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
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg i

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.1 Available Data .................................................................................................................................. 38

A.2 Price Adjustments............................................................................................................................. 38
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg ii

A.2.1 Existing-Source Analysis....................................................................................................... 38

A.2.2 New-Source Analysis............................................................................................................. 40

A.3 Uncertainties and Limitations........................................................................................................... 43

References.................................................................................................................................................. 45
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg iii

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 Characteristicsa.....................................................................................................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,c,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 (CAGR of 3.3%)..........................41

Table A.2-3: Basin Specific Price Projections for the Low Price Growth Case (CAGR of 3.0%).............42

Table A.2-4: Basin Specific Price Projections for the High Price Growth Case (CAGR of 3.4%)............43
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 1

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 (postrequirements 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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 2

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.

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 

Table 1-1. Total CBM Gas Production (Million Cubic Feet), 2007–2011

Industry 2007 2008 2009 2010 2011a

Coalbed Methane Wells 1,999,748 2,022,228 2,010,171 1,916,762 1,779,055

Shale Gas Wells 1,990,145 2,869,960 3,958,315 5,817,122 8,500,983

a. Data for 2011 are estimated.

Source: U.S. DOE, 2013a
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 3

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

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 zerodischarge methods, either applied separately or in combination for the same project.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 4

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 watermanagement 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 zerodischarge methods for managing produced water (both in discharging basins and non-discharging basins), 

to the effect estimated for discharging projects.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 5

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 oneyear 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/).
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 6

 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. 
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 7

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

Detailed Questionnaire Data 

Elements Required Detailed Questionnaire Question

Gross revenue - All money received in 

2008 for the gas sold. Project gas 

production sold (Mcf) multiplied by the 

project average wellhead price ($/Mcf).

2008 gas sold Question B3-60

2008 average wellhead gas price Question B3-62: Requested minimum, 

average, and maximum wellhead price 

received for the project.

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).

2008 royalty rate Question B3-65

2008 severance payment and 

severance tax percentage

Question B3-66

2008 ad valorem payment and ad

valorem tax percentage

Question B3-67

Gas production operating and maintenance 

(O&M) costs.

2008 total gas production O&M 

costs

Question B3-50

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.

2008 produced water management 

system (PWMS) O&M cost (2008 

O&M cost for operating the PWMS)

Question C2-7a

2008 total revenue from operating 

PWMS

Question C2-7b

2008 transport O&M costs (O&M 

costs for gathering and transporting 

the produced water to the PWMS)

Question C2-8c

2008 trucking O&M cost (O&M for 

transporting water by truck to the 

PWMS)

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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 8

Table 2-2: Estimated Average Annual Gas and Water Decline Rates

Region Gas Water

Eastern U.S. basins 7.4% 6.5%

Western U.S. basins 11.2% 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 development3of 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 Raton1) using information received 

 

3

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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 9

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 newsource 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 

2.2.1and the gas price projections described in Appendix A to analyze the potential effects of wastewater 

management technology costs on new sources. Section 4 describes the new-source analysis, including 

analysis methodology and findings.

Table 2-3. Model Project Characteristicsa

Input Parameter Range of Values

Primary Model Project – Detailed 

Questionnaire Question

Secondary Model 

Project

Wells per project (# wells) 48-400 CBM Survey Question A-1 (wells in 

project) and Screener data

Initial gas production 

(MCF/day/well) 33-112

CBM Survey Question B-59 (total gas) U.S. DOE, 2010; U.S. 

