United States

Environmental Protection Agency



# Economic Analysis for Existing and New Projects in the Coal b ed M ethane
I ndustry

EPA 820

- R

- 13

- 006
July 29, 2013J uly 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 Treat ment 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

................................ ................................ ................................ ............................. 38J uly 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

................................ ................................ ................................ ................................ .................. 45J uly 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 Character istics a

................................ ................................ ................................ ..... 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 Production a,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 Rate a

................................ ................................ ................................ ................................ ........ 30

Table 4

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

................................ ................................ ................................ ................................ ............................ 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%)

............ 43J uly 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 Q uestionnaire 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 announce ment 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 i ndustry as of 2008, i.e., the year for which the CBM s urvey collected detailed data. I n 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 p roject economics (post

requirements analysis). EPA performed a similar analysis to assess current and future economic conditions for new CBM projects 1 , and to evaluate whether new regulations would constitute a barrier to entry for new projects.

This docu ment 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 develop ed projections of natural

- ga s 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.J uly 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

t rapped 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 whic h 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 sea m 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 sin gle 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 i n 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 , 2013 a ) 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

declin ed since 2008, production of shale gas increased signif icantly 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 price s for 2000 through 2012

, and EIA

- projected price s 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 locate d near Louisiana are Table 1

- 1

. Total CBM Gas Production (Million Cubic Feet), 2007

– 2011

Industry 2007 2008 2009 2010 2011 a

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

. S ource: U.S. DOE

, 2013aJ uly 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)201 2b

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 waste water 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 analys is, EPA classified w astewater 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

– I nclude s t he 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, o perators may manage the produced water f rom a single project by both discharge and zero

discharge methods, either applied separately or in combination for the same project.J uly 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 the se 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 th e 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 fac e no incremental cost. EPA expects changes to industry economics due to declining gas prices to have a similar effect on all CBM projects

, both discharging projects and those that use zero

- discharge methods for managing produced water (both in discharging

basins and non

- discharging basins). Drilling costs, gas production costs, and available produced water

management methods and costs vary by basin; therefore, the overall financial impact of reduced gas prices will also vary by basin. Because surface water discharge generally does not require transport of the produced water, it entails lower private costs of disposal than zero

- discharge methods. Because of the

genera lly higher costs for using zero

- discharge methods for produced water discharge, EPA expects t hat declining gas prices will have a similar adverse effec t on the economics of CBM projects that use zero

discharge methods for managing produced water (both in discharging basins and non

- discharging basins)

, to the effect estimated for discharging projec ts

.J uly 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 a nd 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 des cription of these data sources. Additional information can be found in the Detailed Study Report and Technical Development Document

.

2.1.1 CBM Survey

In 200 9

, EPA distributed a Screener Questionnaire to all CBM operators that had three or more CBM

wells with p roduction 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 op erated; 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 th e 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 industr y during this one

year period. The one

- year 2008 snapshot contains information for projects at various production stages.

EPA distributed the Detailed Questionnaire to all CBM projects that discharged except for some projects

in the Powder River Basin. Bec ause 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 th e 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/ ).J uly 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 :

 C olorado (Raton Basin)

 Wyoming (Powder River and Green River Basins )

 Pennsylvania (Appalachian Basin)

 West Virginia (Appalachian Basin)

 Alabama (Black Warrior and Cahaba Basins)

 Monta na (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 u sed 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

- discharg e projects based on the data received through the CBM survey for 2008 2

. 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 deter mine 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

- discharg e projec ts, the produced water volume generated, and the produced water volume discharged directly to surface water s

. As described in Section

3

, EPA analyz ed 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 fo r 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. E PA reviewed information on operators in the six basins with data ( Appalachian, Black Warrior, Cahaba, Green River, Powder River , and Raton ) to determine whether: (1) t he operator was still producing CBM and (2) t he operator was still producing water

. EPA did not review information for operators in the Illinois Basin because the State of Illinois provides little informa tion 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 lo nger 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 Be tween 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 f

urther analysis.J uly 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 b ecause 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 prod uced water management method for calendar year 2008 using data collected through the CBM s urvey

. Table 2

- 1 shows the Detailed Questionnaire data

eleme nts 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. Pr oject 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

