Z 

United States

Environmental Protection

Agency

Coalbed Methane Extraction:

Detailed Study Report

 September 2011 
This page intentionally left blank. 
U.S. Environmental Protection Agency

Office of Water (4303T)

1200 Pennsylvania Avenue, NW

Washington, DC 20460

EPA-820-R-10-022

Coalbed Methane Extraction:Detailed Study Report December 2010

i

CONTENTS

Page 

1. EXECUTIVE SUMMARY/INTRODUCTION ............................................................................ 1-1

2. DATA COLLECTION ACTIVITIES ........................................................................................ 2-1

2.1 Stakeholder Outreach ........................................................................................... 2-1

2.2 Site Visits ............................................................................................................. 2-2

2.3 Data Collection to Identify the Affected Universe .............................................. 2-3

2.4 EPA CBM Industry Questionnaire ...................................................................... 2-3

2.4.1 Screener Questionnaire ............................................................................ 2-3

2.4.2 Detailed Questionnaire............................................................................. 2-4

2.5 Collection and Review of Current State and Federal NPDES Regulatory 

Requirements ....................................................................................................... 2-5

3. TECHNICAL AND ECONOMIC PROFILE OF THE CBM INDUSTRY ......................................... 3-1

3.1 CBM Gas Production ........................................................................................... 3-1

3.1.1 History of Production in the CBM Basins ............................................... 3-3

3.1.2 CBM Production ...................................................................................... 3-6

3.1.3 Potential for Development in New CBM Basins ..................................... 3-7

3.2 Produced Water Characteristics ........................................................................... 3-8

3.2.1 Volumes of Produced Water .................................................................... 3-8

3.2.2 Pollutants in Produced Water................................................................... 3-9

3.3 Management of Produced Water ....................................................................... 3-10

3.3.1 Discharge to Surface Water or POTW ................................................... 3-15

3.3.2 Zero Discharge (with No Beneficial Use) ............................................. 3-15

3.3.3 Zero Discharge (with Beneficial Use) ................................................... 3-17

3.4 Treatment Methods ............................................................................................ 3-18

3.4.1 Aeration .............................................................................................. 3-18

3.4.2 Sedimentation/Chemical Precipitation................................................... 3-19

3.4.3 Reverse Osmosis .................................................................................... 3-19

3.4.4 Ion Exchange ......................................................................................... 3-19

3.4.5 Electrodialysis ........................................................................................ 3-20

3.4.6 Thermal Distillation ............................................................................... 3-20

3.4.7 Multiple Technology Applications ........................................................ 3-20

3.5 Current Economics of CBM Production ............................................................ 3-21

3.5.1 Number of Wells and Projects ............................................................... 3-21

3.5.2 Financial Characteristics of CBM Projects ............................................ 3-23

3.5.3 Operators of CBM Projects .................................................................... 3-29

3.6 Trends and Projections ....................................................................................... 3-35

3.6.1 The Present and Future of CBM ............................................................ 3-35

3.6.2 Wellhead Gas Price Projections ............................................................. 3-37

3.6.3 Trends in Costs of Production................................................................ 3-38

3.6.4 The Future of Existing Basins................................................................ 3-40
Coalbed Methane Extraction:Detailed Study Report December 2010

CONTENTS (Continued)

Page 

ii

4. ENVIRONMENTAL ASSESSMENT CONSIDERATIONS ........................................................... 4-1

4.1 Documented Impacts From the Direct Discharge of CBM Produced Water ....... 4-2

4.2 Potential Environmental Impacts From the Direct Discharge of CBM 

Produced Water .................................................................................................... 4-5

4.3 Nonsurface Water Environmental Impacts Associated With CBM 

Produced Water .................................................................................................... 4-8

4.3.1 Land Application Impacts ........................................................................ 4-8

4.3.2 Impoundment Control Technology Impacts .......................................... 4-10

4.4 Assertions of No Environmental Impact Caused by CBM Produced Water ..... 4-11

5. REFERENCES ..................................................................................................................... 5-1

Appendix A SUMMARY OF PERMITTING PRACTICES AND REQUIREMENTS
Coalbed Methane Extraction:Detailed Study Report December 2010

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LIST OF TABLES

Page 

1-1 Currently Producing CBM Basins and Locations ............................................................ 1-1

2-1 Site Visit Numbers and Locations ................................................................................... 2-3

2-2 Common NPDES Permit Parameters and Limitations .................................................... 2-6

3-1 Characteristics of Major CBM Basins ............................................................................. 3-4

3-2 CBM Production by Basin in 2008 .................................................................................. 3-6

3-3 Prospective But Nonproducing CBM Resources ............................................................. 3-7

3-4 Volumes of CBM Produced Water Discharged to Surface Waters in the 

Discharging Basins (2008) ............................................................................................... 3-8

3-5 TDS Concentrations in CBM Produced Water by Basin ............................................... 3-10

3-6 Pollutant Concentrations in CBM Produced Water by Basin ........................................ 3-10

3-7 CBM Produced Water Management Practices Observed During Site Visits ................ 3-13

3-8 Number of Projects by Produced Water Management Practices Reported ................... 3-14

3-9 UIC Program: Well Classes and Description................................................................. 3-16

3-10 Wells and Projects by Discharging and Zero Discharge Basins .................................... 3-22

3-11 Characteristics of Discharging vs. Zero Discharge Projects .......................................... 3-23

3-12 2008 Wellhead Prices ($/Mcf) ....................................................................................... 3-24

3-13 2008 Estimated Gross Revenues ($millions) by Basin, Discharging Basins vs. 

Zero Discharge Basins ................................................................................................... 3-25

3-14 Estimated 2008 Gross Revenues ($millions) by Basin, Discharging Projects vs. 

Zero Discharge Projects ................................................................................................. 3-26

3-15 Assumptions Used in U.S. DOE EIA Cost Models for Four Key CBM Basins............ 3-28

3-16 Operating Costs and Costs of Equipment Assuming a 10-Well Lease in Four Key 

CBM Basins (2008) ....................................................................................................... 3-29

3-17 Number of CBM Operators by Size of Firm ................................................................. 3-30

3-18 Numbers of Operators by Discharge Status and Basin .................................................. 3-31

3-19 Key Financial Information for Publicly Held CBM Firms (2008) ................................ 3-32
Coalbed Methane Extraction:Detailed Study Report December 2010

LIST OF TABLES (Continued)

Page 

iv

3-20 Key Financial Ratios for Public CBM Firms Compared to the OGJ 150 (2008) .......... 3-34

3-21 Average Monthly U.S. Wellhead Price, 2008–2010...................................................... 3-38

3-22 Summary of Information Important to Future Production Trends in the Major 

Discharging Basins ........................................................................................................ 3-40

4-1 Summary of Literature Review Results by Search Category and Type of 

Environmental Impact ...................................................................................................... 4-1

4-2 Summary of Documented Impacts From the Direct Discharge of CBM Produced 

Water Cited in Peer-Reviewed Literature ........................................................................ 4-3

4-3 Scientific Studies Evaluating Potential Environmental Concerns From the Direct 

Discharge of CBM Produced Water ................................................................................ 4-6

4-4 Scientific Studies Evaluating Nonsurface Water Environmental Concerns 

Associated With Land Application of CBM Produced Water ......................................... 4-9

4-5 Scientific Studies Evaluating Nonsurface Water Environmental Concerns 

Associated With Control Technologies for CBM Produced Water ............................... 4-11
Coalbed Methane Extraction:Detailed Study Report December 2010

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LIST OF FIGURES

Page 

1-1 Locations of Currently Producing CBM Basins .............................................................. 1-2

3-1 Profile of a Typical Western CBM Well With Open Hole Completion (DeBruin, 

et al., 2001) ...................................................................................................................... 3-2

3-2 Diagram of Potential Path of Produced Water ............................................................... 3-11

3-3 Projections of Natural Gas Consumption and Supply ................................................... 3-36

3-4 Projections of Shares of Total Gas Production by Type ................................................ 3-36

3-5 Projections of Natural Gas Wellhead Price ................................................................... 3-37

3-6 Indices for Gas Equipment and Annual Operating Costs and Gas Prices in Real 

1976 Dollars ................................................................................................................... 3-39
Coalbed Methane Extraction:Detailed Study Report December 2010

1-1 

1. EXECUTIVE SUMMARY/INTRODUCTION

This report summarizes the information collected and analyzed by the U.S.

Environmental Protection Agency (EPA) as part of a study of the coalbed methane (CBM) 

extraction industry. Currently, CBM discharges are not covered by an Effluent Limitation 

Guideline (ELG), but are regulated under Best Professional Judgment (BPJ) permits. 

CBM is a form of natural gas that is found in coal seams and is extracted by drilling wells 

into the coal seams. Unlike extraction of conventional natural gas, CBM extraction requires the 

removal of groundwater to reduce the pressure in the coal seam, which allows CBM to flow to 

the surface through the well. This water must be managed and, in several states, is sometimes 

permitted for discharge directly or indirectly (via a publicly owned treatment works [POTW]) to 

surface waters.

CBM is currently produced in 15 basins1 as shown in Table 1-1 (U.S. EPA, 2010a). 

Figure 1-1 illustrates the locations of these basins. The states in which direct or indirect 

discharges to surface waters are occurring are Alabama, Colorado, Illinois, Montana, 

Pennsylvania, West Virginia, Wyoming, and Virginia. 

Table 1-1. Currently Producing CBM Basins and Locations

Basin States

Appalachian Virginia a, West Virginia a, Pennsylvania a

Black Warrior Alabama a

Cahaba Alabama a

Greater Green River Wyoming a

Powder River Basin (PRB) Montana a, Wyoming a

Raton Colorado a, New Mexico

San Juan New Mexico

Uinta-Piceance Utah, Colorado

Anadarko Oklahoma

Arkoma Oklahoma, Arkansas

Cherokee/Forest City Kansas

Arkla Louisiana

Permian/Ft. Worth Texas

Illinois Illinois a, Indiana

Wind River Wyoming a

a – States that permit CBM produced water discharge to surface water or POTW.

 

1 Basins are defined as large regions underlain by coalbeds with known CBM resources.
Coalbed Methane Extraction:Detailed Study Report December 2010

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Figure 1-1. Locations of Currently Producing CBM Basins

EPA received comments during the 2005 annual review from citizens and environmental 

advocacy groups requesting development of a regulation. In 2005, EPA identified the CBM 

extraction industry as a candidate for a preliminary study (U.S. EPA, 2006). 

For the 2006 annual review, began EPA collecting data on the number of active basins

producing CBM and their produced water disposal practices. In 2007 EPA began a more detailed 

study of the CBM industry. EPA gathered additional information; including conducting 

numerous site visits to meet with stakeholders and observe a number of CBM produced water 

treatment technologies. 

For this detailed study, EPA used a three-pronged approach to collect additional data on 

this industry: (1) meetings with stakeholders, (2) site visits, and (3) industry surveys—a national 

screener survey and a statistically sampled detailed survey. 

EPA developed a technical and economic profile of the industry, which details 

information on CBM wastewater discharges, treatment technologies that are available to treat 

pollutants associated with CBM discharges (mostly total dissolved solids [TDS]), and the 

financial and economic characteristics of the industry. 

Using survey responses and other data, EPA evaluated the following: the quality and 

quantity of produced water generated from CBM extraction; the available management, storage, 

treatment, and disposal options; and the potential environmental impacts of surface discharges. 