DOE, 2002; Vail and 

Conrad, 2003

Initial water production 

(bbl/day/well) 13-600

CBM Survey Question B-63 (total water) U.S. DOE, 2010; 

Petroleum Association of 

WY, 2005

Land cost ($/well) $380-$200,000

CBM Survey Questions B-20 (lease 

acquisition sum) and B-22 (lump sum to 

secure lease)

U.S. DOE, 2002; Ladlee, 

2011; Lewis, 2004

Drilling cost ($/well) $58,000-$853,000

CBM Survey Questions B-47 (total cost of 

well drilling) and B-48 (total number of 

wells drilled)

U.S. DOE, 2002; SEC 

filings

Lease cost ($/well) $7,830-$164,000

CBM Survey Questions B-23 (one-time 

outlays for project development, before 

2008) and B-49 (total outlay on project 

development, 2008)

U.S. DOE, 2010

Gas production operating 

cost ($/MCF) $0.41-$1.99

CBM Survey Questions B-50 (total O&M 

costs for gas production - 2008) and B-59 

(total gas)

U.S. DOE, 2010; U.S. 

DOE, 2002

Water production operating 

cost ($/bbl of produced 

water)

$0.00-$0.45

CBM Survey Questions C2-7 (total O&M 

costs for water management - 2008) and C2-

3 (total water managed)

U.S. DOE, 2002

Fixed gas production costb

($/well) $978-$17,400 Assumed 5 percent of total gas production operating cost

U.S. DOE, 2010

Fixed water management 

operating cost ($/well) $0-$356 Assumed 5 percent of total water production operating cost

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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 10

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 Region Costs ($/barrel of produced water)

Ion Exchange All basins $0.50

Underground Injection Eastern U.S. basins $4.10

Western U.S. basins $0.54

 

4

See EPA‟s Effluent Limitations Guidelines website for additional information 

(http://water.epa.gov/scitech/wastetech/guide/index.cfm).
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 11

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 over time 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 singleyear analysis not to be as analytically sound as the multiple-year, projection-based analysis. Nevertheless, 
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 12

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 postrequirements 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 over time, 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 non-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. 
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 13

 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.

8

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

 

8 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.

9 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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 14

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:

 Gross revenue: EPA calculated gross revenue as the product of (1) gas sold and (2) 

wellhead gas price estimated for each year following 2008.

 

10 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.

11 Some gas may be used onsite.

12 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).

13 EPA recognizes the uncertainty in this assumption, but lacks information to support a different assumption. 

14 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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 15

 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.

 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. 

 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

 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.

 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 over time; 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 gasextraction 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.
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 16

 Project profitability: For calculating a project‟s NPV, EPA tallied project cash flows on a yearby-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., 
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 17

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 
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 18

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 postrequirements 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. 
July 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 19

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.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 20

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,c,d

Analysis Case 

and Impact 

Metric

Technology Basis: Ion Exchange (IX) Technology Basis: Underground Injection (UI)

Using 17 Percent Hurdle Rate Using 7 Percent Hurdle Rate Using 17 Percent Hurdle Rate Using 7 Percent Hurdle Rate

Unweighted Weighted Unweighted Weighted Unweighted Weighted Unweighted Weighted

Value

% of 

Total Value

% of 

Total Value

% of 

Total Value

% of 

Total Value

% of 

Total Value

% of 

Total Value

% of 

Total Value

% of 

Total

High Price Growth Case

Due to Immediate Project Closurese

Gas Quantity 2.6 0.1% 8.8 0.2% 2.6 0.1% 8.8 0.2% 18.7 0.4% 25.5 0.5% 18.7 0.4% 25.5 0.5%

Project-Years 7 0.6% 89 5.4% 7 0.6% 89 5.4% 11 0.9% 94 5.7% 11 0.9% 94 5.7%

# of Projects 4 6.8% 27 24.3% 4 6.8% 27 24.3% 6 10.2% 30 26.9% 6 10.2% 30 26.9%

Years/Project 2 8.7% 3 22.3% 2 8.7% 3 22.3% 2 9.1% 3 21.2% 2 9.1% 3 21.2%

Due to Production Years Lost at Remaining Projects

Gas Quantity 155.0 3.4% 204.8 4.2% 84.4 1.9% 111.1 2.3% 1,565.7 34.5% 1,691.2 34.4% 1,454.6 32.1% 1,539.5 31.3%