– Gro ss revenue for gas sold
minus r oyalties (mineral rights own er share of production revenue), s everance taxes (sta te share of production revenue), and a d valorem taxes (local/coun ty 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

G as production operating and maintenance (O&M) costs

. 2008 total gas production O&M

costs Question B3

- 50

P rod uced 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 estima ted 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

p ercentage 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 basi n us ing 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 thes e 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, b ecause future project revenue depend s on future gas price s , EPA developed gas

- price projections to use in the economic analysis

. Appendix A provides additional information on these projections

. As describe d 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 meth odology and findings.J uly 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 futur e 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 tha t 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 c hallenges 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 pr ovides 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. E PA did not have information to develop model projects for the Illinois b asin. Because t he Illinois b asin 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 s imilar 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 fo r 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. The s e assumption s are based on best professional judgment

. Section 3.3 o f 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 drillin g 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 development 3 of proj ects 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 Mode l 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) u sing 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 sam e 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.J uly 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 9

through the Detailed Questionnaire only

. EPA develop ed secondary models for three basins − the Appalachian (APP2), Black Warrior (BW2) and Pow d er River (PRB2)

– u sing 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 ge ology 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 informat ion was not available from public data sources for the basin, EPA used the Detailed Questionnaire average to supplement the secondary model project scenario. Table 2

- 3 shows the range of input parameter values
used in the new projects analysis. EPA used basin

- specific values for each model project in the new

source analysis ; however, b ecause 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 range s across all five basins for both the primary and secondary model project scenarios. Table 2

- 3 a lso 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

2.2.1 and the gas price projections described in Appendix A to analyze the potential effects of wastewater management technology costs on new s ources. Section 4 describes the new

- source analysis , including analysis methodology and findings

.

Table 2

- 3 . Model Project Characteristics a

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 ($/bb l 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 cost b ($/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.J uly 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 10



### 2.3 Wastewater Management Technolog ies Considered

The Clean Water Act provides for development of different levels of pollutant control for existing and

new sou rces , 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 eliminate s all discharges to surface water and is currently used for CBM produced

waste water disposal in the majority of basins

. Table 2

- 4 presents the IX costs for TDS removal p rior 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 differe nt 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 techno logies 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

. Wastew ater 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 addition al information ( http://water.epa.gov/scitech/wastetech/guide/index.cfm ).J uly 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 11



## 3 Economic Analysis

- Existing Sources

As described earl ier, 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 o f analyzed existing

CBM project s in two steps :

 First , EPA assess ed 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 c urrent 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

- requirement s 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 li fe of a project back to the present

. Accounting for future natu ral 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. P rojects that appear to

have unfavorable economics in t he near ter m 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 h ave 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. T hese assumpti ons

are inherently subject to uncertainty ; nevertheless, EPA believes that th is 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 economical ly viable

, given

estimated future CBM gas production, natural gas wellhead prices, and production costs ?

 Post

- requirement

s analysis : For project s assessed as economically viable in the baseline, would

the y remain viable considering the change in project economics in the face of wastewater discharge requiremen ts

– looking over the potential life of the project ? W ould 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 anal ys is involved fewer assumptions about future production, costs, and prices than the multiple

- year, projection

- based analysis, but does not account for expected increases in natural gas prices. Accordingly, EPA judges this single

year analysis not to be as analytically sound as the multiple

- year, projection

- based analysis. Nevertheless,J uly 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 assess es the baseline economics of existing projects and identifies those projects that are either :

 Not economic ally 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

- requirement s analysis

.  Economic ally viable before consideration of the wastewater discharge requirements , when

viewed over their potential production life

. EPA retained these projects in the subsequent post

requirement s 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 Warr ior

, Cahaba

, Green River

, Illinois

, Powder , and Raton

– using 2008 as the base analysis year. 5 As described earlier in this document,

b ecause 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, t h is 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 singl e

- 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

- requirement s analysis . EPA assessed projects with positive 2008 pre

- tax operating

income as baseline pas ses and carried them forward for the post

- requirement s 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 the y 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 foll ows :

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 a re 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