The findings from this detailed study are described in this report and include: 
Coalbed Methane Extraction:Detailed Study Report December 2010

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• Approximately 45 percent of all produced water is discharged to waters of the 

United States.

• Various pollutants such as sodium, calcium, and magnesium (used to calculate the 

sodium adsorption ratio [SAR]), total suspended solids (TSS), and metals (e.g., 

selenium, chromium) are present in discharges. 

• Surface water discharges of produced water can increase stream volume, 

streambed erosion, suspended sediment, and salinity. 

• Pollutants from CBM discharges may negatively affect fish populations over 

time. 

• Surface impoundment and land application of produced waters may impact 

groundwater from infiltration and the concentration and/or bioaccumulation of 

CBM-associated pollutants. 

• Advanced water treatment options are being used in the field in some operations 

to remove pollutants in produced water. 

• Widely practiced zero discharge options may be available depending on well 

location. 

• Although the recent downturn in the economy has negatively impacted the CBM 

industry, projections going forward appear more optimistic, with higher prices for 

gas predicted over the longer term.
Coalbed Methane Extraction:Detailed Study Report December 2010

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2. DATA COLLECTION ACTIVITIES

EPA collected and evaluated information from numerous sources to support the 

development of the CBM Detailed Study. EPA used this data to develop an industry profile, 

characterize the wastewater and identify potential pollution control technologies, review the 

potential pollutant load reductions associated with certain treatment technologies, and review 

environmental impacts associated with discharges from this industry. This chapter discusses the 

following data collection activities: 

• Meetings with industry and stakeholders (Section 2.1);

• Site visits, including the site selection process and the information collected

(Section 2.2);

• Data collection to identify the universe of entities for a survey effort (Section 2.3);

• Industry survey activities, including a description of the questionnaires (Section 

2.4); and

• Collection and review of National Pollutant Discharge Elimination System 

(NPDES) permits (Section 2.5).

Other data examined in this study include information from wastewater treatment 

equipment vendors, the U.S. Geological Survey (USGS), and literature and Internet searches on 

CBM processes, technologies, wastewaters, pollutants, and regulation. In addition, EPA 

considered information provided in public comments during the effluent guidelines planning 

process, as well as other contacts with interested stakeholders. EPA also used publicly available 

information from the U.S. Department of Energy’s (U.S. DOE’s) Energy Information 

Administration (EIA), various state oil and gas commission websites, Securities and Exchange 

Commission (SEC) filings by publicly held firms identified as producing CBM, the Oil & Gas 

Journal, and other information as cited in Chapter 3. 

2.1

For this detailed study, EPA conducted extensive stakeholder outreach in addition to an 

expansive site visit program to help identify key issues and concerns of industry and other 

stakeholders. The outreach goals for the detailed study included: (1) collecting information from 

stakeholders; (2) explaining the purpose for an industry survey and the process for approval and 

implementation of the survey; and (3) identifying and resolving issues as early as possible. This 

outreach helped facilitate the development of the questionnaire as comments and suggestions 

from industry and other stakeholders were incorporated into the survey design. 

Stakeholder Outreach

EPA met with a range of stakeholders (e.g., industry representatives; federal, state, and 

tribal representatives; public interest groups and landowners; and water treatment experts) to 

obtain the best available information on the industry and its CBM produced water management 

practices.

To initiate stakeholder involvement, EPA conducted seven teleconferences and 13 

meetings in Washington, D.C. during 2007. Meeting participants included representatives from 

EPA and other federal, state, and tribal agencies (e.g., DOE, USGS, the U.S. Forest Service, and 

the U.S. Department of Interior); representatives from the affected industry; members of public 

interest groups; and CBM treatment experts. EPA posted the briefing slides for the 
Coalbed Methane Extraction:Detailed Study Report December 2010

2-2 

teleconferences on its project website and drafted and shared meeting minutes with participants 

prior to finalizing them; these minutes are available in the public docket. 2

EPA also conducted 23 meetings outside Washington, D.C. in Alabama, West Virginia, 

Pennsylvania, Montana, Wyoming, Colorado, New Mexico, and Texas. Meeting participants 

included a broad range of stakeholders. These meetings were coordinated with site visits to CBM 

operations (see Section 

 

2.2). 

The meetings solicited early feedback from participants to facilitate the development of 

the first draft of the survey instrument and sample design. They also identified interested 

stakeholders for the site visits and meetings outside Washington, D.C. (see below). During these 

meetings, EPA provided information on the following topics: 

• The EPA regulatory development process; 

• An initial review of the CBM sector; 

• The CBM Questionnaire; and 

• The schedule and next steps. 

2.2

EPA visited six CBM basins in eight states to gather data for the CBM Detailed Study 

and the questionnaire. In total, EPA visited 33 sites in different locations within these six CBM 

basins. 

Site Visits 

During each site visit, EPA collected general site information (e.g., location, operator 

name, field name, pooling arrangements, and well spacing); produced water beneficial use and 

disposal methods; treatment methods; and economic information such as descriptions of factors 

affecting decisions to begin production or shut in (cease production from) a well or lease. 

Information collected during each site visit is documented in a report, which is available in the 

public docket (EPA-HQ-OW-2006-0771 and EPA-HQ-OW-2008-0517). Confidential Business 

Information (CBI) in these site visit reports has been redacted from the public versions of the 

reports in the docket. 

Table 2-1 shows the basins in which EPA conducted site visits and the number of 

individual visits made. 

 

2

See DCNs 5177–5182 and 5184 in the docket (EPA-HQ-OW-2006-0771) for meeting documentation. 
Coalbed Methane Extraction:Detailed Study Report December 2010

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Table 2-1. Site Visit Numbers and Locations

Basin States Number of Visits

Appalachian Virginia, West Virginia, Pennsylvania 6

Black Warrior Alabama 1

Green River Wyoming 3

Powder River Montana, Wyoming 17

Raton Colorado, New Mexico 3

San Juan New Mexico 3

Total Visits 33

2.3

EPA licensed database information on historic well production from HPDI, Inc.

Data Collection to Identify the Affected Universe

3

EPA compiled the data into a database that provided information on state, basin, operator 

name, operator's well name and number, unique well identifier (American Petroleum Institute 

[API] number), field, reservoir, and various location and contact information, along with 2006 

gas and water production, where available, for all operators of CBM wells in the United States 

(ERG, 2008). These data formed the basis for compiling the list of respondents for EPA’s survey 

efforts, described in the sections below. 

(a firm 

that compiles information from nearly all of the oil and gas producing states) to get an initial list 

of operator names and their associated gas production and number of wells. EPA supplemented 

these data with well and production data from Indiana and Illinois, states for which HPDI does 

not provide data. EPA also used data from West Virginia and Virginia to identify which wells in 

those states were CBM wells, as well as updated information from West Virginia (WVDEP) on 

gas production in that state. 

2.4

EPA collected data using two instruments: a screener questionnaire and a detailed 

questionnaire. The screener questionnaire focused on identifying CBM projects, which are the 

critical business units within the CBM industry that cannot be identified using publicly available 

information. A project is defined 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. The 

detailed questionnaire focused on obtaining detailed data at the project level. EPA received 

approval for the Coalbed Methane Extraction Sector Survey on February 18, 2009, from the 

Office of Management and Budget (OMB Control No. 2040-0279). 

EPA CBM Industry Questionnaire 

2.4.1 Screener Questionnaire 

EPA used a screener survey to ensure that it had the appropriate contact information for 

CBM operators that were identified in the data collection effort described in Section 0 and to 

provide sufficient information to stratify and select a sample of operators and projects for the 

detailed questionnaire. Establishments operating in more than one basin and/or state received a 

 

3 Use of HDPI, Inc. name should not be construed as an endorsement from EPA.
Coalbed Methane Extraction:Detailed Study Report December 2010

2-4 

survey for each of the basins and/or states in which they operated. EPA sent the screener 

questionnaire in February 2009 to all CBM operators that had three or more producing CBM 

wells in 2006. To reduce respondent burden, EPA completed the screeners for operators 

identified with only one or two wells, using public data from states and from contacts with those 

operators in basins where surface water discharges are permitted. The screener survey database 

was completed in July 2009. 

2.4.1.1 Description of the Screener Questionnaire

The screener survey (U.S. EPA, 2010a) requested the following information: verification 

that the operator produced CBM in 2008, identification of small businesses and number of 

projects operated, and, for each project, information on numbers of wells, gas production, and 

produced water management methods. 

2.4.1.2 Response, Review, and Follow-up

EPA provided support to recipients in completing the screener surveys through an e-mail 

helpline and a toll-free telephone helpline. EPA personnel responded to e-mails and phone calls 

to answer questions about the instructions, standard terminology, and procedures for completing 

the survey, and respond to requests for guidance on the technical information requested in the 

survey. Additional details of how the data were updated to reflect later determinations of out-ofscope operations and the steps taken to protect CBI when reporting summary data in this report 

are presented in a memorandum, which is located in the administrative record (ERG, 2010). 

2.4.2 Detailed Questionnaire

EPA began distributing the detailed questionnaire to the representative sample of CBM 

projects in late October 2009. The detailed questionnaire collects financial and technical data on 

more than 200 CBM projects across the country (Battelle, 2009). 

2.4.2.1 Sample Selection

EPA is aware that the economics and environmental impacts of CBM production depend 

greatly on the location of CBM development and the surrounding ecosystem. The Agency 

considered location of CBM operations during the selection of projects to be surveyed. Using a 

sample frame of 773 projects (based on the screener survey responses), EPA selected over 200 

CBM projects to receive detailed questionnaires. EPA selected the projects for sampling by 

basin, project size (number of wells), and discharge method (i.e., direct or indirect discharge and 

zero discharge). Within each sampled stratum, EPA targeted 30 percent of the projects for 

sampling.

4

Generally, EPA focused on basins where screener respondents reported surface water 

discharges (located in the eight states noted in Table 1-1). EPA also focused on emerging zero 

discharge basins, which were considered likely to provide information on the types of projects 

that might be constructed in basins yet to be developed. These zero discharge basins included 

 

4 Additional details on the sampling process design are documented in an October 19, 2009, memorandum (Battelle, 

2009), which is considered CBI because it reveals numbers of projects by basin and state. These totals could be used 

to back-calculate numbers of projects reported by respondents requesting that this information be handled as CBI. 
Coalbed Methane Extraction:Detailed Study Report December 2010

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Wind River, Arkla, Permian/Fort Worth, and Uinta-Piceance, each of which had relatively few 

projects, thereby requiring a census. The only stratified sampling performed was among zero 

discharge projects in the Wyoming portion of the Powder River Basin. EPA did not send detailed 

questionnaires to projects and operators in established basins that discharge no produced water 

directly or indirectly to surface water (Anadarko, Arkoma, and Cherokee/Forest City) because 

their well-developed infrastructure was not helpful for modeling conditions in newly emerging 

basins. The San Juan basin is a well-developed basin that received questionnaires because EPA 

anticipates that the San Juan basin will serve to model the emerging Black Mesa basin. 

2.4.2.2 Description

The detailed questionnaire requests both technical and financial and economic data, 

including the following information: 

• General information on the operator and parent company; 

• Produced water volumes, water quality, and treatment, reuse, and disposal 

methods; 

• Destination of CBM produced water; 

• Produced water treatment methods, including system design, operating, and cost 

information; 

• Environmental impact on receiving waters;

• Pollutant monitoring;

• Firm-level financial information; and

• Project-level financial information. 