Project-Years 185 15.6% 298 18.1% 127 10.7% 184 11.2% 560 47.3% 730 44.3% 462 39.0% 595 36.2%

# of Projects 18 30.5% 29 26.2% 18 30.5% 29 26.2% 31 52.5% 44 39.3% 30 50.8% 43 38.4%

Years/Project 10 51.2% 10 69.1% 7 35.2% 6 42.7% 18 90.0% 17 112.9% 15 76.7% 14 94.2%

Reference Case

Due to Immediate Project Closurese

Gas Quantity 2.6 0.1% 8.8 0.2% 2.6 0.1% 8.8 0.2% 18.7 0.4% 25.5 0.5% 18.7 0.4% 25.5 0.5%

Project-Years 7 0.6% 89 5.5% 7 0.6% 89 5.5% 11 0.9% 94 5.9% 11 0.9% 94 5.9%

# of Projects 4 6.8% 27 24.3% 4 6.8% 27 24.3% 6 10.2% 30 26.9% 6 10.2% 30 26.9%

Years/Project 2 8.9% 3 22.8% 2 8.9% 3 22.8% 2 9.3% 3 21.7% 2 9.3% 3 21.7%

Due to Production Years Lost at Remaining Projects

Gas Quantity 248.9 5.5% 338.5 6.9% 151.5 3.4% 218.1 4.4% 1,717.1 38.0% 1,841.8 37.6% 1,566.4 34.6% 1,668.1 34.0%

Project-Years 251 21.6% 398 24.7% 166 14.3% 291 18.1% 586 50.3% 753 46.8% 499 42.9% 644 40.0%

# of Projects 22 37.3% 37 32.9% 21 35.6% 36 32.0% 33 55.9% 49 44.2% 31 52.5% 47 42.4%

Years/Project 11 57.8% 11 75.0% 8 40.1% 8 56.4% 18 90.0% 15 105.8% 16 81.6% 14 94.3%

Low Price Growth Case

Due to Immediate Project Closurese

Gas Quantity 2.6 0.1% 8.8 0.2% 2.6 0.1% 8.8 0.2% 18.7 0.4% 25.5 0.5% 18.7 0.4% 25.5 0.5%

Project-Years 7 0.6% 89 5.7% 7 0.6% 89 5.7% 11 1.0% 94 6.0% 11 1.0% 94 6.0%

# of Projects 4 6.8% 27 24.3% 4 6.8% 27 24.3% 6 10.2% 30 26.9% 6 10.2% 30 26.9%

Years/Project 2 9.1% 3 23.6% 2 9.1% 3 23.6% 2 9.5% 3 22.4% 2 9.5% 3 22.4%

Due to Production Years Lost at Remaining Projects

Gas Quantity 287.3 6.4% 375.8 7.7% 275.5 6.1% 364.0 7.5% 1,729.1 38.4% 1,852.7 37.9% 1,729.1 38.4% 1,852.7 37.9%

Project-Years 272 23.9% 413 26.4% 241 21.2% 382 24.5% 581 51.1% 742 47.5% 581 51.1% 742 47.5%

# of Projects 22 37.3% 37 32.9% 21 35.6% 36 32.0% 33 55.9% 49 44.2% 33 55.9% 49 44.2%

Years/Project 12 64.2% 11 80.3% 11 59.6% 11 76.3% 18 91.4% 15 107.5%f18 91.4% 15 107.5%f
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 21

a. % of Total values are calculated relative to baseline.

b. 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.

e. 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
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 22

3.3 Uncertainties and Limitations

This analysis involves several uncertainties and limitations, each of which can lead to over- or underestimation 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 projectspecific 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 23

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 posttreatment, 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).
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 24

 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 non-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 25

 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 26

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 2013 Natural Gas Price ($2010) 2040 Natural Gas Price ($2010) CAGR