- i ncome 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.J uly 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)

q uantity 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 t he 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 ass essed the project as a n immediate b aseline 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 waste water discharge requirements in terms of lost production yea rs and gas produced. EPA carried these projects forward to the post

- requirements analysis ( Section 3.2 )

. EPA conducted this analysis as follows:

 Def ining 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 rate s by basin

. Table 2

- 2 shows the eastern and western U.S. average g as and water decline data. As described in Section 2.2.1

, EPA provides

8 This analysis does not account for the prev ious 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 p roject. 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 t ax 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 wo uld 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 p erformed 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 (2 9 percent) provided this information.J uly 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.
 P rojecting amoun t 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 )

.  P rojecting 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)

a fter 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 product ion 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 200 8 (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) publi shed by EIA

. To reflect the uncertainty in price projections, EPA considered three price growth cases in th is 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 f

ollows:

 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 t echnically 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 m ay 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.J uly 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 w ellhead 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 t ax payment s 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 r ate . 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 year s 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

 P roduced W

ater M anagement S

ystem (PWMS) O&M costs : For this analysis, EPA

ass umed that P WMS 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 calcu lated 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 percentage 18 by (2) 2008 total gas production O&M costs. 19 EPA assumed that fixed O&M cost would remain constant in subsequen t 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 year s , 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 mana gement costs will increase, it is equally possible that improvement in gas

extraction and water

- management technology will lower those costs, again after adjusting for general inflation. Because EPA had no basis for estimating the direction or magnitude of these changes, the Agency assumed that these costs would

remain constant on an inflation

- adjusted basis.

17 To the extent that PWMS O&M costs include a fixed component, the PWMS O&M costs estimated after 2008 would be

underestimated.

18 The share of O&M costs that would continue during a temporary shutdown of the project, as reported in the CBM survey.

19 For one project, percentage of 2008 fixed O&M costs is not reported; consequently, for this project EPA used average percentage estimated for the basin where this project is located, based on percentages reported for other projects in that

basin.J uly 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 year

by

- year basis as described above, on an as

- incurred basis , with production continuing for as long as 35 years. EPA assumed that project d evelopers 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 great er , before the operator know s production per well, how many wells will be drill ed , production costs, and resource/water mix,

etc. However , as project s 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 stag e

- specific rates for analyzing

indi vidual 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 f rom 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 c ost 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, i t 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 t he first analysis year, 2008) in the baseline regardless of the gas

- price case o r 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 flow s and declining NPV. Howeve r, 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 t he minimum rate of return on a pr oject or investment re quired 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 investme nt 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 i mmediate 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.,J uly 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

. F or 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 b ut 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 the s e projects as baseline pass es relative to the 2008 analysis year,

EPA kep t 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 t o losses in natural gas production.



### 3.2 Post

- Requirement s 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 th e post

- requirements analysis for the remaining 112 projects using the same methodology as described in Section 3.1

. For this analysis , EPA adjusted th e 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 a n 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, f or each of the

post

- requirements pass projects , the Agency compared the maximum

- NPV year in the post

- requirement s 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 small er 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) t he change in total CBM gas production

between baseline and post

- requirement s cases, (2) the change in the number of project

- years , and (3) average number o f 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 (5 5 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 proj ect. 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 thou gh NPVJ uly 29, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 18

3.2.2 Post

- Requirement s Analysis Results

Immediate Project Closures

EPA found the same number of projects to be immediate post

- requirement s 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 immediate ly. Given t he relatively

small losses in product ion years and gas quantity , this mean s 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 a re not sufficient to support future production

.

Production Years Lost at Remaining Projects

With IX treatment, EPA estimates that some o f 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 estimate s that 29 to 37 projects would shu t 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 per cent of the total baseline gas quantity )

. The losses

in project

- year s 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 opera ting margin for absorbing treatment technology costs, and thus greater potential for adverse impact.