EPA used data from this survey to calculate the quality and quantity of produced waters 

from the CBM industry and determine means of discharge, treatment technology in place, and 

geographic location. 

2.4.2.3 Questionnaire Response and Review and Follow-up

EPA prepared an electronic version of the detailed questionnaire to minimize operator 

burden and improve data quality and operated voicemail and e-mail helplines to support 

recipients in completing the questionnaires. Additionally, EPA began conducting follow-up 

activities to ensure completeness and accuracy of the questionnaire responses.

2.5

This section summarizes the current NPDES permits in key states. As noted in the 

executive summary, eight states allow produced water to be directly or indirectly discharged to 

surface water. EPA checked with six of these states to see if permits could be obtained for review 

and was able to review permits from four of these states’. EPA’s review focused on determining 

common pollutants.

Collection and Review of Current State and Federal NPDES Regulatory 

Requirements

5

 

5 EPA did not study the permits from Illinois, Pennsylvania, Virginia, and West Virginia in detail for the following 

reasons. One direct discharger was identified in Illinois, but this state has very little CBM activity compared to the 

other states studied. Pennsylvania permits were not available for review. One indirect discharger was identified in 

Virginia, although it is not clear from the screener survey whether the indirect discharge was occurring in Virginia, 

 
Coalbed Methane Extraction:Detailed Study Report December 2010

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Initially, EPA obtained information on CBM permitting requirements via Internet 

searches and discussions with state permitting officials from the six major direct discharging 

states: Alabama, Colorado, Montana, Pennsylvania, West Virginia, and Wyoming. The Agency 

reviewed general and individual state NPDES permits for CBM produced water discharges in

four states with information on monitoring requirements and discharge limitations. Overall, EPA 

determined that states use a combination of general, individual, and watershed-based permits to 

regulate CBM discharges to surface waters. Individual permits were issued more frequently than 

the other permit types, and Wyoming is the only state actively using watershed-based permits for 

CBM discharges. 

EPA identified some common discharge and monitoring requirements across the different 

permitting programs. The most frequently regulated parameters include pH, chloride, TSS, 

Sodium Absorption Ratio (SAR),6

Table 2-2

 oil and grease, and metals (e.g., iron and manganese). Several 

states require continuous monitoring of effluent flow, conductivity, and pH. Three states, 

Alabama, Wyoming, and Montana, include receiving stream monitoring requirements in addition 

to effluent monitoring. lists the parameters commonly regulated in CBM produced 

water NPDES permits. In addition to those parameters listed in Table 2-2, Alabama, Colorado, 

and Wyoming also require whole effluent toxicity (WET) testing of effluent.

Table 2-2. Common NPDES Permit Parameters and Limitations

State

Number 

of Active 

Permits Parameter Unit

Daily

Minimum

Daily 

Maximum

Monthly 

Average

Alabama 24 Chloride mg/L NA 230 NA

Oil and Grease mg/L NA 15 NA

pH s.u. 6 9 NA

Total Iron mg/L NA 6 3

Total Manganese mg/L NA 4 2

Colorado 1 general 

permit 

covering 

about 20 

facilities

Chloride mg/L NA NA 250

Oil and Grease mg/L NA 10 NA

pH s.u. 6.5 9 NA

TSS mg/L NA NA 30

Montana a 3 Oil and Grease mg/L NA 10 NA

pH s.u. 6.5 9 NA

SAR NA Mar–Oct:

2.6–4.5

Nov–Feb:

6.6–7.5

Mar–Oct:

1.3–3.0

Nov–Feb:

3.3–5.0

 

West Virginia, or both states, and Virginia has no direct discharges to surface waters. West Virginia direct discharge 

permits were not yet active at the time of the study.

6 SAR is the ratio of sodium concentrations to calcium and magnesium concentrations in water. This ratio 

characterizes the relative sodicity of water. That is, it measures the relative amount of Na+ ions compared with other 

ions in water, which is significant because sodium may affect vegetation and soil characteristics. Section 4 provides 

further discussion of the potential impacts from elevated SAR.
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Table 2-2. Common NPDES Permit Parameters and Limitations

State

Number 

of Active 

Permits Parameter Unit

Daily

Minimum

Daily 

Maximum

Monthly 

Average

TSS mg/L NA 30–40 17–25

Total Recoverable Cadmium μg/L NA 0.48 0.054

Total Recoverable Fluoride mg/L NA NA 0.5

Total Recoverable Iron mg/L NA NA 0.6

Total Recoverable Selenium μg/L NA 3 0.75

Wyoming About 

800

Chloride mg/L NA 50–2000 NA

Dissolved Iron μg/L NA 74–1000 NA

Dissolved Manganese mg/L NA 50 NA

pH s.u. 6.5 9 NA

SAR NA 1–13

SAR < 7.10 × 

EC – 2.48

NA

TDS mg/L NA 300–5000 NA

a – At the time this report was written, Montana was evaluating how to implement technology-based limits on CBM 

discharges.

NA – Not applicable.

Appendix A summarizes the permitting practices and requirements for each of the six 

states reviewed.
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3. TECHNICAL AND ECONOMIC PROFILE OF THE CBM INDUSTRY

This profile covers both the technical aspects of CBM extraction and produced water 

production and the economic and financial characteristics of the industry. Section 3.1 describes 

CBM gas production and also presents the volumes of gas produced. Section 3.2 presents the 

volumes and quality of water produced during CBM extraction. Section 3.3 discusses the various 

methods for managing produced water and discusses the pollutants in produced water discharges. 

Section 3.4 summarizes various treatment technologies that might be used to reduce pollutants, 

and Section 3.5 discusses the current economics of the CBM industry, including counts of 

operators, numbers of wells, numbers of projects, estimates of revenues generated by those 

projects, and the financial conditions of publicly held firms in the industry. Section 3.6 discusses 

trends in key factors affecting the future economics of CBM production. 

3.1

Coalification, the geologic process that progressively converts plant material to coal, 

generates large quantities of natural gas, which are subsequently stored in the coal seams. The 

increased pressures from water in the coal seams force the natural gas to adsorb to the coal. The 

natural gas consists of approximately 96 percent methane, 3.5 percent nitrogen, and trace 

amounts of carbon dioxide (U.S. EPA, 2004a). This natural gas contained in and removed from 

the coal seams is called coalbed methane or CBM. (U.S. DOE, 2006) 

CBM Gas Production

The amount of available methane in coal varies with coal’s hardness (the resistance to 

scratching). Level of hardness is known as “rank.” The softest coals (peats and lignites) are 

associated with high porosity, high water content, and biogenic methane. In higher-rank coals 

(bituminous), porosity, water, and biogenic methane production decreases, but the heat 

associated with the higher-rank coals breaks down the more complex organics to produce 

methane. The highest-rank anthracite coals are associated with low porosity, low water content, 

and little methane generation (ALL, 2003). The most sought-after coal formations for CBM 

development, therefore, tend to be mid-rank bituminous coals. Coal formations in the eastern 

United States tend to be higher-rank, with lower water content than western coal formations. 

They also tend to have more methane per ton of coal than western coal formations in the key 

basins, but can require fracturing to release the methane because of their low porosity (ALL, 

2003). 

Extraction of CBM requires drilling and pumping the water from the coal seam, which 

reduces the pressure and allows CBM to release from the coal (Wheaton et al., 2006; U.S. DOE, 

2006). CBM extraction often produces large amounts of water, as shown in Section 3.2. Methane 

and water are piped from individual wells to a metering facility, where the amount of production 

is recorded. The methane then flows to a compressor station, where the gas is compressed and 

then shipped via pipeline (De Bruin, et al., 2001). The produced water is a by-product of the gas 

extraction process, requiring some form of management (i.e., use or disposal). 

Well construction for any well drilling operation—including a CBM well—usually 

follows one of two basic types: open hole or cased. In open-hole completions, the well is drilled 

but no lining material is installed, so any gas can seep out all along the well into the wellbore for 

removal to the surface. In cased completions, a lining is installed through all or most of the 

wellbore. These casings need to be perforated or slotted to allow gas to enter the wellbore for 

removal to the surface. Open-hole completions, which are less expensive than perforated or 
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3-2 

slotted completions, are used more often in CBM production than in conventional oil and gas 

production, which use open-hole completion only under certain limited circumstances 

(NaturalGas.org, 2004). For example, open-hole completion is widely used in Wyoming’s 

Powder River Basin (PRB) (ALL, 2003). Figure 3-1 shows the profile of a typical western CBM 

well using open-hole completion. 

Figure 3-1. Profile of a Typical Western CBM Well With Open Hole Completion 

(DeBruin, et al., 2001) 

Operators drill wells into coal-bearing formations that are often not as deep as those 

containing conventional hydrocarbon reserves, particularly in western regions. In the PRB, for 

example, some of the methane-bearing formations are shallow, at hundreds to one thousand feet 

below land surface, compared to conventional oil and natural gas well depths averaging 

approximately 6,000 feet (U.S. DOE, 2005). CBM wells can often be drilled using water well 

drilling equipment, rather than rigs designed for conventional hydrocarbon extraction, which are 

used to drill several thousands of feet into typical conventional reservoirs (Apache Corporation, 

2006). 

A CBM well’s typical lifespan is between 5 and 15 years, with maximum methane 

production often achieved after one to six months of water removal (Horsley & Witten, 2001). 

CBM wells go through the following production stages: 
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3-3 

• An early stage, in which large volumes of groundwater are pumped from the seam 

to reduce the underground pressure and encourage the natural gas to release from 

the coal seam;

• A stable stage, in which the amount of natural gas produced from the well 

increases as the amount of groundwater pumped from the coal seam decreases; 

and

• A late stage, in which the amount of gas produced declines and the amount of 

groundwater pumped from the coal seam remains low (De Bruin, et al., 2001). 

3.1.1 History of Production in the CBM Basins

Table 3-1 shows the major CBM production basins (including those where no 

development has taken place), their locations, typical well depths, and the thickness and depth of 

CBM seams. Interest in producing methane gas from coal seams began in the 1970s, but little 

development occurred until the early 1980s. In 1983 the Gas Research Institute began a field 

study investigating the potential for producing methane gas from coalbed strata (Fisher, 2001). 

By the end of that year, 165 wells had been drilled, producing about 6 billion cubic feet (Bcf) of 

gas, less than 1 percent of the amount produced in 2008. The first area to be developed was the 

Black Warrior Basin in Alabama, followed by the San Juan Basin in New Mexico and Colorado, 

which began development in the latter part of the 1980s. For many years, CBM was almost 

exclusively produced from these three states (Fisher, 2001). Production in the PRB began in 

earnest in the early 1990s, and the PRB quickly became a major source of CBM by the end of the 

1990s (Wyoming Oil and Gas Conservation Commission [WOGCC], 2010). Although not 

increasing as rapidly since that time, production has risen fairly steadily. By 2000, Wyoming was 

producing 10 percent of all CBM; by 2008, production in the state was approaching a third (U.S. 

DOE EIA, 2010a; U.S. EPA, 2010a). 