Low Economic 

Growth

$3.07 $6.87 3.0%

Reference $3.17 $7.52 3.3%

High Economic 

Growth

$3.21 $8.01 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, 

 

31 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 27

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 

(economical production 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 28

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 (Raton1) 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, Cahaba1, 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 (Raton1), the earliest production years are 2048 to 2049, or a 

delay of 35 to 36 years beyond 2013, for the 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, Cahaba1, 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 29

 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, Cahaba1) 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 30

Table 4-2: Effect of Wastewater Discharge Requirements on New CBM Projects, Using 17 Percent 

Hurdle Ratea

Model Project

Baseline Basis: Ion Exchange (IX) Basis: Underground Injection (UI)

First Year in 

Which 

Production Is 

Economical

Production 

(MMcf)

Delay in First 

Year of 

Production 

(years)

Change in 

Production (%)

Delay in First 

Year of 

Production 

(years)

Change in 

Production (%)

High Price Growth Case

APP1 2040 88,682 0 0.0% 2 0.0%

APP2 2018 47,577 1 0.0% 10 1.3%

ILL1 2041 88,682 0 0.0% 2 0.0%

ILL2 2041 47,577 0 0.0% 2 1.3%

BW1/Cahaba1 2026 147,863 4 0.0% 16 0.0%

BW2/Cahaba2 2026 1,148,990 2 2.8% 10 22.8%

GR1 after 2050 NA after 2050 NA after 2050 NA

PRB1 after 2050 NA after 2050 NA after 2050 NA

PRB2 2026 18,541 20 0.0% 21 0.0%

Raton1 2048 61,506 2 0.0% after 2050 NA

Reference Case

APP1 2042 88,682 0 0.0% 1 0.0%

APP2 2020 47,315 2 0.6% 13 1.9%

ILL1 2043 88,682 0 0.0% 1 0.0%

ILL2 2043 47,315 0 0.6% 1 1.9%

BW1/Cahaba1 2032 147,863 2 0.0% 12 0.0%

BW2/Cahaba2 2031 1,118,228 2 2.7% 7 22.6%

GR1 after 2050 NA after 2050 NA after 2050 NA

PRB1 after 2050 NA after 2050 NA after 2050 NA

PRB2 2030 18,541 17 0.0% 18 0.0%

Raton1 2049 61,506 after 2050 NA after 2050 NA

Low Price Growth Case

APP1 2044 88,682 0 0.0% 1 0.0%

APP2 2023 47,024 2 0.6% 13 2.1%

ILL1 2045 88,682 0 0.0% 1 0.0%

ILL2 2045 47,024 0 0.6% 1 2.1%

BW1/Cahaba1 2035 147,863 2 0.0% 11 0.0%

BW2/Cahaba2 2035 1,082,291 1 2.7% 6 22.5%

GR1 after 2050 NA after 2050 NA after 2050 NA

PRB1 after 2050 NA after 2050 NA after 2050 NA

PRB2 2035 18,541 14 0.0% 15 0.0%

Raton1 after 2050 NA after 2050 NA after 2050 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:
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 31

 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, Cahaba1), 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 (PRB1), 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 (Raton1), 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, Cahaba1, 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 (PRB1) 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 32

 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, Cahaba1) 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 33

Table 4-3: Effect of Water Discharge Requirements on New CBM Projects, Using 7 Percent Hurdle

Ratea

Model Project

Baseline Ion Exchange (IX) Underground Injection (UI)

First Year in 

Which 

Production Is 

Economical

Production 

(MMcf)

Delay in First 

Year of 

Production 

(years)

Change in 

Production (%)

Delay in First 

Year of 

Production 

(years)

Change in 

Production (%)

