gas price data. Specifically, EPA developed basin-specific price projections
based on three different DOE projection cases, to account for the inherent uncertainty in projecting
natural gas prices.31 EPA then used these wellhead price series to calculate the compound annual growth
rate (CAGR) over the 28-year period from 2013 to 2040 for each of the price cases. EPA began these
projections from 2013 to capture the expected change in natural gas prices beginning from the present and
continuing into future years, thus reflecting the price changes that CBM project developers would
experience and/or anticipate in assessing new project opportunities. Table 4-1 reports the starting and end
values and resulting annual growth rates. These values define the price paths used in the analysis
described below.
Table 4-1: Compound Annual Growth Rates for Natural Gas Wellhead Prices , 2013- 2040
Gas-Price Case
Low Economic
Growth
Reference
High Economic
Growth
2013 Natural Gas Price ($2010)
$3.07
$3.17
$3.21
2040 Natural Gas Price ($2010)
$6.87
$7.52
$8.01
CAGR
3.0%
3.3%
3.4%
1 . Appalachian Basin wellhead prices are used as an example for this calculation.
2. The CAGR does not vary by basin.
Source: U.S. EPA Analysis, 2013
4.1.3 Estimating the Potential for Delay and Reduced CBM Gas Production Due to
Treatment Technology Costs
This analysis finds the initial wellhead price that, when coupled with a given price path, would cause a
given model project to be economically viable to undertake. EPA then found the calendar year in which
this price would occur, based on the specific EIA-based price projection underlying the analysis. EPA
also identified the calendar year in which a model project would cease production, given the price path
and other project economic specifications. With information on the beginning and end of a project, EPA
tallied the total quantity of CBM gas that would be economically produced from the project. EPA
performed this analysis for the baseline case - i.e., with no additional cost from discharge requirements -
and then for cases including the additional cost from discharge requirements.
The general project analysis framework, outlined at Section 4.1.1, above, simulates the economics of
CBM gas production over time, and the developer's decision of when to terminate production given the
project's operating cash flow profile. The analysis assumes that developers make production decisions
according to the principle of maximizing the NPV of pre-tax cash flow, and, based on this principle,
produce gas through the year in which project NPV is maximized.
Starting from this general framework, the analysis proceeds as follows:
> Solve for the lowest starting wellhead price (and associated price path) that yields non-negative
NPV over the project analysis period, which includes the initial development years and the years
following initial development. The analysis period may include years of negative cash flow,
For information on the development of the price projections, see Appendix A.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 26
-------
particularly during the early project years when development wells are being drilled. The solution
for lowest starting wellhead price reflects the implicit price path, based on the CAGRs for the
EIA price projections. The following discussion refers to the lowest starting wellhead price that
yields non-negative NPV, as the breakeven starting price.
> EPA assumed that the project ceases production following the year in which NPV is maximized.
Beyond this year, operating cash flow becomes negative and subsequent production reduces the
NPV below the maximum achievable value. Total gas production for the project is simply the
sum of CBM gas production quantities over this production life.
> EPA then found the actual calendar year, for the associated basin-specific EIA price case, in
which the starting breakeven price would occur. As noted in Appendix A, EPA extended the price
forecasts through 2050, to allow identification of breakeven price years that are after 2040.
> This analysis yields the following key outputs: starting breakeven price, year of occurrence
(economicalproduction year}, and total quantity of CBM gas produced.
EPA performed this analysis for the following case specifications:
> By model project
> By EIA gas-price case
> By required rate of return (7 and 17 percent)
EPA first performed the baseline analysis, followed by the post-requirements analysis. As key output
metrics for these analyses, EPA calculated:
> The delay in economical production year between baseline and post-requirements cases. EPA
found that most new projects are not economically viable under current natural gas prices, but
would become viable in a future year as a result of increasing natural gas prices - that is, new
projects would be delayed independent of wastewater treatment requirements. When EPA found
that wastewater discharge requirements would further delay viable development of these projects,
EPA termed this delay the additional delay. This additional delay constitutes a potential Barrier
to Development of new projects and is a key consideration in assessing the economic impact of
potential wastewater discharge requirements on new CBM projects.
> The change in total CBM gas production between baseline and post-requirements cases. Potential
reductions in gas production for a given model project because of discharge requirements
constitutes an additional adverse economic impact. EPA accounted for such reductions as part of
the Barrier to Development analysis.
4.2 Analysis Results
The following sections summarize the analysis findings:
> Section 4.2.1 summarizes the results of the analysis using a 17-percent required rate of return
(hurdle rate). Table 4-2 reports these analysis results.
> Section 4.2.2 summarizes the results of the analysis using a 7-percent required rate of return
(hurdle rate). Table 4-3 reports these analysis results.
Unlike the presentation of results for the existing projects analysis, EPA reports these results separately
by required rate of return/hurdle rate case because of the additional information presented in the new
sources analysis - in particular, focusing on the delay in economical production year.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 27
-------
4.2.1 Using 17-Percent Required Rate of Return (Hurdle Rate)
For the baseline analysis, none of the model projects are currently economically viable, regardless of
basin.32 The Green River and Powder River Basins' primary model projects (GR1 and PRB1) are not
viable at baseline for any of the price growth cases. The Raton model project (Ratonl) is not economical
at baseline only under the low price growth case. For the other model projects and price growth cases, the
projects become viable within the period of the analysis, with the economical production years ranging
from 2018 and 2049. Economical production years and delay beyond 2013 are as follows:
> The secondary Appalachian model project (APP2) has the earliest economical production years,
2018 to 2023 or a delay of 5 to 10 years beyond 2013, depending on price case. Economical
production years for the primary Appalachian model project (APP1) are later, at 2040 to 2044 or
a delay of 27 to 31 years beyond the present.
> For the Illinois basin model projects (ILL1 and ILL2), the earliest production years are 2041 to
2045, or a delay of 28 to 32 years beyond 2013.33
> For the Black Warrior/Cahaba basin model projects (BW1, BW2, Cahabal, Cahaba2), the earliest
production years are 2026 to 2035, or a delay of 13 to 22 years beyond 2013.
> For the Powder River Basin secondary model project (PRB2), the earliest production years are
2026 to 2035, or a delay of 13 to 22 years beyond 2013.