The older basins, such as San Juan and Black Warrior, have not seen growth in CBM 

production during the 2000s. San Juan production appears to have peaked in 2002, with some 

decline since then. Black Warrior production has been level in the 2000s (U.S. DOE EIA, 

2010a). The rise in U.S. production over time has been driven primarily by production in 

Wyoming, mostly in the PRB. Production in several other basins has also increased over time, 

although these basins contribute less to CBM production growth than PRB (U.S. DOE EIA, 

2010a). Several additional basins are of interest for future CBM production, although little to no 

development is currently underway. Section 3.6.4 discusses the future of CBM production in the 

various basins. 
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Table 3-1. Characteristics of Major CBM Basins

Basin Location/Area Coalbed Thickness

Well Depth or Depth to Target 

Coal Seam

Appalachian (Central) 23,000 square miles in Kentucky, 

Tennessee, Virginia, and West Virginia

with greatest potential for development 

in a 3,000 square mile area in southwest 

Virginia and south central West Virginia

Variable 1,000 to 2,000 feet

Appalachian (Northern) 43,700 square miles in Kentucky, 

Maryland, Ohio, Pennsylvania, Virginia, 

and West Virginia

Average of 25 feet in Pennsylvania Ranges from surface outcrops to 

depths of 2,000 feet with most 

occurring at depths of less than 

1,000 feet

Arkoma 13,500 square miles in Arkansas and 

Oklahoma

600 to 2,300 feet 0 to 4,500 feet

Black Warrior • Covers about 23,000 square miles in 

Alabama and Mississippi

• Measures approximately 230 miles 

east-west and 188 miles north-south

1 to 8 feet 350 to 2,500 feet

Cherokee/Forest City • Cherokee is 26,500 square miles in 

Oklahoma, Kansas, and Missouri

• Forest City is 47,000 square miles in 

Iowa, Kansas, Missouri, and Nebraska

Few inches to 6 feet Depth to coal in the shallow portion 

of Cherokee ranges from surface to 

230 feet and up to 1,200 feet in the 

deeper portion 

Greater Green River Comprises five smaller basins in 

Wyoming, Colorado, and Utah

Multiple coal seams up to 50 feet thick Not Readily Available

Illinois Northwestern Kentucky, southeastern 

Indiana, and Illinois

Multiple thin coal seams Most seams are at less than 650 

feet; across the basin, all seams are 

less than 3,000 feet deep

Piceance 7,225 square miles in Northwest 

Colorado 

2,000 feet on west side to 6,500 feet on 

east site

Depth to methane-bearing 

formation is 6,000 feet, which has 

hindered development

Powder River Basin 25,800 square miles in northeastern 

Wyoming and southern Montana

Ranges by formation – Wasatch 

Formation has thin coals (6 feet or less) 

while Fort Union coals, which are below 

Wasatch, can be up to 6,200 feet thick

450 to 6,500 feet
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Table 3-1. Characteristics of Major CBM Basins

Basin Location/Area Coalbed Thickness

Well Depth or Depth to Target 

Coal Seam

Raton • 2,200 square miles in southeastern 

Colorado and northeastern New 

Mexico

• Measures 80 miles north-south and as 

much as 50 miles east-west

Vermejo coals are 5 to 35 feet thick and 

Raton coal layers are 10 to 140 feet 

thick

Not Readily Available

San Juan • Covers an area of about 7,500 square 

miles across the Colorado/New 

Mexico line in the Four Corners 

region. 

• Measures approximately 100 miles 

north-south direction and 90 miles 

east-west. 

Majority of production is in the 

Fruitland Formation. Coals of the 

Fruitland Formation range from 20 to 

over 40 feet thick

Wells drilled into the Fruitland coal 

seam typically range from 600 feet 

to 3,500 feet

Uinta Eastern Utah (small portion in 

northwestern Colorado) covering 14,450 

square miles

Exploration in Ferron Coals and 

Blackhawk formation

Depths to coal range from 1,000 to 

7,000 feet

Wind River Central Wyoming east of Powder River 

Basin

Potential for development in Upper 

Cretaceous Formation with thicknesses 

of up to 100 feet and Meeteetse 

Formation with thicknesses of less than 

20 feet

Not Readily Available

Sources: U.S. EPA, 2004a, U.S. EPA, 2004b; ARI, 2010b; ALL, 2003.
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3.1.2 CBM Production 

CBM production in 2008 totaled nearly 2 trillion cubic feet (Tcf) of gas (U.S. EPA, 

2010a),7

In 2008, according to EPA’s screener survey database,

 when compared to a total of 25.8 Tcf of all forms of natural gas was produced (U.S. 

DOE EIA, 2010b); CBM composed about 8 percent of all natural gas produced, and is 

considered an important ongoing supply of energy by U.S. DOE. 

8

Table 3-2

 252 operators managed 

approximately 56,000 CBM wells in the United States in 15 basins located in 16 states (U.S. 

EPA, 2010a). identifies all of the currently (as of 2008) producing basins and presents 

CBM production by basin.9

By far the largest producing states are Wyoming and New Mexico. Wyoming contains 

the largest portions of the PRB and Green River as well as the Wind River Basin. New Mexico 

contains most of the San Juan Basin and a portion of the Raton Basin. 

 More than two-thirds of all CBM produced in 2008 was produced in 

the San Juan and Powder River Basins (69 percent). About 88 percent was produced by the five 

largest producing basins (San Juan, Powder River, Appalachian, Raton, and Black Warrior). In 

the Powder River, Green River, Raton, Black Warrior, Cahaba, Appalachian, and Illinois basins, 

some produced water is discharged to surface waters or POTWs. In the remaining basins the only 

practice is zero discharge. In 2008, roughly 50 percent of total CBM was produced in basins in 

which some surface water discharge is occurring.

Table 3-2. CBM Production by Basin in 2008

Basin State(s)

CBM Production

Total (Bcf) Percentage of Total

PRB WY, MT 607 31%

Green River WY, CO 13 1%

Raton CO, NM 129 6%

Black Warrior AL 104 5%

Cahaba AL 4 0%

Appalachian and IL PA, WV, VA, OH, IN, IL 144 7%

San Juan NM, CO 755 38%

Cherokee/Forest City KS 79 4%

 

7 There are some discrepancies in the screener database from published figures for some basins. Both the screener 

and detailed survey ask for production; for the screener survey, operators might have approximated their production; 

whereas operators might have provided more exact production figures from the project financial records needed to 

complete the detailed survey. Alternatively, some states’ production data might be less accurate than the operators’ 

records; additionally, some wells are classified in some states as confidential wells. It is not certain that published 

data contain information on confidential wells. Most state websites indicate that they do not warrant the accuracy of 

their data.

8 For information in the screener to be reported without concern that CBI would be revealed, the screener database 

was modified to replace CBI data with publicly available data on numbers of wells and gas production. Additionally, 

projects identified as out of scope later during implementation of the detailed questionnaire were also removed from 

the screener database. The modifications made to the screener database are documented in (ERG, 2010).

9 The Appalachian Basin and Illinois Basin have been combined here, in part, to maintain confidentiality of CBI as 

noted in ERG, 2010.
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Table 3-2. CBM Production by Basin in 2008

Basin State(s)

CBM Production

Total (Bcf) Percentage of Total

Uinta-Piceance CO, UT 65 3%

Arkoma OK, AR 66 3%

Anadarko OK, AR 18 1%

Other LA, TX, WY 3 0%

Total 1,988 100%

Source: U.S. EPA, 2010a.

3.1.3 Potential for Development in New CBM Basins

The basins that have been developed to date are those with mid-rank coals (coals with 

more energy associated with them and generally more gas than lowest-rank and highest-rank 

coals). Additional CBM prospects exist in other areas in the United States that have not yet been 

developed. Table 3-3 summarizes prospective but nonproducing CBM resources. Because of the 

existing pipeline infrastructure, coal rank, and coal volume, the most likely basin to produce 

commercial quantities of CBM over the next 10 years is the Black Mesa Basin (ARI, 2010a). 

Table 3-3. Prospective But Nonproducing CBM Resources

Region Name Location

Estimated Gas in 

Place (Tcf) Status

Alaska—Cook Inlet Southern 

Alaska

136 Located close to existing Kenai LNG facility. One 

unsuccessful pilot plant that was built can provide 

data for further development.

Alaska—North Slope Far northern 

Alaska

621 No development to date because of remoteness from 

markets; not characterized; pipeline planned to 

transport natural gas to southern markets could 

benefit CBM.

Pacific Northwest 

Coal Region

Washington and 

Oregon

10 Geologically complex area makes gas recovery 

challenging. No conventional gas production in the 

region is a positive market factor. Some testing 

demonstrated good gas content, permeability, and 

gas flow rates.

Black Mesa Basin Northeastern 

Arizona

1–10 Large-scale surface mining in the area since the 

1960s but no CBM testing to date. Could access 

market via recently constructed Questar Southern 

Trails gas pipeline.

Low-Rank Coals in 

the Gulf Coast

Florida 

panhandle to 

Texas Gulf 

Coast

1.7–7.9 Gas-rich coals occur below 3,000 feet. Over 400,000 

acres have been leased and individual test pilots have 

been installed. Exploration is active in north central 

Louisiana following 2005 revision of state law to 

accommodate CBM. Exploration is also active in 

Maverick County in southcentral Texas. 
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Table 3-3. Prospective But Nonproducing CBM Resources

Region Name Location

Estimated Gas in 

Place (Tcf) Status

Other Low-Rank 

Coals

North Dakota,

Northern 

Montana, 

Michigan

Unknown Little work done to date to assess the CBM potential 

of lignite coals, but anecdotal evidence from water 

well drillers suggests CBM exists in North Dakota

lignite.

Source: ARI, 2010a.

3.2

EPA evaluated the quality and quantity of produced water generated from CBM

extraction using preliminary data from responses to the detailed survey questionnaires and other 

sources. As discussed in Section 3.1, water within the coal seam usually must be removed before 

and during CBM production. The quantity and quality of this produced water varies from basin 

to basin, and even within the basin itself. The quality of produced water depends, in part, on the 

hardness of the coal found within the formation. The quantity of produced water depends on type 

of coal and the overall production history of the basin. Basins with a longer production history, 

such as the San Juan basin, produce less total water and less water per well than the more 

recently developed basins, such as the PRB.

Produced Water Characteristics

3.2.1 Volumes of Produced Water 

Based on preliminary data from the detailed questionnaire responses, EPA estimated that, 

in 2008, more than 47 billion gallons of produced water were pumped out of coal seams and 

approximately 22 billion gallons of that produced water (or about 45 percent) were discharged to 

surface waters. Table 3-4 presents preliminary volumes of produced water discharged (basins 

not listed here do not discharge). 

Table 3-4. Volumes of CBM Produced Water Discharged to Surface Waters in the 

Discharging Basins (2008) 

Basin Volume (million gallons/year) a

Appalachian 32.3

Black Warrior 2,454.3

Cahaba 244.0

Green River 327.1

Illinois 113.4

Powder River (Montana) 1,266.8

Powder River (Wyoming) 14,622.5

Raton 2,515.8

Total 21,543.9

Source: Preliminary detailed questionnaire data (U.S. EPA, 2010b). 

a – The volume totals for each basin do not include discharges to POTWs, which are minimal.
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3.2.2 Pollutants in Produced Water

CBM produced water is generally characterized by elevated levels of salinity, sodicity, 

and trace elements (e.g., barium and iron) (ALL, 2003). Other trace pollutants that may be 

present in produced water include potassium, sulfate, bicarbonate, fluoride, ammonia, arsenic, 

and radionuclides. The characteristics of the produced water depend on the geography and 

location (e.g., naturally occurring elements). All of these parameters can cause adverse 

environmental impacts (see Chapter 4) and also affect the potential for beneficial use of 

produced water. 