High Price Growth Case

APP1 2028 88,682 0 0.0% 5 0.0%

APP2 2010 45,500 0 1.0% 8 4.0%

ILL1 2030 88,682 1 0.0% 4 0.0%

ILL2 2030 45,500 1 1.0% 4 4.0%

BW1/Cahaba1 2016 147,863 0 0.0% 18 0.0%

BW2/Cahaba2 2010 454,634 0 3.3% 9 27.6%

GR1 after 2050 NA after 2050 NA after 2050 NA

PRB1 2041 53,151 2 0.0% 2 0.0%

PRB2 2022 17,463 22 6.2% 23 6.2%

Raton1 2036 61,506 3 0.0% 4 0.0%

Reference Case

APP1 2033 88,682 1 0.0% 2 0.0%

APP2 2010 45,500 0 1.0% 10 3.3%

ILL1 2034 88,682 1 0.0% 2 0.0%

ILL2 2034 45,500 1 1.0% 2 3.3%

BW1/Cahaba1 2016 147,863 2 0.0% 20 0.0%

BW2/Cahaba2 2010 444,788 6 3.3% 12 27.5%

GR1 after 2050 NA after 2050 NA after 2050 NA

PRB1 2042 53,151 2 0.0% 3 0.0%

PRB2 2023 17,463 23 6.2% 24 6.2%

Raton1 2038 61,506 3 0.0% 4 0.0%

Low Price Growth Case

APP1 2036 88,682 0 0.0% 1 0.0%

APP2 2010 45,500 0 0.0% 13 3.3%

ILL1 2037 88,682 0 0.0% 1 0.0%

ILL2 2037 45,500 0 0.0% 1 3.3%

BW1/Cahaba1 2018 147,863 2 0.0% 20 0.0%

BW2/Cahaba2 2016 433,136 1 3.3% 10 27.3%

GR1 after 2050 NA after 2050 NA after 2050 NA

PRB1 2045 53,151 2 0.0% 2 0.0%

PRB2 2028 16,426 19 12.9% 20 12.9%

Raton1 2041 61,506 3 0.0% 3 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.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 34

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 over time. 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 35

Conclusion

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 nonoperational 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 36

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 37

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 projectspecific 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.

 

35 For more information on the CBM survey see http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 38

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, 2011a)

 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-overyear 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.

 

36 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.

37 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 39

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 for the 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 Low Reference High

2008 na na na

2009 -54.6% -54.6% -54.6%

2010 10.7% 10.7% 10.7%

2011 -9.5% -9.5% -9.5%

2012 -37.8% -37.2% -37.0%

2013 17.5% 20.3% 21.5%

2014 -7.6% -5.3% -5.6%

2015 -1.6% -0.7% 0.7%

2016 16.4% 16.9% 18.2%

2017 3.4% 4.5% 4.0%

2018 8.6% 7.7% 8.6%

2019 1.5% 2.0% 2.7%

2020 1.8% 2.0% 3.2%

2021 2.1% 2.5% 3.1%

2022 4.6% 4.8% 4.7%

2023 3.3% 4.1% 5.0%

2024 2.7% 2.5% 2.5%

2025 0.5% 1.4% 2.4%

2026 2.3% 3.1% 4.3%

2027 1.3% 0.9% 0.4%

2028 2.3% 2.7% 2.9%

2029 0.7% 1.3% 0.8%

2030 1.9% 1.7% 1.8%

2031 2.1% 2.4% 2.5%

2032 1.2% 1.7% 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.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 40

Table A.2-1: Year-Over-Year Percent Changes in Gas 

Wellhead Prices

Year Low Reference High

2033 4.2% 2.5% 4.2%

2034 2.7% 4.2% 4.0%

2035 5.8% 4.6% 2.9%

2036 6.6% 6.2% 5.6%

2037 5.8% 5.4% 5.0%

2038 6.0% 5.6% 5.2%

2039 2.0% 2.0% 1.8%

2040 3.1% 3.0% 2.8%

2041 4.7% 4.4% 4.1%

2042 4.7% 4.4% 4.1%

Source: U.S. EPA Analysis,2013; U.S. DOE, 2011a; 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 nationallevel 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.