> For the Raton basin model project (Ratonl), the earliest production years are 2048 to 2049, or a
delay of 35 to 36 years beyond 2013, forthe reference and high price growth cases.
For the IX treatment technology option, the economical production year is additionally delayed from zero
years to a maximum of 20 years for projects that become economical before 2050. The model project
additional delay effects are as follows:
> The Appalachian basin primary model project experiences no additional delay in economical
production years, the secondary model project (APP2) experiences an additional delay of 1 to 2
years.
> The Illinois basin model projects (ILL1 and ILL2) experience no additional delay.
> The Black Warrior/Cahaba basin model projects (BW1, BW2, Cahabal, Cahaba2) experience
additional delays of 1 to 4 years.
32 In contrast to the finding in the existing project analysis that some existing projects remain economically viable, the new
project analysis found that new projects are not currently viable because these projects would need to incur all of the project
development costs - i.e., lease acquisition, project planning, and drilling of wells. In the existing project analysis, projects
have already incurred these costs and they do not enter into the assessment of economic viability of continued production for
existing projects: for the existing project analysis, these costs are considered sunk and are not accounted for in assessing the
viability of existing projects. This distinction is very important in assessing the viability of existing and new projects: new
projects have not already incurred these costs and a projects' production economics must support incurrence of these
substantial upfront costs in order for new projects to be economically viable.
33 Although the Appalachian and Illinois model projects are the same, the baseline (and post-requirements) results differ
slightly because of the assignment of different natural gas prices and price paths to the basins. The prices and price paths are
mapped to basins based on the specific states within a basin. The prices for the Illinois basin are based on wellhead prices in
Kentucky, Indiana and Illinois, while the Appalachian basin reflects Kentucky, Tennessee, Ohio, Pennsylvania, Virginia and
West Virginia. This result differs from the Black Warrior and Cahaba basins, which also use the same model project and,
with both basins being in Alabama, the same prices. As a result, the analysis findings for Black Warrior and Cahaba are
identical. See discussion at Section 2.2.2, page 8.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 28
-------
> The Powder River Basin secondary model project (PRB2) experiences additional delay of 14 to
20 years.
> The Raton basin model project experiences additional delay of 2 years under the high price
growth case; the estimated additional delay extends beyond the end of the analysis period for the
reference and low price growth cases.
In cases where there is a range in the number of additional-delay-years for a given basin, the range results
from the different price growth cases.
Gas production effects are generally small, and occur as increases, ranging from no change to an increase
of nearly 3 percent. The finding that production increases with the addition of technology option costs is
at first counter-intuitive. However, on closer inspection, the increased production results from the higher
breakeven price that is required for the technology option case than for the baseline (no additional cost)
case. Even though prices grow at the same year-over-year CAGR under both cases, the simple numerical
slope of the price path that begins from the higher breakeven price (required for the technology option
case) increases more rapidly than the slope under the price path that begins from the lower breakeven
price (for the baseline case). The greater increase, year-over-year, in the simple slope means that project
economics improve more rapidly in out-years for the higher breakeven price case, and that the production
life can be extended for this case with the higher price (and revenue increases) compared to the lower
breakeven price case. Of importance, even though gas production may increase in some of the analysis
cases, the increase occurs with a delay in production, and accordingly, a delay in realization of the
economic benefit to society from natural gas production: on a discounted present value basis, the quantity
and economic value from natural gas production may be less under the post-requirements case even
though a larger quantity of gas is produced.
For the UI disposal option, which is generally more expensive than the IX technology option, the
additional delays in economical production year are greater than under the IX technology option. The
economical production year is additionally delayed from a minimum of 1 year to a maximum of 21 years
for projects that become economical before 2050. The model project additional delay effects are as
follows:
> The Appalachian basin primary model (APP1) project experiences additional delay of 1 to 2
years; the secondary model project (APP2) experiences additional delay of 10 to 13 years.
> The Illinois basin model projects (ILL1 and ILL2) experience additional delays of 1 to 2 years.
> The Black Warrior/Cahaba basin primary model project (BW1, Cahabal) experiences additional
delays of 11 to 16 years; the secondary model project (BW2, Cahaba2) experiences additional
delays of 6 to 10 years.
> The Powder River Basin secondary model project (PRB2) experiences additional delay of 15 to
21 years.
> The estimated additional delay for the Raton basin model project extends beyond the end of the
analysis period.
The gas production effects are more substantial with UI disposal than with IX treatment. Again, these
effects are due to increased gas production, which, as described above, results from the additional delay in
economical production year and the assumption of constant percentage growth in natural gas prices.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 29
-------
Table 4-2: Effect of Wastewater Discharge Requirements on New CBM Projects, Using 17 Percent
Hurdle Rate3
Model Project
Baseline
First Year in
Which
Production Is
Economical
Production
(MMcf)
Basis: Ion Exchange (IX)
Delay in First
Year of
Production
(years)
Change in
Production (%)
Basis: Underground Injection (UT)
Delay in First
Year of
Production
(years)
Change in
Production (%)
Bgh Price Growth Case
APP1
APP2
ILL1
ILL2
BWl/Cahabal
BW2/Cahaba2
GR1
PRB1
PRB2
Ratonl
2040
2018
2041
2041
2026
2026
after 2050
after 2050
2026
2048
88,682
47,577
88,682
47,577
147,863
1,148,990
NA
NA
18,541
61,506
0
1
o
o
4
2
after 2050
after 2050
20
2
0.0%
0.0%
0.0%
0.0%
0.0%
2.8%
NA
NA
0.0%
0.0%
2
10
2
2
16
10
after 2050
after 2050
21
after 2050
0.0%
1.3%
0.0%
1.3%
0.0%
22.8%
NA
NA
0.0%
NA
Reference Case
APP1
APP2
ILL1
ILL2
BWl/Cahabal
BW2/Cahaba2
GR1
PRB1
PRB2
Ratonl
2042
2020
2043
2043
2032
2031
after 2050
after 2050
2030
2049
88,682
47,315
88,682
47,315
147,863
1,118,228
NA
NA
18,541
61,506
0
2
o
o
2
2
after2050
after2050
17
after 2050
0.0%
0.6%
0.0%
0.6%
0.0%
2.7%
NA
NA
0.0%
NA
1
13
1
1
12
7
after 2050
after 2050
18
after 2050
0.0%
1.9%
0.0%
1.9%
0.0%
22.6%
NA
NA
0.0%
NA
!x)w Price Growth Case
APP1
APP2
ILL1
ILL2
BWl/Cahabal
BW2/Cahaba2
GR1
PRB1
PRB2
Ratonl
2044
2023
2045
2045
2035
2035
after 2050
after 2050
2035
after 2050
88,682
47,024
88,682
47,024
147,863
1,082,291
NA
NA
18,541
NA
0
2
o
o
2
T
after 2050
after 2050
14
after 2050
0.0%
0.6%
0.0%
0.6%
0.0%
2.7%
NA
NA
0.0%
NA
1
13
1
1
11
6
after 2050
after 2050
15
after 2050
0.0%
2.1%
0.0%
2.1%
0.0%
22.5%
NA
NA
0.0%
NA
a. EPA conducted analyses of new projects only for projects where the first year in which production is economical is within the period from
2010 to 2050. The analysis stops at 2050.