Salinity represents the total concentration of dissolved salts in the produced water, 

including magnesium, calcium, sodium, and chloride. Salinity can be measured as electrical 

conductivity (EC), expressed in deciSiemens per meter (dS/m), as well as total dissolved solids 

(TDS). TDS includes any dissolved minerals, salts, metals, cations, or anions in the water. The 

salinity of CBM produced water also relates to the measured sodicity value.

Sodicity is excess sodium present in produced water that can deteriorate soil structure 

(i.e., swell and disperse clays reducing pore size), which reduces the infiltration of produced 

water through the soil. The sodicity of produced water is expressed as the SAR, which is the 

ratio of sodium (Na) present in the water to the concentration of calcium (Ca) and magnesium 

(Mg) (Equation 3-1).

( ) [ ] [ ] Ca Mg 2

1

[Na ] SAR

2+ 2+

+

+

= Equation 3-1 

Table 3-5 presents available literature data for minimum and maximum produced water 

TDS concentrations in 9 of the 15 CBM basins (data were obtained separately for each portion of 

the Uinta-Piceance Basin). EPA used these data to estimate average TDS concentrations in each 

of the basins where such data were available. When this average might not accurately reflect the 

TDS concentrations in produced water basin-wide, EPA substituted other values were used that 

were deemed to be more representative. As the table shows, EPA estimates that average TDS 

concentrations vary widely, from approximately 1,100 mg/L TDS in the Powder River Basin up 

to 86,000 mg/L in the San Juan Basin. For comparison, the recommended TDS limit for potable 

(drinking) water is 500 milligrams per liter (mg/L) and 1,000 to 2,000 mg/L (USGS, 2000) for 

irrigation and stock ponds. 

EPA used preliminary questionnaire discharged flow volumes from Table 3-4 and the 

concentration estimates presented in Table 3-5 to calculate approximate TDS discharges from 

CBM operations. EPA estimated that approximately 500 million pounds of TDS from CBM 

production operations were discharged to surface waters in 2008.10

 

10 To compute the total TDS discharge, EPA used concentrations from the Black Warrior Basin to estimate the 

concentrations for the Cahaba and Illinois basins (data from ALL, 2003).
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Table 3-5. TDS Concentrations in CBM Produced Water by Basin

Basin

Minimum

(mg/L)

Maximum

(mg/L)

Average

(mg/L)

Average

(lbs/gal)

Appalachian <10,000 >10,000 10,000 0.0835

Black Warrior <50 60,000 16,000 0.1335

Cahaba <50 60,000 16,000 0.1335

Green River ND >10,000 5,000 0.0417

Illinois <50 60,000 16,000 0.1335

Powder River 244 8,000 1,066 0.0089

Raton 310 >3,500 1,905 0.0159

San Juan 180 171,000 85,590 0.7143

Uinta 6,350 42,700 24,525 0.2047

Piceance 1,000 6,000 3,500 0.0292

Source: U.S. EPA 2006, U.S. EPA 2010b. 

ND – Not detected. 

The available literature also yielded concentration data for other pollutants for five of the 

basins (see Table 3-6).

Table 3-6. Pollutant Concentrations in CBM Produced Water by Basin

Pollutant

Pollutant Concentration by Basin (mg/L)

San Juan Basin

Black Warrior 

Basin

Powder River 

Basin Raton Basin Uinta Basin

Min Max Min Max Min Max Min Max Min Max

Barium 0.7 63 NA NA 0.06 2 NA NA NA NA

Calcium 0 228 NA NA 5 200 4 24 NA NA

Chloride 0 2,350 40 36,000 3 119 15 719 2,300 14,000

Iron 0 228 0.1 400 0.03 11 0.1 23 NA NA

Magnesium 0 90 NA NA 1 52 1 8 NA NA

Potassium 0.6 770 NA NA 2 20 1 17 NA NA

Sodium 19 7,130 60 21,500 89 800 210 991 NA NA

Sulfate 0 2,300 1 1,350 0.01 1,170 1 204 NA NA

Source: U.S. EPA 2006. 

Min – Minimum.

Max – Maximum.

NA – No data available. 

3.3

CBM well operators use a variety of methods to manage, store, treat, and dispose of 

CBM produced water. 

Management of Produced Water

Figure 3-2 shows the potential path of produced water. As mentioned in 

Section 2.4, CBM is usually produced from a project, which is defined as a well, group of wells, 

lease, group of leases, or some other recognized unit that is operated as an economic unit when 
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3-11 

making production decisions. The produced water from the project might be managed using 

various storage, treatment, and disposal methods, and each CBM project can use several different 

management methods. 

All CBM operators need a system gathering and transporting produced water. CBM 

produced water from individual wells is often gathered via a pipeline system to transport the 

water to a centralized storage system and then to either a treatment system or the final disposal 

location. Section 3.4 discusses common treatment methods. The final destination of CBM 

produced water may include the following:

• Discharge – Either direct discharge to surface water or indirect discharge to a 

POTW (Section 3.3.1);

• Zero discharge (with no beneficial use) – Zero discharge might include 

evaporation/infiltration,

11

3.3.2

 underground injection, or land application with no crop 

production (Section ); and

• Zero discharge (with beneficial use) – Beneficial use might include land 

application, wildlife watering, or other miscellaneous beneficial uses (Section 

3.3.3). 

Produced water from CBM 

operations

Treatment

• Aeration

• Filtration

• Ion Exchange

• Reverse Osmosis

• Sedimentation

Storage

• Storage Ponds

• Tanks

Zero Discharge (with no 

beneficial use )

• Underground Injection

• Evaporation /infiltration (with 

no surface discharge )

Discharge

• To Surface Water

• To POTW

Zero Discharge (with 

beneficial use )

• Land Application

• Livestock Watering

No Treatment or Storage

To Final Disposal Method

Figure 3-2. Diagram of Potential Path of Produced Water

Operators may contract with a commercial disposal company to manage the wastewater. 

Typically, the produced water is stored on site in tanks and later hauled to the third-party 

 

11 CBM operators may also use evaporation/infiltration to reduce the amount of produced water discharged to 

surface water.
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3-12 

company. Sections 3.3.1 through 3.3.3 and Section 3.4 discuss the disposal and treatment 

methods in more detail. 

The produced water management methods used in a particular basin depend on a variety 

of factors such as water quantity, water quality, availability of receiving waters, availability of 

formations for injection, landowner interests, and state regulations. Table 3-7 lists each basin 

included in EPA’s site visit program, the typical management and disposal practices in use, the 

factors affecting the management practice, and treatment and beneficial use methods observed 

during the site visit program.

The screener survey provided EPA with information on which produced water 

management practices are used at each project. These management practices are divided into two 

major groups: discharging practice (direct discharge to surface waters or indirect discharge to a 

POTW) or zero discharge practice (land application, evaporation/infiltration pond, underground 

injection, beneficial use, transport to a commercial disposal facility, or no water generated). 

The basins in which direct or indirect discharge is practiced are called “discharging 

basins” in this profile and include the Powder River, Appalachian, Illinois, Raton, Black Warrior, 

Cahaba, and Green River Basins. EPA determined that, in other basins, CBM operators manage 

produced water without discharging any portion of it directly or indirectly to surface waters. In 

these basins, called “zero discharge basins” in this profile, produced water is managed primarily 

by underground injection, trucking to a commercial disposal facility, or collection in ponds for 

use by livestock/wildlife (beneficial use) or in evaporation/percolation ponds. 

Table 3-8 presents the number of projects using the various produced water management 

methods by basin. Note that the numbers reported reflect multiple produced water management 

practices at many projects. For example, a project might be reported to use surface water 

discharge, evaporation/infiltration ponds, and underground injection. For the purposes of this 

profile, such a project is considered a discharging project because at least some produced water 

is reported to be discharged to surface waters. Only projects reporting no direct or indirect 

discharge are considered zero discharge projects.12

 

12 Nine CBI “projects” use some type of zero discharge practice; these projects are not reflected in the counts 

presented in Table 3-8 to protect potential confidential information. EPA set projects per operator per basin to one 

for all operators claiming project information as CBI (see ERG, 2010).
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Table 3-7. CBM Produced Water Management Practices Observed During Site Visits 

Basin

Management and Disposal 

Practices in Use

Factors Affecting 

Management Option

Treatment Technologies 

Observed During Site Visit

Beneficial Use Observed 

During Site Visit

Appalachian (Central) • Injection

• Land application (with no 

crop production)

• Surface discharge

• Availability of large 

receiving water bodies

• Land application is permitted 

under West Virginia general 

permit

• Sedimentation None observed

Appalachian (Northern) • Injection

• Surface discharge

• Availability of large 

receiving water bodies

• Aeration

• Sedimentation (Pennsylvania 

does not allow the use of 

chemical coagulants to treat 

CBM produced water)

None observed

Black Warrior Basin • Surface discharge • Availability of large 

receiving water bodies

• Geological formations can 

not handle the volumes of 

produced water

• Operators typically use a 

combination of storage 

ponds, sedimentation, and 

aeration

None observed

PRB • Injection

• Surface discharge

• Evaporation/infiltration 

ponds

• High volumes of water with 

low salinity

• Aeration

• Sedimentation

• Ion exchange

• Land application

• Livestock watering

• Subsurface drip irrigation 

(SDI)

• Small amounts may be used 

for dust suppression

Raton • Injection 

• Surface discharge

• Aerated storage ponds • Small amounts may be used 

for dust suppression

• Livestock watering

San Juan • Injection

• One operator is an indirect 

discharger 

• Availability of formations 

for injection

• High salinity of produced 

water

• State regulations

• Altela thermal distillation 

system is used for the 

indirect discharger

None observed

Source: DCN 05354.
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Table 3-8. Number of Projects by Produced Water Management Practices Reported

Basin

Direct 

Discharge

Indirect 

Discharge

Land 

Application

Underground 

Injection

Evaporation/ 

Infiltration 

Pond Beneficial Use a

Haul to 

Commercial 

Disposal

No Water 

Generated

Discharging Basins

Powder River 149 2 29 31 145 154 4 4

Green River 3 0 0 10 1 1 2 0

Raton 3 0 0 3 3 1 2 0

Black Warrior 13 0 0 0 1 0 2 0

Cahaba 2 0 0 1 0 0 1 0

Appalachian and Ill. 8 3 2 15 7 0 7 1

Total, Discharging Basins 178 5 31 60 157 156 18 5

% of Projects Reporting 29% 1% 5% 10% 26% 26% 3% 1%

Zero Discharge Basins

San Juan 0 0 0 58 2 1 142 2

Cherokee/Forest City 0 0 0 25 0 0 3 0

Uinta-Piceance 0 0 0 11 2 0 2 0

Arkoma 0 0 0 16 0 0 153 2

Anadarko 0 0 0 14 0 0 6 1

Other 0 0 0 2 0 0 1 0

Total, Zero Discharge 

Basins

0 0 0 126 4 1 307 5

% of Projects Reporting 0% 0% 0% 28% 1% 0% 69% 1%

Source: U.S. EPA, 2010a. Note: Zero discharge practices claimed as CBI are not reported here (see ERG, 2010); counts reflect multiple practices at many 

projects.

a – Livestock and wildlife watering.
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As Table 3-8 shows, in zero discharge basins, the primary produced water management 

practices are underground injection and hauling for commercial disposal. In discharging basins, 

in addition to direct and indirect surface water discharge, operators also use zero discharge 

methods. In these basins, evaporation/infiltration ponds and beneficial use (livestock and wildlife 

watering) are common zero discharge practices; underground injection and hauling are less 

common. Land application, another practice that can be considered zero discharge, is relatively 

rare and found primarily in the PRB and, as witnessed during site visits, in the Appalachian 

basin. Land application under proper circumstances (e.g.., with produced water with low SAR 

and other pollutants) can be considered beneficial use (e.g., irrigation). Only 10 projects, located 

primarily the Powder River, San Juan, and Arkoma Basins, produced no water in 2008. 