 

39 EPA relied on actual historical state-level prices reported by EIA for the year 2010.
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 41

Table A.2-2: Basin Specific Price Projections for the Reference Case (CAGR of 3.3%)

Year

APP (VA, WV, 

PA, OH)

BW and Cahaba 

(AL) GR (WY, CO) PRB (MT, WY) Raton (CO, NM) Illinois (IL, IN)

2010 $4.63 $4.46 $4.13 $3.97 $4.64 $4.13

2011 $4.19 $4.04 $3.74 $3.59 $4.20 $3.74

2012 $2.63 $2.53 $2.35 $2.26 $2.64 $2.35

2013 $3.17 $3.05 $2.82 $2.71 $3.17 $2.82

2014 $3.00 $2.89 $2.68 $2.57 $3.01 $2.68

2015 $2.98 $2.87 $2.66 $2.55 $2.98 $2.66

2016 $3.48 $3.35 $3.10 $2.98 $3.49 $3.10

2017 $3.63 $3.50 $3.24 $3.12 $3.64 $3.24

2018 $3.91 $3.77 $3.49 $3.36 $3.92 $3.49

2019 $3.99 $3.84 $3.56 $3.42 $4.00 $3.56

2020 $4.07 $3.92 $3.63 $3.49 $4.08 $3.63

2021 $4.17 $4.02 $3.72 $3.58 $4.18 $3.72

2022 $4.37 $4.21 $3.90 $3.75 $4.38 $3.90

2023 $4.55 $4.38 $4.06 $3.90 $4.56 $4.06

2024 $4.66 $4.49 $4.16 $4.00 $4.67 $4.16

2025 $4.73 $4.55 $4.22 $4.05 $4.74 $4.22

2026 $4.87 $4.69 $4.35 $4.18 $4.88 $4.35

2027 $4.92 $4.74 $4.39 $4.22 $4.93 $4.39

2028 $5.05 $4.86 $4.50 $4.33 $5.06 $4.50

2029 $5.12 $4.93 $4.56 $4.39 $5.13 $4.56

2030 $5.21 $5.02 $4.64 $4.46 $5.22 $4.64

2031 $5.33 $5.13 $4.75 $4.57 $5.34 $4.75

2032 $5.42 $5.22 $4.83 $4.65 $5.43 $4.83

2033 $5.55 $5.35 $4.95 $4.76 $5.56 $4.95

2034 $5.79 $5.57 $5.16 $4.96 $5.80 $5.16

2035 $6.05 $5.83 $5.40 $5.19 $6.07 $5.40

2036 $6.43 $6.19 $5.73 $5.51 $6.44 $5.73

2037 $6.77 $6.53 $6.04 $5.81 $6.79 $6.04

2038 $7.16 $6.89 $6.38 $6.14 $7.17 $6.38

2039 $7.30 $7.03 $6.51 $6.26 $7.32 $6.51

2040 $7.52 $7.25 $6.71 $6.45 $7.54 $6.71

2041 $7.86 $7.57 $7.01 $6.74 $7.87 $7.01

2042 $8.20 $7.90 $7.32 $7.03 $8.22 $7.32

2043 $8.57 $8.25 $7.64 $7.35 $8.59 $7.64

2044 $8.95 $8.62 $7.98 $7.67 $8.97 $7.98

2045 $9.35 $9.00 $8.34 $8.01 $9.37 $8.34

2046 $9.76 $9.40 $8.71 $8.37 $9.78 $8.71

2047 $10.19 $9.82 $9.09 $8.74 $10.22 $9.09

2048 $10.65 $10.25 $9.50 $9.13 $10.67 $9.50

2049 $11.12 $10.71 $9.92 $9.53 $11.14 $9.92

2050 $11.61 $11.19 $10.36 $9.96 $11.64 $10.36

Source: U.S. EPA Analysis, 2013: U.S. DOE, 2011a; U.S. DOE, 2012c; U.S. DOE, 2012a; and U.S. DOE, 2012b
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 42