Source: U.S. EPA Analysis, 2013
4.2.2 Using 7-Percent Required Rate of Return (Hurdle Rate)
The baseline analysis using the 7-percent required rate of return differ slightly from those developed for
the 17-percent rate, with the economical production years generally earlier than the value estimated for
the 17-percent rate. At the 7-percent rate, the Appalachian, Black Warrior and Cahaba secondary model
projects (BW2/Cahaba2 and APP2) are already economical, while the analysis using under the 17 percent
rate found no model projects to be currently economical. Other model projects would become economical
between 2016 and 2045. Using the 7-percent rate, only the Green River basin model project is not
currently economical at baseline.
Economical production years and delay beyond 2013 are as follows:
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 30
-------
> The analysis indicates that the secondary Appalachian model projects (APP2) is currently
economical under all price cases. Economical production years for the primary Appalachian
model project (APP1) are later, at 2028 to 2036 or a delay of 15 to 23 years beyond 2013.
> For the Illinois basin model projects (ILL1 and ILL2), the earliest production years are 2030 to
2037, or a delay of 17 to 24 years beyond 2013.
> The analysis indicates that the secondary Black Warrior/Cahaba basin model projects (BW2,
Cahaba2) are currently economical with the reference and high price growth cases. Under the low
price growth case, the economical production year for BW2 and Cahaba2 is delayed to 2016. For
the primary Black Warrior/Cahaba basin model projects (BW1, Cahabal), the earliest production
years are 2016 to 2018, or a delay of 3 to 5 years beyond 2013.
> For the Powder River Basin primary model project (PRB 1), the earliest production years are 2041
to 2045, or a delay of 28 to 32 years beyond 2013. For the Powder River Basin secondary model
project (PRB2), the earliest production years are 2022 to 2028, or a delay of 9 to 15 years beyond
2013.
> For the Raton basin model project (Ratonl), the earliest production years are 2036 to 2041, or a
delay of 23 to 28 years beyond 2013.
For the IX treatment technology option, the economical production year is additionally delayed from zero
years to a maximum of 23 years for projects that become economical before 2050. The model project
additional delay effects are as follows:
> The Appalachian basin primary model project experiences no additional delay in economical
production years under the high and low price growth cases, and a one to year additional delay
under the reference price growth case. The secondary Appalachian basin model project (APP2)
experiences no delay in economical production year.
> The Illinois basin model projects (ILL1 and ILL2) experience no additional delay under the low
price growth case and an additional delay of one year under the reference and high price growth
cases.
> The Black Warrior/Cahaba basin model projects (BW1, BW2, Cahabal, Cahaba2) experience no
additional delay under the high price growth case, and additional delays of 1 to 6 years under the
reference and low price growth cases.
> The Powder River Basin primary model project (PRB 1) experiences an additional delay of 2
years, while the secondary model project (PRB2) experiences additional delay of 19 to 23 years.
> The Raton basin model project experiences additional delay of 3 years.
As stated above, in cases where there is a range in the number of delay-years for a given basin, the range
results from the different price growth cases.
Gas production effects are somewhat greater under the 7-percent required rate of return than under the 17-
percent rate, and, again, occur as increases, ranging from no change to an increase of nearly 13 percent.
As observed for the 17-percent required rate of return, additional delays in economical production year
are greater with UI disposal than with IX treatment. The economical production year is additionally
delayed from a minimum of 1 year to a maximum of 24 years for projects that become economical before
2050. The model project additional delay effects are as follows:
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 31
-------
> The Appalachian basin primary model (APP1) project experiences additional delay of 1 to 5
years; the secondary model project (APP2) experiences additional delay of 8 to 13 years.
> The Illinois basin model projects (ILL1 and ILL2) experience additional delays of 1 to 4 years.
> The Black Warrior/Cahaba basin primary model project (BW1, Cahabal) experiences additional
delays of 18 to 20 years; the secondary model project (BW2, Cahaba2) experiences additional
delays of 9 to 12 years.
> The Powder River Basin primary model project (PRB1) experiences additional delay of 2 to 3
years. The Powder River Basin secondary model project (PRB2) experiences additional delay of
20 to 24 years.
> The Raton basin model project experiences additional delays of 3 to 4 years.