With UI disposal

, some of the remaining 82 projects that EPA did not assess as immediate post

requirement s closure s also stop production earlier due to disposal requirements . T he t otal 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.J uly 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 4 4 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 t hese projects would lose

, on average, between 15 and 17 years of gas production , resulting in a total gas loss of between 1, 691 and 1,85 3 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 Production a ,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 Hig h Price Growth Case
Due to Immediate Project Closures e 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/Pro ject 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 Pr oduction 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

- Y ears 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 Proj ects 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 Closures e

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

- Y ears 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/Pro ject 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 Pr oduction 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

- Y ears 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 Proj ects 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 Closures e

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

- Y ears 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 Proj ects 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 Pr oduction 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

- Y ears 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 Proj ects 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/Pro ject 12 64.2% 11 80.3% 11 59.6% 11 76.3% 18 91.4% 15 107.5% f 18 91.4% 15 107.5% fAugust 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 differen ces in the baseline values against which the percent

- change values are calculated. The differences in baseline valu es result from the change in p roject econo mics, 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 p rojects. Source: U.S. EPA Analysis, 2013Augu st 6, 2013 Economic Analysi s 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 under

estimation of impacts. Key uncertainties and limitations for the economic analysis 26 include :

 The analysis does not account for the previous o utlays 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 pr opensity for earlier project termination.

 The analysis uses generic basin

- le vel gas and water decline rates, which may differ from project

specific decline rates

. This divergence may over

- or under

- state the impact of wastewater discharge requirements.

 The actual gas prices received by each project may differ from those estimated for and used in this analysis, which may over

- or under

- state the impact of wastewater discharge requirements.

 This analysis does not account for the possibility of additional wells being drilled at existing projects, which may over

- or under

- state the impact of wastewater discharge requirements. It is possible that additional wells would have improved project economics , depending on the productivity of those wells

.  This analysis does not include CBM projects that may have beg u n 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 t echnically recoverable

gas reserves or remain ing proved reserves

, but use information on production at 2008 (as reported in survey responses) together with basin

- specific decline rates, to estimat e 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 w astewater 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 pas t experience has shown that costs for technologies s u ch 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 gen eral

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 t he Technical Development Document for the Coalbed Methane Extraction Industry (DCN CBM00669 ) for additional details and assumptions regarding ion exchange and underground injection.Augu st 6, 2013 Economic Analysi s 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 Q uestionnaire obtained data at the project level, EPA conducted the new

- source analysis at the level of the project. For th e 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 waste water management techn ology 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 analy sis ( 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, m ost 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 gener ally 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 increas e 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) . Th is analysis looked at the potential for treatment technology and dis posal 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

– consti tute 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 (baselin e) and post

treatment, i.e., accounting for wastewater treatment and disposal costs, (post

- requirements) cases:

 Baseline analysis :

 Independent of potential wastewater discharge requirements , what initial price level is needed to achieve economically viabl e 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 CB M projects after imposition of ELG requirements ?

27 Given the uncertainty in future natural gas prices, EPA used alternativ e projections of wellhead gas prices to assess how CBM project economics would change over time (see Appendix A )

.Augu st 6, 2013 Economic Analysi s 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 develo pment 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 require m ents on project delay and total gas production.

The elements of the economic analysis fo r 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 lev els, 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 d escribed 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 yea rs 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 flo ws 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 t ax rates and the applicability of certain tax provisions, based on the size of the producing entity.

 In general, projects generate negative cash flow in the ir early years, while development wells are still being drilled , and the cash outlay for these well s 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 develop ment 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 ce rtain 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

.Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 25

 Operating cash flow during the production years is defined as gross reven ue, 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

calcula ted 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 p roduction 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 year 29 ; 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 informat ion 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 exis ting CBM projects

. See the project profitability discussion

in Section 3.1.1

, for information o n 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 t o 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 price s 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

develo pment 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.Augu st 6, 2013 Economic Analysi s 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. According ly, 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 supp ort 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 acco unt 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 project ions 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 oppor tunities. 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 Rate s 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 find s the initial wellhead price that, when coupled with a given price path, would cause a given model project to be economical ly 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 begin ning 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 in cluding 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 decisi on 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 analysi s 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

.Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 27

particularly during the early project years when development wells are being drilled. The solut ion 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 p roject 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 re turn (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

- requirement s 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 treatmen t 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

- requirement s 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 fin dings :

 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 ret urn/hurdle rate case because of the additional information presented in the new sources analysis

– in particular, focusing on the delay in economical production year.Augu st 6, 2013 Economic Analysi s 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 o f 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 n ot economical at baseline only under the low price growth case. For the other model projects and price growth cases , the projects become viable wit hin 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 f

or 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 a n 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 cos ts 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

.Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 29

 The Powder River Basin secondary model project (PRB2) experiences a dditional delay of 14 to 20 years.