Table A.2-3: Basin Specific Price Projections for the Low Price Growth Case (CAGR of 3.0%)

Year

APP (VA, WV, 

PA, OH)

BW and Cahaba 

(AL) GR (WY, CO) PRB (MT, WY) Raton (CO, NM) Illinois (IL, IN)

2010 $4.63 $4.46 $4.13 $3.97 $4.64 $4.13

2011 $4.19 $4.04 $3.74 $3.59 $4.20 $3.74

2012 $2.61 $2.51 $2.33 $2.24 $2.61 $2.33

2013 $3.07 $2.95 $2.73 $2.63 $3.07 $2.73

2014 $2.83 $2.73 $2.53 $2.43 $2.84 $2.53

2015 $2.79 $2.68 $2.49 $2.39 $2.79 $2.49

2016 $3.24 $3.12 $2.89 $2.78 $3.25 $2.89

2017 $3.36 $3.23 $2.99 $2.88 $3.36 $2.99

2018 $3.65 $3.51 $3.25 $3.13 $3.65 $3.25

2019 $3.70 $3.57 $3.30 $3.17 $3.71 $3.30

2020 $3.77 $3.63 $3.36 $3.23 $3.78 $3.36

2021 $3.85 $3.70 $3.43 $3.30 $3.85 $3.43

2022 $4.02 $3.88 $3.59 $3.45 $4.03 $3.59

2023 $4.16 $4.01 $3.71 $3.57 $4.17 $3.71

2024 $4.27 $4.11 $3.81 $3.66 $4.28 $3.81

2025 $4.29 $4.13 $3.83 $3.68 $4.30 $3.83

2026 $4.39 $4.23 $3.92 $3.77 $4.40 $3.92

2027 $4.45 $4.28 $3.97 $3.81 $4.46 $3.97

2028 $4.55 $4.38 $4.06 $3.90 $4.56 $4.06

2029 $4.58 $4.41 $4.09 $3.93 $4.59 $4.09

2030 $4.67 $4.50 $4.17 $4.01 $4.68 $4.17

2031 $4.77 $4.60 $4.26 $4.09 $4.78 $4.26

2032 $4.83 $4.65 $4.31 $4.14 $4.84 $4.31

2033 $5.03 $4.84 $4.48 $4.31 $5.04 $4.48

2034 $5.16 $4.97 $4.60 $4.43 $5.17 $4.60

2035 $5.46 $5.26 $4.87 $4.68 $5.47 $4.87

2036 $5.82 $5.61 $5.19 $4.99 $5.84 $5.19

2037 $6.16 $5.93 $5.50 $5.28 $6.17 $5.50

2038 $6.53 $6.29 $5.82 $5.60 $6.54 $5.82

2039 $6.66 $6.42 $5.94 $5.71 $6.68 $5.94

2040 $6.87 $6.62 $6.13 $5.89 $6.89 $6.13

2041 $7.19 $6.93 $6.42 $6.17 $7.21 $6.42

2042 $7.53 $7.25 $6.72 $6.46 $7.55 $6.72

2043 $7.88 $7.60 $7.03 $6.76 $7.90 $7.03

2044 $8.25 $7.95 $7.36 $7.08 $8.27 $7.36

2045 $8.64 $8.32 $7.71 $7.41 $8.66 $7.71

2046 $9.05 $8.72 $8.07 $7.76 $9.07 $8.07

2047 $9.47 $9.12 $8.45 $8.12 $9.49 $8.45

2048 $9.92 $9.55 $8.85 $8.50 $9.94 $8.85

2049 $10.38 $10.00 $9.26 $8.90 $10.41 $9.26

2050 $10.87 $10.47 $9.70 $9.32 $10.89 $9.70

Source: U.S. EPA Analysis, 2013; U.S. DOE, 2011a; U.S. DOE, 2012c; U.S. DOE, 2012a; and U.S. DOE, 2012b
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 43