Also as described for the 17-percent rate analysis, the gas production effects are more substantial with UI
disposal than with IX treatment, with production effects ranging from zero to 28 percent. Again, these
effects are to increase gas production, which results from the additional delay in economical production
year and the assumption of constant percentage growth in natural gas prices.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 32
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Table 4-3: Effect of Water Discharge Requirements on New CBM Projects, Using 7 Percent Hurdle
Rate3
Model Project
Baseline
First Year in
Which
Production Is
Economical
Production
(MMcf)
Ion Exchange (IX)
Delay in First
Year of
Production
(years)
Change in
Production (%)
Underground Injection (UI)
Delay in First
Year of
Production
(years)
Change in
Production (%)
Bgh Price Growth Case
APP1
APP2
ILL1
ILL2
BWl/Cahabal
BW2/Cahaba2
GR1
PRB1
PRB2
Ratonl
2028
2010
2030
2030
2016
2010
after 2050
2041
2022
2036
88,682
45,500
88,682
45,500
147,863
454,634
NA
53,151
17,463
61,506
0
o
I
I
o
0
after 2050
2
22
3
0.0%
1.0%
0.0%
1.0%
0.0%
3.3%
NA
0.0%
6.2%
0.0%
5
8
4
4
18
9
after 2050
2
23
4
0.0%
4.0%
0.0%
4.0%
0.0%
27.6%
NA
0.0%
6.2%
0.0%
Reference Case
APP1
APP2
ILL1
ILL2
BWl/Cahabal
BW2/Cahaba2
GR1
PRB1
PRB2
Ratonl
2033
2010
2034
2034
2016
2010
after 2050
2042
2023
2038
88,682
45,500
88,682
45,500
147,863
444,788
NA
53,151
17,463
61,506
1
0
1
1
2
6
after 2050
2
23
3
0.0%
1.0%
0.0%
1.0%
0.0%
3.3%
NA
0.0%
6.2%
0.0%
2
10
2
2
20
12
after 2050
3
24
4
0.0%
3.3%
0.0%
3.3%
0.0%
27.5%
NA
0.0%
6.2%
0.0%
!x)w Price Growth Case
APP1
APP2
ILL1
ILL2
BWl/Cahabal
BW2/Cahaba2
GR1
PRB1
PRB2
Ratonl
2036
2010
2037
2037
2018
2016
after 2050
2045
2028
2041
88,682
45,500
88,682
45,500
147,863
433,136
NA
53,151
16,426
61,506
0
0
0
0
2
1
after 2050
2
19
3
0.0%
0.0%
0.0%
0.0%
0.0%
3.3%
NA
0.0%
12.9%
0.0%
1
13
1
1
20
10
after 2050
2
20
3
0.0%
3.3%
0.0%
3.3%
0.0%
27.3%
NA
0.0%
12.9%
0.0%
a. EPA conducted analyses of new projects only for projects where the first year in which production is economical is within the period from
2010 to 2050. The analysis stops at 2050.
Source: U.S. EPA Analysis, 2013
4.3 Uncertainties and Limitations
Like the existing project analysis, the new project analysis is subject to a range of uncertainties and
limitations, which may lead to over- or under-estimation of the impact of treatment technologies on the
economics of new CBM projects. Key uncertainties and limitations for the economic analysis34 include:
> The analysis uses relatively simple basin-level models to assess project economics in the baseline
and with installation of treatment technology. These models cannot capture all of the complexities
of CBM project development and production. In addition, the models and the assumptions of the
analysis cannot replicate the decision process of developer/operators in deciding such matters as:
34 See the Technical Development Document for the Coalbed Methane Extraction Industry (DCN CBM00669) for additional
details and assumptions regarding ion exchange and underground injection.
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 33
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whether and when to develop a CBM gas opportunity; how to develop it in terms, for example, of
number of wells and timing of wells; and when to shut down production. EPA's analysis based on
the model projects provides valuable insight into the economics of production across basins;
nevertheless, the resource characteristics and production economics of actual CBM projects are
likely to differ, perhaps substantially, from the model projects used in this analysis. As a result,
the findings of impact from discharge requirements on project economics may be greater or less
than the impacts that would occur with actual CBM projects.
> The analysis uses a relatively simple, deterministic framework to estimate gas production and
project economic performance overtime. Omission of the uncertainties in production, prices, and
costs may lead to lead to over- or under-estimation of the impact of wastewater discharge
requirements on project economics and develop/operator decisions.
> The actual gas prices received by each project likely differ from those estimated for and used in
this analysis, which may over- or under-state the impact of wastewater discharge requirements.
> The estimates of project costs and treatment technology option costs assume no change in the
underlying unit cost values on an inflation-adjusted basis - that is, costs are assumed to change in
in line with general inflation. If costs change in the future in a way that differs from general
inflation - whether at a higher or lower rate - then the analysis of project economics may over- or
under-state the impact of wastewater discharge requirements.
> EPA completed this analysis on a pre-tax basis, which means that the analysis does not account
for potential effects of tax considerations on project development, production, and termination
decisions. Omitting these considerations from the analysis could lead to over- or under-estimation
of the impact of wastewater discharge requirements on project economics and develop/operator
decisions.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 34
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Overall, this analysis shows that based on the 2008 CBM survey data and a 2010 data review, a large
fraction of existing CBM projects are no longer economically viable, independent of the wastewater
discharge requirements considered in this analysis. Specifically, EPA estimated that approximately 25
percent of existing CBM projects either closed immediately in 2008 or were non-operational by 2010.
EPA expects that an additional 43 percent of the existing CBM projects reported in 2008 were shut down
by 2012. The deteriorating economic viability of these projects results largely from declining natural gas
prices since the time of the CBM survey.
For the analysis of the impact of wastewater discharge requirements on existing projects, EPA focused on
the 112 CBM projects that were found economically viable out of the 148 total projects given the 23
immediate baseline closures estimated through the 2008 assessment and 13 projects found non-
operational in 2010. Of these 112 CBM projects, EPA found that the wastewater technology options
considered in this analysis would lead to immediate or earlier shutdown of CBM projects and losses in
gas production than would occur in the absence of technology costs. Specifically, EPA estimated that
under the IX treatment option, 24 percent of the 112 projects estimated to be economically viable in the
baseline would shut down immediately, with an additional 26 to 33 percent experiencing losses in
production life. Under the UI disposal option, 27 percent of the 112 economically viable projects would
shut down immediately, with an additional 38 to 44 percent experiencing losses in production life. In
general, because UI disposal costs are higher than IX treatment costs, the loss in production life and
quantity is greater under the UI option than that under the IX treatment option.
Further, this analysis found that new CBM projects in most CBM gas basins are not economically viable
at current natural gas prices, independent of the wastewater discharge requirements considered in this
analysis. For most basins and analysis cases, natural gas prices need to increase substantially above
currently low levels before new CBM projects become economically viable. If CBM developers seek a
level of financial return indicated to EPA by CBM industry representatives (17 percent), projects are not
currently viable in any of the CBM basins analyzed under a range of natural gas price growth cases.