 The Raton basin model project experiences a dditional 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 numb er 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 product ion 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 t han 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 c ase, 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 occ urs 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 p ost

- 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 technolog y 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 mod el (APP1) project experien ces a dditional delay of 1 to 2

years; the secondary model project (APP2) experiences a dditional delay of 10 to 13 years.

 The Illinois basin model projects (ILL1 and ILL2) experience additional delays of 1 to 2 years.

 The Black War

rior/Cahaba basin primary model project (BW1, Cahaba1 ) experience s additional delays of 1 1 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) ex periences a dditional 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, t hese

effects are due to increase d 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.Augu st 6, 2013 Economic Analysi s 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 Rate a

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)

T he 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 th e 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 economica l at baseline.

Economical production years and delay beyond 2013 are as follows:Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 31

 The analysis indicates that the secondary Appalachian model project s (APP2) is currently

economical under all price cases

. Economical production years for the primary Appalac hian model project (APP1) are later, at 20 28 to 20 36 or a delay of 15 to 23 years beyond 2013.

 For the Illinois basin model projects (ILL1 and ILL2), the earliest production years are 20 30 to
20 37 , or a delay of 17 to 24 years beyond 2013.

 The analysis ind icates 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 20 1 6 to 20 18, or a delay of 3 to 5 years beyond 2013.

 For the Powder River Basin prim ary model project (PRB 1 ), the earliest production years are 20 41

to 20 4 5, 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 20 36 to 204 1 , or a delay of 23 to 28 years beyond 2013.

For the IX treatment technology option, the economical production year is addition ally delayed from zero years to a maximum of 2 3 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 prod uction 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 mo del projects (ILL1 and ILL2) experience no additional delay under the low price growth case and a n additional delay of one year under the reference and high price growth

cases.

 The Black Warrior/Cahaba basin model projects (BW1, BW2, Cahaba1, Cahaba2) expe rience no additional delay under the high price growth case, and additional delay s of 1 to 6 years under the reference and low price growth cases

.  The Powder River Basin primary model project (PRB1) experiences a n additional delay of 2 years, while the sec ondary model project (PRB2) experiences a dditional delay of 1 9 to 2 3 years.

 The Raton basin model project experiences a dditional 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 1 3 percen t.

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 2 4 years for projects that become economical before 2050. The model project additional delay effects are as follows:Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 32

 The Appalachian basin primary model (APP1) project experiences a dditional delay of 1 to 5 years; the secondary model project (APP2) experi ences a dditional 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 1 8 to 20 years; th e secondary model project (BW2, Cahaba2) experiences additional delays of 9 to 1 2 years.

 The Powder River Basin primary model project (PRB1) experiences a dditional delay of 2 to 3

years. The Powder River Basin secondary model project (PRB2) experiences a dd itional delay of

20 to 2 4 years.

 The Raton basin model project experiences additional delays of 3 to 4 years.

Also as described for the 17

- percent rate analysis, t he 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.Augu st 6, 2013 Economic Analysi s 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
Rate a

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 17,46 3 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 17,46 3 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 16,42 6 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 analysis 34 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 comp lexities 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 Ex traction Industry (DCN CBM00669 ) for additional details and assumptions regarding ion exchange and underground injection.Augu st 6, 2013 Economic Analysi s 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 provide s 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 re sult, 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

p roject 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 cost s 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.Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 3 5



## Conclusion

Overall, this analysis shows that based on the 2008 CBM survey dat a and a 2010 data review

, a large

fract ion 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 i n 2008 or were non

- operational by 2010. EPA expects that an additional 43 percent of the existing CBM projects reported in 2008 were shut down by 2012. The deteriorating economic viability of these projects results largely from declining natural gas prices since the time of the CBM survey.
For the analysis of the impact of wastewater discharge requirements on existing projects, EPA focused on

the 112 CBM projects that were found economically viable out of the 148 total projects given the 23

immediate baseline closures estimated through the 2008 assessment and 13 projects found non

operational in 2010 . Of these 112 CBM projects, EPA found that the wastewat er 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, 2 4 percent of the 112 projects estimated to be economically viable in the

baseline would shut down immediately, with an additional 26 to 3 3 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 thi s 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 indu stry 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

vi able 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 h igher natural gas price growth cases.