3.3.1 Discharge to Surface Water or POTW 

Based on screener survey responses, EPA determined that CBM well operators in a 

number of basins discharge at least a portion of their produced water directly to surface water. 

Screener responses indicated that indirect discharge of produced water is not common; only three 

operators with five projects (two in the PRB and three in the Appalachian Basin) discharged 

produced water to a POTW in 2008; during site visits, EPA also observed indirect discharges in 

basins other than PRB and the Appalachian as listed in Table 3-14. Discharge to surface water is 

most prevalent (by volume) in the Black Warrior, Powder River, and Raton Basins. Using 

preliminary questionnaire data, EPA estimated that approximately 22 billion gallons of produced 

water are discharged annually to surface waters. CBM well operators typically transport 

produced water to the discharge location via buried pipelines (i.e., gathering system). 

3.3.2 Zero Discharge (with No Beneficial Use)

The following subsections describe zero discharge disposal methods that are not 

considered beneficial use.

3.3.2.1 Evaporation/Infiltration Impoundments

Operators use earthen storage impoundments (ponds) to manage the produced water by 

allowing the water to evaporate or penetrate into the soil and become groundwater. 

Impoundments may also be used for storage or in conjunction with surface water discharge to 

control the wastewater flow to the outfall. 

The impoundments are typically excavated rectangular pits with sloped sides and 

perimeter berms. There are two types of impoundments used for evaporating or infiltrating 

produced water: in-channel and off-channel. In-channel ponds are located within an existing 

drainage basin, including all perennial, intermittent, and ephemeral defined drainages, lakes, 

reservoirs, and wetlands. Off-channel ponds are located in upland areas, outside natural 

drainages and alluvial deposits associated with these natural drainages (Pochop et al.,1985). 

Many CBM well operators in the PRB manage produced water in impoundments to 

minimize or eliminate the amount of wastewater discharging to surface water. Most of the 

impoundments in the PRB are off-channel and are designed to contain all CBM produced water 

without discharge (Oil & Gas Consulting, 2002). 
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3.3.2.2 Underground Injection 

The Underground Injection Control (UIC) Program, under the Safe Drinking Water Act, 

ensures that injection wells do not endanger current and future underground sources of drinking 

water (USDW). USDW are defined as aquifers or portions of aquifers that contain less than 

10,000 mg/L of TDS and have enough groundwater to supply a public water system. Currently 

there are five classes for deep wells used for disposal. EPA defines these classes (listed in Table 

3-9) according to the type of fluid and location (U.S. EPA, 2005). 

Table 3-9. UIC Program: Well Classes and Description

Well Type Injection Well Description

Class I Wells used to inject fluids underneath the lowermost formation containing USDW

Class II Wells used to inject nonhazardous fluids associated with oil and natural gas recovery and 

storage of liquid hydrocarbons

Class III Wells associated with solution mining (e.g., extraction of uranium, copper, and salts)

Class IV Wells used to inject hazardous or radioactive waste into or above USDW

Class V Any injection well that is not contained in Classes I to IV

Source: U.S. EPA, 2005. 

The type of injection well CBM operators can use to manage produced water are Class II. 

By injecting produced water with high salt content or other contaminants deep underground, 

Class II wells prevent surface contamination of soil and water. CBM produced water typically 

has lower TDS concentrations than the water in the injection zone. If the well is properly 

designed, maintained, and operated, there is little risk of groundwater contamination from 

produced water. However, this practice can be limited by the availability of suitable formations 

to accept the volumes of water injected (e.g., high-porosity formations located below saline 

aquifers to avoid any potential for drinking water contamination). Under federal and state 

requirements, the produced water must be injected into the originating formation or into 

formations that are similar to those from which it was extracted (Zimpfer et al., 1988). 

Operators install Class II wells by either drilling new holes or converting existing wells 

such as marginal oil-producing wells, plugged and abandoned wells, and wells that were never 

completed (dry holes). Some operational difficulties associated with injecting CBM produced 

water include formation plugging and scaling, formation swelling, corrosion, and incompatibility 

of injected produced water with receiving formation fluids. In general, these issues can be 

avoided or remedied by using engineering and operational applications such as treatment 

chemicals (U.S. EPA, 1996). 

Pretreatment for injection may include removing iron and manganese by precipitation. 

Iron and manganese form oxides upon exposure to air, which may clog the well. Settling tanks 

with splash plates aerate the produced water, which oxidize iron and manganese to insoluble 

forms that can precipitate in the tank. Biocides may also be added to the produced water prior to 

injection to control biological fouling. 
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3.3.2.3 Land Application (with No Crop Production)

EPA observed the disposal of produced water by land application with no crop 

production in West Virginia (Appalachian Basin). In West Virginia, produced water may be 

disposed of by land application based on the quality of the water and the land’s ability to 

assimilate the water. The produced water is land applied such that there is no runoff to surface 

water. In West Virginia, water quality parameters that limit land application of CBM water are 

chloride content and TDS. Land application may not be feasible for reasons including wet or 

frozen conditions or soils with high clay fractions that may impede produced water from 

infiltrating into the soil, causing it to run off into nearby streams or rivers. Any conditions 

causing limited infiltration preclude land application, and other disposal methods must be used. 

3.3.3 Zero Discharge (with Beneficial Use)

The beneficial use of CBM produced water is defined as a use that provides a service to 

local communities and ecosystems without resulting in the direct discharge of produced water to 

surface waters. Beneficial uses include irrigation of cropland and pastureland without return 

flows to drainages and livestock and wildlife watering (Oil & Gas Consulting, 2002). 

Water quality and quantity are the primary characteristics of CBM produced water that 

determine the potential beneficial use options at a CBM site. For example, concentrations of 

certain trace elements such as arsenic, manganese, and zinc can limit the beneficial use options 

available due to the elements’ potential toxicity to humans and the environment. In addition, 

other site-specific constraints such as water rights, permitting regulations, location, and cost may 

limit the beneficial use management options available at a given site.

3.3.3.1 Land Application (with Crop Production)

The quality of CBM produced water and the physical and chemical properties of the 

irrigated soils determine whether produced water can be used for irrigation. The three primary 

water quality considerations of produced water for irrigation applications are salinity, sodicity, 

and toxicity (see Section 4.3.1). When CBM produced water is used for irrigation, soil samples 

are periodically analyzed to ensure that the application will not cause plugging or dispersal (and 

subsequent erosion) of the soil structure. Soil sample analytes include SAR, EC, pH, and soil 

moisture (to confirm that water is being absorbed). Complete soil chemistry and hydraulic 

properties are also analyzed and reviewed on a periodic basis. Soil amendments (e.g., gypsum) 

may be added to improve the physical properties of the soil. 

EPA observed subsurface drip irrigation (SDI) systems developed by BeneTerra, LLC, to 

beneficially use CBM produced water. BeneTerra currently operates SDI systems in the Powder 

River Basin. In Wyoming, SDI systems are permitted under the Wyoming Department of 

Environmental Quality’s (WYDEQ) UIC program as Class V injection disposal wells.

BeneTerra’s SDI system disperses produced water through polyethylene tubing placed 

below ground level. BeneTerra contracts with energy companies to design, build, and operate the 

SDI systems for a given period of time. Surface and water use agreements are made among all 

parties – the CBM operator, landowner, and BeneTerra. BeneTerra agrees to disperse a set 

volume of water over a set contract period, works with the landowner to determine the type of 

crops that will be grown on the irrigated area, and determines the soil amendments required to 
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maintain the proper soil chemistry given the type of crop and the produced water quality. 

BeneTerra also uses groundwater modeling to predict the subsurface flow of the injected CBM 

produced water to ensure that it does not connect with surface waters (U.S. EPA, 2007). 

3.3.3.2 Livestock and Wildlife Watering 

CBM produced water used for livestock watering is typically stored either in system 

reservoirs and stream drainages or in small containment vessels (e.g., tire tanks). Spacing stored 

water throughout grazing lands or letting it overflow to a drainage system allows landowners to 

distribute water to their livestock in selected locations on ranch lands, which can prevent or 

reduce livestock impacts to naturally occurring surface waters.

Similar to livestock watering, CBM produced water can be stored in ponds to provide 

additional water sources to support drinking water needs and habitat requirements for local 

wildlife. In general, wildlife watering ponds improve the diversity of habitats available, increase 

wildlife populations and ranges in the region, and enhance community dynamics in the local 

ecosystem (ALL, 2003). In some cases, wildlife watering ponds may also improve the quality of 

water available to wildlife and provide habitats for transient populations such as migrating birds 

during the winter season. 

3.3.3.3 Industrial Uses

Another possible beneficial application of CBM produced water is industrial operations, 

such as energy extraction industries, cooling towers, or fire protection. As with all disposal 

methods, using produced water in industrial applications depends on the quality of the produced 

water and the water quality required for the application. During the site visit program, EPA 

observed CBM operations that use produced water for dust suppression during drilling or mining 

activities and for equipment washing. 

3.4

Operators may treat the CBM produced water prior to discharge or other management. 

The level of CBM produced water treatment depends on the pollutants present in the water and 

the final destination. EPA identified and investigated technologies for treating produced water, 

including aeration, chemical precipitation, reverse osmosis, ion exchange, electrodialysis, 

thermal distillation, and combination technologies. These technologies reduce or eliminate 

pollutants in the produced water, allowing beneficial use or surface water discharge. 

Treatment Methods

3.4.1 Aeration 

Aeration is primarily used to precipitate (remove) iron from the wastewater, which 

reduces or eliminates stream bed staining and preserves the aesthetic quality of the receiving 

stream. The aeration process mixes air and water, typically by injecting air into water, spraying 

water into the air, or allowing water to pass over an irregular surface. Pollutants are released 

from the water through oxidation, precipitation, or evaporation. CBM well operators may use 

spray nozzles, agitators, and bubble diffusers to aerate the water before discharge. Following 

sedimentation and chemical precipitation, discharges to surface water typically flow over rip-rap 

to aerate the water before it enters the stream bed, which also helps to reduce erosion and further 

precipitate pollutants (e.g., iron) from the water. 
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3.4.2 Sedimentation/Chemical Precipitation

CBM well operators use sedimentation and chemical precipitation to remove suspended 

solids. Solids settle to the bottom of sedimentation basin and are removed via an underflow pipe. 

Chemical addition is often used to facilitate solids settling (i.e., chemical precipitation). 

Sedimentation is not expected to reduce dissolved solids. 

This treatment typically occurs prior to discharging the produced water to surface water 

or a POTW. Numerous operators use sedimentation to remove iron (typically preceded by some 

form of aeration to facilitate iron settling). EPA also received several questionnaire responses 

indicating targeted barium removal using chemical precipitation. As discussed in Section 3.3.2, 

operators often use storage ponds for evaporation/infiltration, where solids will typically settle to 

some extent. 