Using the rate of return of 17 percent indicated by CBM project developers, new projects would not be
viable until 2018 - 2049 with most new projects delayed by at least 30 years. For the 7-percent required
rate of return case, CBM projects appear currently viable in only three of the seven discharging CBM
basins, and these instances most often occur under higher natural gas price growth cases.
Accounting for costs of the wastewater discharge requirements considered in this analysis generally
lengthens the delay until new CBM projects would become economically viable. Under either the IX
treatment or UI disposal options, additional delays before projects would be economically viable -
beyond the delays already discussed above for new projects to become viable even without such
requirements - range from zero years to over 20 years. For the IX treatment option, using industry's
indicated rate of return of 17 percent, most model projects experience an additional delay of two years.
Under the more expensive UI disposal option, additional delays range from 1 to more than 20 years.
Using the 17-percent rate of return, most projects experience a delay of over 20 years. In summary, the
addition of wastewater discharge requirements would substantially burden the economic/financial
performance of new CBM projects, and would further delay project viability by a significant number of
years for most projects, regardless of the natural gas growth cases or the financial return sought by CBM
project developers.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 35
-------
Overall, EPA found that applying wastewater discharge requirements would impose significant burdens
in terms of immediate or early shutdown and loss of gas production from the projects that remained
economically viable at 2008 and 2010. For new projects, EPA reached the following findings: (1) CBM
projects do not generally appear economically viable at present, and for many development opportunities,
for substantial periods into the future, and (2) discharge requirements would further delay these projects'
economic viability.
Given these findings for both existing and new sources, EPA's judgment at this time is that it should not
move forward with additional regulation of wastewater discharges from CBM projects. Pending changes
in CBM gas production economics, and increased volume of CBM activity and wastewater discharges,
and possible changes in the available wastewater management approaches and/or associated costs, EPA
may revisit this decision in future years.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 36
-------
Appendix A Developing Wellhead Price Forecasts
The existing- and new-source economic analyses rely on projections of natural gas prices to assess how
CBM project economics would change over time, and to estimate how treatment technology option costs
would affect project economics. The two analyses use price projections as follows:
> For the existing-source analysis. EPA collected 2008 wellhead prices, by project, in the CBM
survey.35 To estimate future revenue for existing projects, EPA began from the survey-reported
prices but needed estimates of how natural gas prices would change over time to forecast project-
specific prices beyond the survey-reported values.
> For the new-source analysis. EPA again needed future prices for natural gas that new CBM
projects would receive for gas sold. Because the new project analysis does not begin from a price
reported in the CBM survey, however, EPA needed both starting price values and how those
prices would change over time to forecast prices and revenue that would be received by new
projects. In addition, as described in Section 4.1.2, EPA developed natural gas price paths, which
reflect the average expected growth rate in wellhead prices from the present (2013) through 2040,
for the new project analysis. EPA used these price paths to estimate when new CBM projects
would become economically viable, by basin, starting wellhead price, and required rate of return.
For both the existing- and new-source analyses, the appropriate price concept for these prices is an
upstream price, specifically wellhead price.
Price projections are inherently uncertain. To account for this uncertainty, EPA developed three price
growth cases, based on AEO gas-price projections. The three price growth cases are as follows:
> Reference case, which draws directly from the natural gas reference case. This case assumes an
annual increase of 2.5 percent in GDP between 2010 and 2035, while real disposable income per
capita grows at 1.5 percent per year.
> A High Price-Growth case, which is based on AEO's high economic growth case. This case
assumes an annual GDP growth of 3.0 percent and an annual increase in real disposable income
per capita of 1.6 percent, between 2010 and 2035.
> A Low Price-Growth case, which is based on AEO's low economic growth case. This case
assumes an annual increase of 2.0 percent in GDP and an annual increase of 1.3 percent in real
disposable income per capita between 2010 and 2035.
In addition to these cases, EIA provides other natural gas price forecasts, which are defined on various
parameters, for example, the quantity of natural gas resources determined as technically and economically
recoverable over the next few decades. EPA chose the high and low economic growth cases as providing
reasonable upper and lower price growth cases for economic analysis.
This appendix describes the methodology and data used to develop the estimated year-over-year changes
in wellhead prices, as used in the both the existing- and new-source analyses: the starting price values, by
basin, as used in the new-source analysis; and the price path growth rates, also as used in the new-source
analysis.
For more information on the CBM survey see http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm.
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 37
-------
A.1 Available Data
EPA used the following EIA data to calculate national-level and basin-specific projections:
> Historical wellhead prices by state (U.S. DOE, 2012c)
> U.S. wellhead prices for 2008 from Annual Energy Outlook (U.S. DOE, 201 la)
> Henry Hub and wellhead Reference case, High Economic Growth case, and Low Economic
Growth case price projections for the United States, for the period 2009 to 2035, from Annual
Energy Outlook (U.S. DOE, 2012a)
> Henry Hub wellhead Reference case price projections for the United States, for the period 2010 to
2040, from AEO 2013 Early Release (U. S. DOE, 2012b)
The price projections from AEO 2013 Early Release are EIA's most current estimates of future natural
gas prices. However, EIA's Early Release data are limited in several ways compared to the previous
release. The Early Release forecasts are for the Reference case only; are at the national level only; and are
published as Henry Hub prices, which is downstream from the wellhead, and not the price concept needed
for the impact analyses. Despite these limitations, EPA decided to use the 2013 Early Release data for this
analysis, with certain adjustments. Apart from being one-year more recent than the previous price series,
of particular note is the fact that the 2013 Early Release data extend the forecast an additional five years
into the future, compared to the previous forecast series.
To obtain price projections appropriate for the CBM impact analyses, EPA applied a number of
adjustments, described below, to the AEO 2013 Early Release data.
A.2 Price Adjustments
The following sections describe gas-price adjustments first for the existing-source analysis, and then for
the new-source analysis. The steps in developing the price growth paths for the new-source analysis build
from the methodology outlined for the existing-source analysis.