Accounting for costs of the wastewater discharge requireme nts 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 opt ion , using industry‟s indicated rate of return of 17 percent, most model projects experience a n 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 r eturn, 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 signif icant number of years for most projects, regardless of the natural gas growth cases or the financial return sought by CBM project developers.Augu st 6, 2013 Economic Analysi s of Treatment Technology Options for CBM Projects | pg 36

Overall, EPA found that applying wastewater discharge requirements would impose significant burdens

in terms of im mediate 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 fo r 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 regulati on 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 wastewa ter management approaches and/or associated costs , EPA may revisit this decision in future years.Augu st 6, 2013 Economic Analysi s 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 econo mics 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 C BM

survey

. 35 To estimate future revenue for existing projects, EPA began from the survey

- reported prices but needed estimates of how natural ga s prices would change over time to forecast project

specific prices beyond the survey

- reported values.

 For the ne w

- 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 ra te 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 bo th 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 dispos able 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 perc ent, 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 20 35.

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. EP A chose the high and low economic growth cases as providing reasonable upper and lower price growth cases for economic analys i s.
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.Augu st 6, 2013 Economic Analysi s 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 , 201 2c )

 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 201 3 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 Re lease 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 yea rs 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 se ctions 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 analy sis.

A.2.1 Existing

- Source Analysis

For the existing

- source analysis, EPA developed price projections, and associated estimates of year

- over

year changes in prices, by making the following adjustments to the AEO 2013 Early Release data:

1. Using AEO 2012 price pro jections (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 203 4 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.Augu st 6, 2013 Economic Analysi s 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

p rice 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 pro jections for the two alternative price growth

cases to be us ed 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 projection s developed for 2008 to 2040, calculate the annual price differentials between Henry Hub and wellhead prices for each of the pri ce 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 proje ct 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 20 42 ( 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.Augu st 6, 2013 Economic Analysi s 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 not ed above, EPA needed to perform the following adjustments to develop basin

- specific wellhead price paths for the new

- source analys i s:

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 ann ual wellhead prices by st ate, for 2010, to the CBM basins, and averaging the state

- level prices for each basin. 39 These prices provide the basin

- specific price values to which the profiles of price change, from the national

level price forecasts, are applie d 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 i n 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.Augu st 6, 2013 Economic Analysi s 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

, 201 2c ; U.S. DOE

, 2012a; and U.S. DOE

, 2012bAugu st 6, 2013 Economic Analysi s 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

, 201 2c ; U.S. DOE

, 2012a; and U.S. DOE

, 2012bAugu st 6, 2013 Economic Analysi s 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

, 201 2c ; 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:Augu st 6, 2013 Economic Analysi s 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 als o 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 avail able 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 Earl y 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 refle cting 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 Ear l y 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 Ear l y 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

exp ect 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

- spec ific projections for existing projects, EP A 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



## References

Constellation Energy Partners LLC‟s SEC Filing (2007) ( http://www.sec.gov/Archives/edgar/data/1362705/000119312508045648/d10k.htm ).

De Bruin, R.H., R.M. Lyman, R.W. Jones, and L.W. Cook. 2001. Coalbed Methane in Wyoming Information Pamphlet 7 (revised). Wyoming State Geological Survey. EPA

- HQ

- OW

- 2004

- 0032

- 1904, DCN 03070.

GeoMet, Inc‟s SEC Filing (2011) (http://www.sec.gov/Archives/ed gar/data/1352302/000119312512140602/d280036d10k.htm).