Table A.2-4: Basin Specific Price Projections for the High Price Growth Case (CAGR of 3.4%)

Year

APP (VA, WV, 

PA, OH)

BW and Cahaba 

(AL) GR (WY, CO) PRB (MT, WY) Raton (CO, NM) Illinois (IL, IN)

2010 $4.63 $4.46 $4.13 $3.97 $4.64 $4.13

2011 $4.19 $4.04 $3.74 $3.59 $4.20 $3.74

2012 $2.64 $2.55 $2.36 $2.27 $2.65 $2.36

2013 $3.21 $3.09 $2.86 $2.75 $3.22 $2.86

2014 $3.03 $2.92 $2.70 $2.60 $3.04 $2.70

2015 $3.05 $2.94 $2.72 $2.62 $3.06 $2.72

2016 $3.61 $3.48 $3.22 $3.10 $3.62 $3.22

2017 $3.76 $3.62 $3.35 $3.22 $3.77 $3.35

2018 $4.08 $3.93 $3.64 $3.50 $4.09 $3.64

2019 $4.19 $4.04 $3.74 $3.59 $4.20 $3.74

2020 $4.33 $4.17 $3.86 $3.71 $4.33 $3.86

2021 $4.46 $4.30 $3.98 $3.82 $4.47 $3.98

2022 $4.67 $4.50 $4.17 $4.01 $4.68 $4.17

2023 $4.91 $4.73 $4.38 $4.21 $4.92 $4.38

2024 $5.03 $4.84 $4.48 $4.31 $5.04 $4.48

2025 $5.15 $4.96 $4.59 $4.42 $5.16 $4.59

2026 $5.37 $5.18 $4.79 $4.61 $5.39 $4.79

2027 $5.40 $5.20 $4.81 $4.63 $5.41 $4.81

2028 $5.55 $5.35 $4.95 $4.76 $5.56 $4.95

2029 $5.60 $5.39 $4.99 $4.80 $5.61 $4.99

2030 $5.70 $5.49 $5.08 $4.88 $5.71 $5.08

2031 $5.84 $5.63 $5.21 $5.01 $5.85 $5.21

2032 $5.89 $5.67 $5.25 $5.05 $5.90 $5.25

2033 $6.13 $5.91 $5.47 $5.26 $6.14 $5.47

2034 $6.38 $6.14 $5.69 $5.47 $6.39 $5.69

2035 $6.56 $6.32 $5.86 $5.63 $6.58 $5.86

2036 $6.93 $6.68 $6.18 $5.94 $6.95 $6.18

2037 $7.28 $7.01 $6.49 $6.24 $7.29 $6.49

2038 $7.65 $7.37 $6.83 $6.56 $7.67 $6.83

2039 $7.79 $7.50 $6.95 $6.68 $7.81 $6.95

2040 $8.01 $7.71 $7.14 $6.86 $8.02 $7.14

2041 $8.33 $8.02 $7.43 $7.14 $8.35 $7.43

2042 $8.67 $8.35 $7.73 $7.43 $8.69 $7.73

2043 $9.02 $8.69 $8.04 $7.73 $9.04 $8.04

2044 $9.38 $9.04 $8.37 $8.05 $9.40 $8.37

2045 $9.76 $9.40 $8.71 $8.37 $9.78 $8.71

2046 $10.16 $9.79 $9.06 $8.71 $10.18 $9.06

2047 $10.57 $10.18 $9.43 $9.06 $10.59 $9.43

2048 $11.00 $10.59 $9.81 $9.43 $11.02 $9.81

2049 $11.44 $11.02 $10.21 $9.81 $11.47 $10.21

2050 $11.91 $11.47 $10.62 $10.21 $11.93 $10.62

Source: U.S. EPA Analysis, 2013; U.S. DOE, 2011a; U.S. DOE, 2012c; U.S. DOE, 2012a; and U.S. DOE, 2012b

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:
August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 44

 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 45

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