A.2.1 Existing-Source Analysis
For the existing-source analysis, EPA developed price projections, and associated estimates of year-over-
year changes in prices, by making the following adjustments to the AEO 2013 Early Release data:
1. Using AEO 2012 price projections (i.e., the previous year's forecast) for 2008 to 2035,36 project
DOE prices for the years 2036 through 2040 for each of the price growth cases. EPA made this
projection based on the compound annual growth rate (CAGR) for the last five years provided
(2030 to 2035), and used the calculated CAGR to project prices for the years 2036 to 2040.37 EPA
completed this step for both Henry Hub and wellhead prices.
For the existing project analysis, EPA relied on the full range of annual price projections reported in AEO 2012 (2009 to
2035) and added 2008 price data from AEO 2011 to extend prices from 2008 to 2035.
In EIA's High Economic Growth case, natural gas prices decline steeply in natural gas in 2035 due to an assumed influx of
gas from the Alaskan Natural Gas Transportation System will occur and drive down prices. Following conversation with
EIA, EPA dropped the price data for this year in developing its High Price Growth case, as EIA is no longer assuming that
this significant external event will occur in developing the AEO 2013 price forecasts (Joe Benneche, personal
communication, December 12, 2012). Instead, for the High Price Growth case, EPA used data for the years 2010 to 2034
from EIA's High Economic Growth Case, and projects price data beyond 2034 using the CAGR for the five-year period
from 2029 to 2034.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 38
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2. Using the AEO 2012 price growth paths developed for 2008 to 2040,38 calculate year-by-year
price differentials, using Henry Hub prices, between the Reference case and the alternative price
growth cases.
3. Apply these year-by-year price differentials to the AEO 2013 Reference case price projection for
2008 to 2040 to develop national, Henry Hub projections for the two alternative price growth
cases to be used in this analysis (High Price-Growth Case and Low Price-Growth Case), based on
the newer AEO price series. This adjustment assumes that the year-by-year differentials between
the Reference Case and the alternative price growth cases from AEO 2012, will also apply to the
AEO 2013 data.
4. Using the AEO 2012 price projections developed for 2008 to 2040, calculate the annual price
differentials between Henry Hub and wellhead prices for each of the price cases. Apply these
price differentials to the AEO 2013 price projections developed for 2008 to 2040 to convert the
projections based on the 2013 Early Release from Henry Hub to wellhead prices, for each of the
price growth cases. This adjustment assumes that the differential between Henry Hub and
wellhead prices from the AEO 2012 forecasts, will also apply to the AEO 2013 data.
5. Calculate the CAGR values forthe period 2035-2040 from each of the adjusted price growth
cases; use these CAGR values to project wellhead prices for all price forecast cases from 2040 to
2050.
6. Calculate the year-over-year percent change in prices for each of the price growth cases, for the
years 2008 to 2042 (see Table A.2-1).
Table A.2-1: Year-Over-Year Percent Changes in Gas
Wellhead Prices
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Low
na
-54.6%
10.7%
-9.5%
-37.8%
17.5%
-7.6%
-1.6%
16.4%
3.4%
8.6%
1.5%
1.8%
2.1%
4.6%
3.3%
2.7%
0.5%
2.3%
1.3%
2.3%
0.7%
1.9%
2.1%
1.2%
Reference
na
-54.6%
10.7%
-9.5%
-37.2%
20.3%
-5.3%
-0"7%
16"9%
4"5%
7J%
2.0%
2"6%
2"5%
4"8%
4"l%
2.5%
1.4%
3.1%
0.9%
2J%
11%
ij%
2"4%
1.7%
High
na
-54.6%
10.7%
-9.5%
-37.0%
21.5%
-5.6%
oj%
18"2%
4"6%
8"6%
2.7%
3"2%
3'7i%
4J%
5""6%
2.5%
2.4%
4.3%
0.4%
2"9%
0"8%
r'8%
2"5%
0.8%
38 National price data for 2008 through 2011 are EIA modeled prices and may vary from EIA reported historical prices for
those years.
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 39
-------
Table A.2-1: Year-Over-Year Percent Changes in Gas
Wellhead Prices
Year
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
Low
4.2%
2.7%
5.8%
6.6%
5.8%
6.0%
2.0%
3.1%
4.7%
4.7%
Reference
2.5%
4.2%
4"6%
6"2%
5"4%
5"6%
2"6%
3"6%
4"4%
4"4%
High
4.2%
4.0%
2"9%
5"6%
5""6%
5"2%
r'8%
2"8%
4"T%
4"l%
Source: U.S. EPAAnalysis,2013; U.S. DOE, 201 la; U.S. DOE,
2012a; and U.S. DOE, 2012b
7. Apply year-over-year percent change in prices to 2008 average wellhead price for each project,
for each price growth case, to develop project-specific prices for each analysis year.
A.2.2 New-Source Analysis
Because of the issues associated with the Early Release forecasts, as noted above, EPA needed to perform
the following adjustments to develop basin-specific wellhead price paths for the new-source analysis:
1. Develop a national-level price projection for each of the price cases, for the years 2010 to 2050,
using Step 1 through Step 5 from the adjustments listed above.
2. Restate prices from 2011 dollars to 2010 dollars (the analysis year) using GDP deflator series.
3. Develop wellhead prices by basin by mapping the average annual wellhead prices by state, for
2010, to the CBM basins, and averaging the state-level prices for each basin.39 These prices
provide the basin-specific price values to which the profiles of price change, from the national-
level price forecasts, are applied in developing basin-specific forecasts, as described in the next
step.
4. Calculate the year-over-year percentage change for each of the national wellhead price cases, for
the period 2010-2050.
5. Apply these year-over-year percentage changes for each price case to the average wellhead price
per basin to develop the three price projections from 2010 to 2050 for each basin analyzed. The
resulting values are approximate wellhead natural gas prices in 2010 dollars, by CBM basin.
These values build from the 2013 Early Release price forecast profile, and retain the year-by-year
differentials between the Reference Case and alternative growth cases and the year-by-year
differentials between Henry Hub prices and wellhead price - both as observed in the complete
price dataset from AEO 2012.
The following tables report the basin-specific price projections that EPA developed for each of the price
growth cases, and used in the new project analysis. As reflected in the tables, EIA projects volatility in
natural gas prices in the short term with a sharp decline into 2012, a significant increase in 2013, and then
another period of decline into 2015. In the longer term, prices grow steadily, beginning to rise at a higher
rate in the early 2030s.