Ladlee, Jim. 2011. “ The Implications of Multi

- Well Pads in the Marcellus Shale .” Cornell ‟ s Research & Policy Brief Series. September. Available online at: http://devsoc.cals.cornell.edu/cals/devsoc/outr each/cardi/publications/loader.cfm?csModule=security/ getfile&PageID=1016988

. Lewis, Terry. 2004. Federal Government Leases Land in Alabama, Arkansas, Louisiana, Michigan, and Mississippi, for Oil and Gas Exploration. September 24. Available online at: http ://www.blm.gov/pgdata/etc/medialib/blm/es/og_sales.Par.2900.File.dat/PR_Oil&GasLeaseSept23 _04.pdf

. Office of Management and Budget (OMB). 2003. Circular A

- 4. September 17, 2003. Available electronically at: http://www.whitehouse.gov/omb/circulars_a004_a

- 4# b

. Petroleum Association of Wyoming. 2005. CBNG Water Management and Treatment Options in Wyoming ‟ s PRB. October. Available online at: http://deq.state.wy.us/wqd/wypdes_permitting/WYPDES_cbm/Pages/CBM_Watershed_Permitting/T ongue_PrairieDog_HangingWoman_Bad ger_Creek]/Tongue%20PHB%20Downloads/Meeting%202
%206

- 8

- 06/WSBP%20Water%20Mange%20Pres%206

- 06.pdf

. Summit Gas‟s SEC Filing (2009) ( http://www.summitgas.com/Docs/10_K_3_31_10.pdf ).

United States D epartment of Energy ( U.S. DOE ). 2002. “ Powder River Basin Coalbed Methane Development and Produced Water Study ” . November. Prepared by Advanced Resources International, Inc. (ARI). Available online at: http://www.fe.doe.gov/programs/oilgas/publications/coa lbed_methane/PowderRiverBasin2.pdf

. United States Department of Energy (U.S. DOE). 2010. "Oil and Gas Lease Equipment and Operating Costs 1994 Through 2009". September 28.

United States Department of Energy ( U.S. DOE) . 2011a. AEO 2011 National Energy Modeling System. Natural Gas Supply, Disposition, and Prices. Downloaded December, 4, 2012 from http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2011&subject=3

- AEO2011&table=13

- AEO2011®ion=0

- 0&cases=ref2011

- d020911a.

United States Department of Ener gy ( U.S. DOE) . 2012 a . AEO 2012 National Energy Modeling System. Natural Gas Supply, Disposition, and Prices. Downloaded November, 19, 2012 from http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=0

- AEO2012&table=13

- AEO2012®ion=0

- 0&cases=re f2012

- d020112c.August 6, 2013 Economic Analysis of Treatment Technology Options for CBM Projects | pg 46

United States Department of Energy ( U.S. DOE) . 2012 b . AEO 2013 National Energy Modeling System. Natural Gas Supply, Disposition, and Prices. Downloaded December, 4, 2012 from http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2013ER&subje ct=0

- AEO2013ER&table=13

- AEO2013ER®ion=0

- 0&cases=early2013

- d102312a.

United States Department of Energy (U.S. DOE) . 201 2c . Natural Gas Wellhead Price. Dow n

- loaded December 28, 2012 from http://www.eia.gov/dnav/ng/ng_pri_sum_a_EPG0_FWA_DMcf_a.htm. United States Department of Energy (U.S. DOE) . 201 3a. U.S. Natural Gas Gross Withdrawals and Production

. Downloaded March 1, 2013 from http://www.eia.gov/dnav/ng/ng_prod_sum_dcu_NUS_a.htm

United States Department of Energy (U.S. DOE) . 201 3b. U.S. Natural Gas Prices . Downloaded March 1,
2013 from http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm

U.S. EPA, 2009. Detailed Questionnaire for the Coalbed Methane Extraction Sector. October. EPA

- HQ

OW

- 2008

- 0517

- 0706 . downloadable from http://www.regulations.gov/#!documentDetail;D=EPA

HQ

- OW

- 2008

- 0517

- 0706

Vail, Bill and Matt Conrad (Marshall Miller and As sociates). 2003. Coalbed Methane Development, An Issues Overview. October 29. West Virginia Coal Bed Natural Gas Workshop . Roanoke, WV. Available online at: http://www.wvenergyroadmapworkshops.org/presentations/03Oct_Miller.pdf

.