3.4.3 Reverse Osmosis

Reverse osmosis (RO) separates dissolved solids or other constituents from water by 

passing the water solution through a semipermeable cellophane-like membrane. RO is a proven 

treatment process for removing TDS and other constituents such as arsenic. RO has been used 

extensively to convert brackish water/seawater (brine) to drinking water, to reclaim wastewater, 

and to recover dissolved salts from various industrial processes. 

Although RO membranes can remove dissolved solids, suspended solids need to be 

removed in pretreatment steps. A high-quality feed water with reduced TSS levels prevents the 

membrane from plugging. In addition, membrane fouling and scaling will increase the required 

pressure to maintain a constant flow through the treatment process. 

Preliminary responses to the questionnaire indicate RO as the primary desalting 

membrane process used in produced water treatment. The high-quality water resulting from the 

RO process could be available for many beneficial uses (ALL, 2003). 

In addition to RO, nanofiltration is also a high-pressure desalting membrane process. 

Microfiltration and ultrafiltration are low-pressure membrane filtration processes that are used to 

remove solid particles; these are not considered desalting membranes, but are often used in the 

pretreatment steps. 

3.4.4 Ion Exchange 

In an ion exchange system (IX), wastewater passes through a system that contains a 

material (typically a resin) to extract and absorb specific constituents. In a typical setup, a feed 

stream passes through a column, which holds the resin. Pollutants absorb onto the resin as the 

feed moves through the system. Eventually the resin becomes saturated with the targeted 

pollutant requiring regeneration of the resin. A regenerant solution then passes through the 

column. For cation resins such as for sodium and metals, the regenerant is an acid, and the 

hydrogen ions in the acid remove the absorbed pollutant from the resin. The sodium and metals 

concentrations are much higher in the regenerant than in the feed stream. Therefore, the ionexchange process separates the sodium from the water and results in a concentrated brine stream 

and a treated produced water stream. Because the salt content of the produced water has been 

reduced, the treated stream can be discharged to surface waters or beneficially used. 
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EMIT Water Discharge Technology and LLC Higgins LoopTM – This technology is 

currently being used in the PRB and is a continuous countercurrent IX system. The EMIT 

process uses a strong acid cation exchange resin, which removes sodium, barium, 

calcium, and magnesium ions from the water and exchanges them with hydrogen ions 

(ALL, 2006a). 

Drake Water Technology Process (Drake Process)

3.4.5 Electrodialysis

 – This is a proprietary pilot-scale 

technology using an IX system that selectively removes sodium ions from CBM 

produced water. The PRB produced water is typically high in sodium (making it the 

dominant ion) and low in calcium and magnesium, which can yield high SAR values that 

limit beneficial use. Drake has four patents pending and a fifth in preparation that 

optimize the design of IX systems to treat PRB produced water. (U.S. EPA, 2009). 

Similar to RO, electrodialysis (ED) is also considered a desalting membrane (removes 

dissolved contaminants) but uses an electrically driven process. Electrodialysis uses alternating 

pairs of cation (positively charged) and anion (negatively charged) membranes positioned 

between two oppositely charged electrodes. Channeled spacers between the membranes create 

parallel flow streams across the membrane surface. Water is pumped into the flow channels; 

when voltage is applied, the electrical current causes ions from the water to migrate toward the 

oppositely charged electrodes and are restrained in the polarized membranes (Malmrose et al., 

2004). 

3.4.6 Thermal Distillation

EPA observed a proprietary thermal distillation process to treat produced water prior to 

discharge to a POTW in the San Juan basin. The AltelaRain® system is a transportable and fully 

integrated water thermal distillation treatment system for both CBM and conventional produced 

water. The system is built and contained in standard 20-foot or 45-foot shipping containers and 

transported by truck to individual well sites. The AltelaRain® system concentrates TDS into a 

brine waste stream and discharges water with very low TDS concentrations.

3.4.7 Multiple Technology Applications

EPA observed pilot-scale treatment facilities that integrate several treatment technologies 

to reduce pollutant concentrations so that water can be beneficially used or discharged. One pilot 

plant was run by an operator in conjunction with Sandia National Laboratories and New Mexico 

State University. The system used separators, ultrafiltration, and RO to treat produced water 

prior to beneficial use. 

EPA also observed a pilot plant run by Triwatech, consisting of a portable, pilot treatment 

system that included “off-the-shelf” equipment as well as proprietary, patent-pending treatment 

technologies. This system has been pilot tested for several operators in the San Juan Basin. The 

Triwatech pilot plant is located in a portable truck trailer and can be moved to different well 

sites. The system is used to determine the optimal treatment configuration for a specific CBM

water quality. Triwatech typically requires about two to four weeks of study to determine an 

optimal design for a full-scale system. The final Triwatech process design consists of pretreatment, polishing treatment, and post-treatment, which may consist of technologies such as 
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filtration, sedimentation, nanofiltration, RO, IX, or activated carbon. There are several different 

treatment steps that are evaluated during the initial pilot testing, and the final treatment system 

comprises a mix of the different types of treatment.

3.5

CBM is a form of natural gas and therefore is included in the accounting of U.S. natural 

gas reserves and production. However, because of differences in CBM geological formations and 

production characteristics, the economics of CBM production and other natural gas 

(conventional gas) or oil production differ, as discussed below. 

Current Economics of CBM Production

As noted in Section 3.1, CBM is generally produced from relatively shallow coalbeds. 

These coalbeds underlie the surface in broad areas, often covering many hundreds of square 

miles. Large amounts of produced water are typically generated initially; over time, the amount 

of water produced generally diminishes. In contrast, conventional gas is often contained within 

sharply defined geological formations, which can be accessed only from a relatively small area 

using deeper wells, typically, than those required for CBM production. Extracting conventional 

gas often generates relatively little water at first, but the production of water can increase over 

time. These differences in production between conventional gas and CBM lead to a very 

different economic profile in terms of production economics and, in some cases, firm economics. 

Because produced water management costs are a significant portion of operating costs in either 

type of gas production (U.S. DOE EIA, 2010e), CBM projects often begin with high operating 

costs that tend to diminish over time, while operating costs for conventional oil and gas often rise 

over time.

3.5.1 Number of Wells and Projects 

CBM wells are rarely operated as single units responsible for their own production costs, 

because operators realize economies of scale in operating several wells together as an economic 

unit. Given that CBM production requires numerous wells distributed over the coalbed, operators 

tend to include a large number of wells in each economic production unit, or project. 

In conventional oil and gas production, where the productive geographic area of an 

oil/gas producing formation is typically constrained, an economic production unit is often a 

lease. A lease usually comprises a relatively small number of wells ganged to a tank battery. In 

the tanks, water is separated and the oil and/or gas is prepared for sale and delivered to the 

market by pipeline (oil and gas) or truck (usually only oil). Produced water from that group of 

wells is piped to an underground injection well(s) located on the lease or nearby. Alternatively, 

the produced water might be trucked to a commercial disposal facility. The costs of produced 

water disposal are also shared among the group of wells. 

For CBM production, however, the economic production unit can be much larger than a 

lease, and the concept of “project” is more applicable. A project can be as small as a single well 

or a lease with just a few wells, but it can also be as large as over 1,000 wells. The tendency 

toward large projects is due to the wide geographic area in which a coalbed might be located. 

Projects in the discharging basins tend to be larger than projects in zero discharge basins. 
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According to EPA’s screener survey,13 a total of about 56,000 CBM wells, organized into 

approximately 750 projects, produced gas and/or water in 2008.14

Table 3-10

Of these projects, a minority 

(approximately 180 projects) discharged some produced water. and Table 3-11

characterize the numbers of wells and projects reported in the questionnaire. As Table 3-10

shows, most of these wells are located in the PRB (21,000, or 38 percent). The zero discharge 

basins have a relatively small number of wells (18,600 or 33 percent) but account for about 50 

percent of production, because average production per well is greater in the zero discharge basins 

than in the discharging basins. Table 3-11 also presents information on gas produced by 

discharging and zero discharge projects in each basin. As the table shows, projects that 

discharged at least some produced water to surface waters averaged gas production of 27 million 

cubic feet (MMcf) per well and 4.4 Bcf per project in 2008, while those that discharged no 

produced water averaged greater gas production per well (45 MMcf) but lower production per 

project (2.1 Bcf) than projects discharging to surface waters. The higher per-project production 

in discharging basins results from the higher average number of wells per project in the 

discharging basins. 

Table 3-10. Wells and Projects by Discharging and Zero Discharge Basins

Basin

Number of 

Wells

Percentage of 

Total Wells

Number of 

Projects

Average Wells 

per Project

Discharging Basins

PRB 21,000 38% 220 100

Green River 3,700 7% 5 750

Raton 320 1% 15 25

Black Warrior 5,200 9% 15 350

Cahaba 400 1% 2 200

Appalachian/Illinois 6,200 11% 30 200

Total Wells (Discharging Basins) 37,000 66% 280 130

Zero Discharge Basins

San Juan 7,000 13% 200 35

Uinta-Piceance 1,000 2% 15 80

Anadarko 2,800 5% 35 80

Arkoma 2,400 4% 180 15

Cherokee/Forest City 5,300 9% 40 130

Other 80 0% 4 20

Total Wells (Zero Discharge Basins) 18,600 33% 474 40

Total Wells, U.S. 56,000 750 75

Source: U.S. EPA, 2010a. 

Note: Unless less than 5, all numbers are rounded to nearest 5, 10, or 100. Totals are independently rounded.

 

13 See (ERG, 2010) for how the data presented here were modified to protect CBI.

14 Because wells can produce water before producing gas, screener respondents were asked to report numbers of 

wells that were producing either water or gas.
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Table 3-11. Characteristics of Discharging vs. Zero Discharge Projects

Type of Project

Number 

of Wells

Number 

of 

Projects

Gas Produced 

(2008) (Bcf)

Wells per 

Project

Gas per 

Well 

(MMcf)

Gas per 

Project 

(Bcf)

Discharging Projects

PRB 17,600 150 512 120 29 3.4

Green River 80 3 7 30 87 2.3

Raton 2,800 3 99 930 35 32.8

Black Warrior 5,100 15 104 400 20 8.0

Cahaba 400 2 4 200 10 1.9

Appalachian and IL 3,400 10 80 300 24 7.3

Total Discharging Projects 29,300 180 805 160 27 4.4

Zero Discharge Projects Operating Within Discharging Basins a

PRB 3,700 70 95 50 26 1.4

Green River 250 10 6 25 27 0.6

Raton 950 2 30 475 32 15.1

Black Warrior 15 1 <1 15 28 0.4

Appalachian and IL 2,800 20 64 150 23 3.4

Total Zero Discharge Projects in 

Discharging Basins

7,700 100 196 75 26 1.9

Zero Discharge Projects Operating Within Zero Discharge Basins

San Juan 7,000 200 755 35 107 3.8

Cherokee/Forest City 5,300 40 79 130 15 2.0

Uinta-Piceance 1,000 15 65 80 64 5.0

Arkoma 2,400 180 66 15 28 0.4

Anadarko 2,800 35 18 80 6 0.5

Other 70 4 3 20 48 0.9

Total Zero Discharge Projects in 

Zero Discharge Basins

18,600 470 987 40 53 2.1

Total Zero Discharge Projects, All 

Basins

26,200 570 1,183 45 45 2.1

Total, U.S. 56,000 750 1,988 75 36 2.6

Source: U.S. EPA, 2010a. 