EPA relied on actual historical state-level prices reported by EIA for the year 2010.
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 40
-------
Table A.2-2: Basin Specific Price Projections for the Reference Case (CAGR of 3.3%)
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
APP (VA, WV,
PA, OH)
$4.63
$4.19
$2.63
$3.17
$3.00
$2.98
$3.48
$3.63
$3.91
$3.99
$4.07
$417
$4.37
$4.55
$4.66
$4.73
$4.87
$4.92
$5.05
$5.12
$5.21
$5.33
$5.42
$5.55
$5.79
$6.05
$6.43
$6.77
$7.16
$7.30
$7.52
$7.86
$8.20
$8.57
$8.95
$9.35
$9.76
$10.19
$10.65
$11.12
$11.61
BW and Cahaba
(AL)
$4.46
$4.04
$2.53
$3.05
$2."89
$2.87
$3.35
$"3.50
$3.77
$"3.84
$192
$4.02
$4.21
$438
$449
$4.55
$469
$474
$486
$493
$J02
$5713
$"5".22
$535
$5757
$5783"
$6719
$6753"
$6789"
$7."6"3"
$"7.25
$7757
$7."9"6"
$8.25
$8762"
$"9.00
$9.40
$"9.82
$1025
$T6".7"i
$Tu9
GR (WY, CO)
$4.13
$3.74
$2.35
$2.82
$2.68
$2.66
$3~To
$"3"".24
$349
$"3"".56
$3.63
$3.72
$3.90
$4.06
$4.16
$4.22
$4.35
$4.39
$4.50
$4.56
$4.64
$4.75
$4.83
$4.95
$5.16
$5.40
$5".73
$6764
$6738"
$e3T
$"6771
$7.01
$7732"
$7.64
$7.98
$8.34
$8.71
$9.09
$9.50
$9.92
$10.36
PRB (MT, WY)
$3.97
$3.59
$2.26
$2.71
$2.57
$2.55
$2.98
$3.12
$3.36
$3.42
$3.49
$3.58
$3.75
$3.90
$4.00
$4.05
$4.18
$4.22
$4.33
$4.39
$4.46
$4.57
$4.65
$4.76
$4.96
$5.19
$5.51
$5.81
$6.14
$6.26
$6.45
$6.74
$7.03
$7.35
$7.67
$8.01
$8.37
$8.74
$9.13
$9.53
$9.96
Raton (CO, NM)
$4.64
$4.20
$2.64
$3.17
$3.01
$2.98
$3.49
$3.64
$3.92
$4.00
$4.08
$4.18
$4.38
$4.56
$4.67
$4.74
$4.88
$4.93
$5.06
$5.13
$5.22
$5.34
$5.43
$5.56
$5.80
$6.07
$6.44
$6.79
$7.17
$7.32
$7.54
$7.87
$8.22
$8.59
$8.97
$9.37
$9.78
$10.22
$10.67
$11.14
$11.64
Illinois (IL, IN)
$4.13
$3.74
$2.35
$2.82
$2.68
$2.66
$3.10
$3.24
$3.49
$3.56
$3.63
$3.72
$3.90
$4.06
$4.16
$4.22
$4.35
$4.39
$4.50
$4.56
$4.64
$4.75
$4.83
$4.95
$5.16
$5.40
$5.73
$6.04
$6.38
$6.51
$6.71
$7.01
$7.32
$7.64
$7.98
$8.34
$8.71
$9.09
$9.50
$9.92
$10.36
Source: U.S. EPA Analysis, 2013: U.S. DOE, 201 la; U.S. DOE, 201 2c; U.S. DOE, 201 2a; and U.S. DOE, 201 2b
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 41
-------
Table A.2-3: Basin Specific Price Projections for the Low Price Growth Case (CAGR of 3.0%)
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
APP (VA, WV,
PA, OH)
$4.63
$4.19
$2.61
$3.07
$2.83
$2.79
$3.24
$3.36
$3.65
$3.70
$3.77
$3.85
$4.02
$4.16
$427
$429
$439
$445
$455
$458
$467
$477
$4.83
$5.03
$5.16
$5.46
$5.82
$6.16
$6.53
$6.66
$6.87
$7.19
$7.53
$7.88
$8.25
$8.64
$9.05
$9.47
$9.92
$10.38
$10.87
BW and Cahaba
(AL)
$4.46
$404
$2.5"l
$2.95
$2.73
$2.68
'$Ti2
$3".23
$131
$3".57
$3".63
$3".70
$3".88
$4oT
$4.11
$413
$423
$428
$438
$441'
$450
$460
$465
$484
$497
$5".26
$5".6"l
$5".93
$6.29
$6.42
$6.62
$6.93
$7.25
$7.60
$7.95
$"8.32
$8.72
$9/12
$9.55
$To.oo
jYo.47
GR (WY, CO)
$4.13
$3"74
$2"33
$2773"
$2"53
$249
$2"89
$2"99
$3"25
$3730
$336
$343
$3"59
$3"'77i
$3781
$3"83
$3792"
$3797
$406
$409
$417
$426
$431
$448
$460
$487
$5719
$57so
$5782
$5794
$6713
$642
$6772
$7.03
$7736
$7771
$8707
$845
$8785
$9726
$9770
PRB (MT, WY)
$3.97
$3.59
$2.24
$2.63
$2.43
$2.39
$2.78
$2.88
$3.13
$3.17
$3.23
$3.30
$3.45
$3.57
$3766
$3768
$3777
$3781
$3790
$3793
$401
$409
$4.14
$4.31
$4.43
$4.68
$4.99
$5.28
$5.60
$5.71
$5.89
$6.17
$6.46
$6.76
$7.08
$7.41
$7.76
$8.12
$8.50
$8.90
$9.32
Raton (CO, NM)
$4.64
$4.20
$2.61
$3.07
$2.84
$2.79
$3.25
$3.36
$3.65
$3.71
$3.78
$3.85
$4.03
$4.17
$428
$430
$440
$446
$456
$459
$468
$478
$4.84
$5.04
$5.17
$5.47
$5.84
$6.17
$6.54
$6.68
$6.89
$7.21
$7.55
$7.90
$8.27
$8.66
$9.07
$9.49
$9.94
$10.41
$10.89
Illinois (IL, IN)
$4.13
$3774
$2.33
$2773
$2.53
$249
$2.89
$2.99
$3'.25
$3730
$3736
$343
$3759
$3771'
$3781
$3783
$3792
$3797
$406
$409
$417
$426
$431
$448
$460
$487
$"5"7l9
'$5750
$5782
'$'"5'"."9"4
$6'"."i"3"
$642
$"6"'.72
$7.03
$736
$7".7"i'
$8".'07"
$"8".'4"5
$8785
'$"'9'".'2"6
$"9770
Source: U.S. EPA Analysis, 2013; U.S. DOE, 2011a; U.S. DOE, 201 2c; U.S. DOE, 201 2a; and U.S. DOE, 201 2b
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 42
-------
Table A.2-4: Basin Specific Price Projections for the High Price Growth Case (CAGR of 3.4%)
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
APP (VA, WV,
PA, OH)
$4.63
$4.19
$2.64
$3.21
$3.03
$3.05
$3.61
$3.76
$4.08
$4.19
$4.33
$4.46
$4.67
$4.91
$5.03
$5.15
$5.37
$5.40
$5.55
$5.60
$5.70
$5.84
$5.89
$6.13
$6.38
$6.56
$6.93
$7.28
$7.65
$7.79
$8.01
$8.33
$8.67
$9.02
$9.38
$"9.76
$To.i6
$1057
$7f.oo
$11.44
$11.91
BW and Cahaba
(AL)
$4.46
$4.04
$2.55
$3.09
$2.92
$2.94
$3.48
$3.62
$3.93
$4.04
$4.17
$4.30
$4.50
$4.73
$4.84
$4.96
$5.18
$5.20
$5.35
$5.39
$5.49
$5.63
$5.67
$5.91
$6.14
$6.32
$6.68
$7.01
$7.37
$7.50
$7.71
$8.02
$8.35
$8.69
$9"04
$9"40
$9"79
$Toi8
$1O59
$11.02
$11.47
GR (WY, CO)
$4.13
$3.74
$2.36
$2.86
$2.70
$2.72
$3.22
$3.35
$3.64
$3.74
$3.86
$3.98
$4.17
$4.38
$4.48
$4.59
$4.79
$4.81
$4.95
$4.99
$5.08
$5.21
$5.25
$5.47
$5.69
$5.86
$6.18
$6.49
$6.83
$6.95
$7.14
$7.43
$7.73
$8.04
$8.37
$8.71
$9.06
$9.43
$9.81
$10.21
$10.62
PRB (MT, WY)
$3.97
$3.59
$2.27
$2.75
$2.60
$2.62
$3.10
$3.22
$3.50
$3.59
$3.71
$3.82
$4.01
$4.21
$4.31
$4.42
$4.61
$4.63
$4.76
$4.80
$4.88
$5.01
$5.05
$5.26
$5.47
$5.63
$5.94
$6.24
$6."56
$6.68
$6.86
$7.14
$7.43
$7.73
$8.05
$8.37
$8.71
$9.06
$9.43
$9.81
$10.21
Raton (CO, NM)
$4.64
$4.20
$2.65
$3.22
$3.04
$3.06
$3.62
$3.77
$4.09
$4.20
$4.33
$4.47
$4.68
$4.92
$5.04
$5.16
$539
$5.41
$5.56
$5.61
$5.71
$5.85
$5.90
$6.14
$6.39
$6.58
$6.95
$7.29
$7.67
$7.81
$8.02
$8.35
$8.69
$9.04
$9.40
$9.78
$1018
$1O59
$TTo2
$11.47
$11.93
Illinois (IL, IN)
$4.13
$3.74
$2.36
$2.86
$2.70
$2.72
$3.22
$3.35
$3.64
$3.74
$3.86
$3.98
$4.17
$4.38
$4.48
$4.59
$4.79
$481
$495
$4.99
$5.08
$5.21
$5.25
$5.47
$5.69
$5.86
$6.18
$6.49
$6.83
$6.95
$7.14
$7.43
$7.73
$8.04
$8.37
$8.71
$9.06
$9.43
$9.81
$10.21
$10.62
Source: U.S. EPA Analysis, 2013; U.S. DOE, 2011a; U.S. DOE, 201 2c; U.S. DOE, 201 2a; and U.S. DOE, 201 2b
A.3 Uncertainties and Limitations
While EIA's price projections are inherently uncertain, EPA made a number of assumptions in adjusting
prices that increases this uncertainty:
Augusts, 2013
Economic Analysis of Treatment Technology Options for CBM Projects | pg 43
-------
> EPA extended the AEO 2012 price projections by five years, to 2040, so that these price forecasts
would cover the same period as the AEO 2013 Early Release price forecast. EPA also extended
the adjusted AEO 2013 Early Release price paths 10 years, to 2050, to be used in the impact
analyses. In both cases, EPA assumed that prices would grow at constant year-over-year
percentage growth rates, based on the last five years of the available forecasts, following the end
of the explicit forecast period.
> In creating the High and Low Price Growth cases - based on EIA's Low Economic Growth and
High Economic Growth - EPA based its analysis on the Reference price projections from AEO
2013 Early Release. EPA assumed that the two alternative EIA price cases would deviate from
the Reference case in the same way as they did in the AEO 2012 data. The only exception is the
removal of one year of data in the High Economic Growth case, an outlier reflecting an
assumption that EIA is no longer using in developing the AEO 2013 price forecasts (Joe
Benneche, personal communication, December 12, 2012).
> In converting the AEO 2013 Early Release prices from Henry Hub to wellhead projections, EPA
used the year-by-year price differentials from the extended AEO 2012 price paths.
> For the AEO 2013 Early Release data, EIA reports price projections at only the national level.
• To establish projections that are more consistent with those that new CBM projects could
expect to receive, EPA calculated basin-specific projections, averaging prices over the states
in which a basin is located, with the assumption that future annual price changes for each
state would mirror changes at the national level.
• To develop project-specific projections for existing projects, EPA assumed that the future
changes in price experienced by each project would mirror the national-level price projection.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 44
-------
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