Note: Most numbers are rounded to nearest 5, 10, 100, or 1,000, unless less than 5. Totals are independently 

rounded.

a – A discharging basin is defined as one that has at least one discharging project operating within it. However, zero 

discharge projects may also be operational within these basins as well.

3.5.2 Financial Characteristics of CBM Projects 

As with any business, CBM project revenues received must cover the costs of production 

or it is not economical to produce the project. Additionally, for planned projects not yet 

constructed, the estimated operating cash flow over time must be able to cover all of the costs of 

the project from inception to end of life. Operating cash flow is revenues to all of the working 

interest owners minus their combined share of the costs of production, including produced water 
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management costs over the assumed production lifetime of the project. The cash flow must be 

positive over this time frame and must also cover the projected investment costs (e.g., costs of 

preparing the site, drilling the wells, constructing and installing the production (including 

produced water management) infrastructure, as well as provide some return to the investors to 

cover the cost of capital15

Once a project is constructed and begins operating, it will continue to be operated as long 

as cash flow is positive (allowing for possibly a few years of negative cash flow initially as the 

coalbed is dewatered and potentially little gas is produced). Thus, key financial characteristics of 

existing CBM projects are project revenues and production costs (including produced water 

management). The key financial characteristics of new CBM projects include the total 

investment costs of the project, as well as the annually occurring revenues and production costs. 

 and risk (new oil and gas ventures of any type are risky investments). 

If the operating cash flow over the estimated project operating life is not expected to cover the 

investment costs with a reasonable return to investors, the project will not be undertaken. 

3.5.2.1 Project Revenues

Project revenues depend on the amount of gas produced from the project and the price 

received for that gas. Using preliminary EPA questionnaire responses, EPA was able to 

approximate the average revenues per project that were likely to have been earned, by basin, 

using the wellhead price of gas from publicly available sources and production volumes reported 

in EPA’s screener survey. Wellhead price is the price received by the interest owners at the 

wellhead (that is, net of additional gathering, transportation, and other costs which reduce the 

price from that seen at the major gas gathering hubs). The U.S. Department of Energy’s EIA (US 

U.S. DOE EIA 2010c) provides the average wellhead prices for gas in 2008 by state for most oil 

and gas producing states. 

Table 3-12 presents average wellhead prices received in 2008 in some of the key CBM 

basin states. These prices range from a high of $9.65 per thousand cubic feet (Mcf) in Alabama 

to a low of $6.94 per Mcf (New Mexico, Colorado). The high wellhead price in Alabama results 

in part from the state’s proximity to Henry Hub, which is the major gas distribution hub and 

pricing point for gas futures in the United States. This hub, which is the intersection of a number 

of large pipelines, is located in Louisiana. The higher the transportation cost, the lower the 

wellhead price received by the operators. Because transport costs from states located near 

Louisiana are much lower than those from the Rocky Mountain area, the average wellhead price 

in Texas, Louisiana, and Alabama is much higher than in the Rocky Mountain states. 

Table 3-12. 2008 Wellhead Prices ($/Mcf)

Basin Wellhead Price ($/Mcf) State Wellhead Price Used

Anadarko $7.96 OK

Appalachian a $7.96 U.S.

Illinois $7.96 U.S.

Arkoma $7.96 OK

Black Warrior $9.65 AL

 

15 For example, borrowing money has a cost, expressed as interest payments. 
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Table 3-12. 2008 Wellhead Prices ($/Mcf)

Basin Wellhead Price ($/Mcf) State Wellhead Price Used

Cahaba $9.65 AL

Cherokee/Forest City $8.40 KS

Green River $6.94 CO

Arkla $8.73 LA

Permian/Ft. Worth $8.51 TX

Wind River $6.86 WY

Powder River $6.86 WY

Raton $6.94 CO

San Juan $6.94 NM

Uinta-Piceance $6.94 CO

Source: U.S. DOE EIA, 2010c.

a – Individual prices by state were not available.

EPA multiplied the relevant questionnaire responses for gas production in each basin (see 

Table 3-2) and per project (see Table 3-11) by the relevant wellhead price in each basin shown in 

Table 3-12. In this way, EPA estimated the total 2008 gross revenues (revenues to all interests) 

associated with CBM production nationally, for each basin, and per project in each basin (see 

Table 3-13).

Table 3-13. 2008 Estimated Gross Revenues ($millions) by Basin, Discharging Basins vs. 

Zero Discharge Basins

Basin Gross Revenues/Project Total Gross Revenues by Basin

Discharging Basins

PRB $19 $4,163

Green River $7 $93

Raton $179 $893

Black Warrior $72 $1,006

Cahaba $18 $36

Appalachian and IL $38 $1,146

Discharging Basins Average/Total $26 $7,338

Zero Discharge Basins

San Juan $26 $5,241

Cherokee/Forest City $17 $662

Uinta-Piceance $35 $453

Arkoma $3 $528

Anadarko $4 $144

Other $6 $26

Zero Discharge Basins Average/Total $15 $7,054

Source: EPA estimates (see text).
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In 2008, EPA estimates that total gross revenues for CBM were about $14 billion. Of 

these revenues, approximately $7.3 billion (51 percent) was generated in discharging basins and 

approximately $7 billion (49 percent) was generated in zero discharge basins. Average revenues

per project over all projects were estimated to be about $21 million. In discharging basins, 

average revenues per project were estimated to be about $26 million and in zero discharge 

basins, average revenues per project were estimated to be about $15 million. 

Note that these estimated revenues are gross revenues that are shared among working 

interest operators, royalty owners, and state and local governments. Typical royalty payments 

might range from 10 to 20 percent of gross revenues; state and local taxes might consume several 

additional percentages. Thus the percentage of revenues received by all working interest 

operators (including a 100 percent interest owner) might be less than 80 percent of the gross 

project revenues. .

The per-project estimated gross revenues range from $3 million per project in the 

Arkoma Basin (where number of wells per project tends to be smaller) up to $179 million per 

project in the Green River Basin (where number of wells per project are among the highest). 

Table 3-14 presents similar gross revenue information, but identifies the estimated 

average gross revenues per project depending on whether the projects are discharging or zero 

discharge projects. For discharging projects, the average gross revenues per project in 2008 were 

estimated to be about $33 million, whereas for zero discharge projects, the average gross 

revenues per project were estimated to be about $15 million. There are more than three times as 

many wells, on average, at discharging projects than at zero discharge projects (see Table 3-11), 

which explains much of the difference in estimated average revenues per project between 

discharging and zero discharge basins and projects. Given that the amount of gas produced per 

well at discharging projects tends to be lower on average than the amount of gas produced per 

well at zero discharge project (and thus revenues per well are likely to be lower), the size of the 

projects is most likely the major factor in this difference (see Table 3-11).

Table 3-14. Estimated 2008 Gross Revenues ($millions) by Basin, Discharging Projects vs. 

Zero Discharge Projects

Basin Average Gross Revenues/Project Total Gross Revenues by Basin

Discharging Projects

PRB $24 $3,513

Green River $16 $49

Raton $228 $684

Black Warrior $77 $1,002

Cahaba $18 $36

Appalachian and IL $58 $636

Discharging Projects Average/Total $33 $5,920

Zero Discharge Projects

PRB $9 $650

Green River $4 $45

Raton $105 $209
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Table 3-14. Estimated 2008 Gross Revenues ($millions) by Basin, Discharging Projects vs. 

Zero Discharge Projects

Basin Average Gross Revenues/Project Total Gross Revenues by Basin

Black Warrior $4 $4

Appalachian and IL $27 $510

San Juan $26 $5,241

Cherokee/Forest City $17 $662

Uinta-Piceance $35 $453

Arkoma $3 $528

Anadarko $4 $144

Other $6 $26

Zero Discharge Projects

Average/Total

$15 $8,473

Source: EPA estimates (see text).

Note that wellhead prices can be slightly less at CBM projects on average than at 

conventional oil and gas leases because CBM projects are sometimes located in areas with less 

developed pipeline infrastructure (and therefore greater transportation costs). However, this is 

becoming a less important issue. In recent years, several pipelines have been constructed in the 

Rocky Mountain area, which has historically been underserved. Two of these pipelines, the 

Cheyenne Plains Pipeline and the Rockies Express Pipeline, have substantially increased 

transport capacity in Colorado and Wyoming. The Colorado Interstate Pipeline Company’s 

Cheyenne Plains Pipeline, which was built in 2004 and has the capacity to transport over 730 

MMcf per day, transports natural gas from production sites in these states to southwestern 

Kansas through an interconnection with Northern Natural Gas and Natural Gas Pipeline 

Company of America (U.S. DOE EIA, 2010d). The largest boost to carrying capacity in the 

Rockies region, however, was the addition of the Rockies Express Pipeline System, with a 1.8 

Bcf/day capacity. The second segment of the pipeline was placed in service in 2007 and was 

fully operational in November 2009, becoming the first direct transport from the Rocky 

Mountain region to the Midwest and Northeast (KinderMorgan, 2010). 

Due to increasing access to pipelines with sufficient capacity, EPA believes the average 

wellhead prices used in these estimates reasonably approximate prices received by CBM projects 

in 2008 and do not substantially overstate average 2008 revenues reported in this profile of CBM 

project finances. 

It is, however, important to note that 2008 wellhead gas prices were at an historic high. In 

2009, the price of gas dropped substantially. The U.S. average dropped from $7.96 per Mcf to 

$3.71 per Mcf, a 53-percent reduction (U.S. DOE EIA, 2010c). Therefore, average revenue per 

project in 2009 also are expected to have declined substantially, although the exact declines are 

difficult to estimate given expected production declines from existing wells combined with 

additions to production from new wells at CBM projects. Section 3.6 discusses wellhead price 

trends in more detail.
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3.5.2.2 Project Costs

Balanced against the estimated project revenues are the total investment costs of the 

project and gas production costs. Total investment costs include costs to acquire leases, prepare 

the site, drill wells, and construct and install production equipment and piping. Gas production 

costs include energy and labor costs to extract the gas and produced water management costs, 

including treatment and disposal. 

EPA’s detailed questionnaire data on production costs are not yet available. However, 

U.S. DOE EIA (2010e) provides a cost study of four primary CBM basins, including the 

Appalachian, Black Warrior, Powder River, and San Juan Basins. In this cost study, EIA 

characterizes 10-well leases dewatered by artificial lift (that is, using pumping systems, rather 

than natural flow) for each of the four basins. Table 3-15 presents the basic assumptions used in 

their costing assumptions for each of these leases (a 10-well lease in these basins is generally 

smaller than a typical project, as defined in EPA’s surveys, in most cases). As this table shows, 

the PRB is modeled as having leases with the shallowest wells, a moderate level of gas 

production per well, and the highest produced water production per well among the four basins 

investigated. San Juan leases are modeled assuming the deepest wells, highest gas production per 

well, and a relatively modest water production per well. Leases in the Appalachian Basin are 

assumed to have the least-productive wells. Black Warrior is a moderate case in all categories.

Table 3-15. Assumptions Used in U.S. DOE EIA Cost Models for Four Key CBM Basins

Basin Well Depth (ft) Dewatering Method

Per Well

Gas Production 

(Mcf/day)

Water Production 

(barrels/day)

Appalachian 2,000 Sucker Rod 60 20

Black Warrior 2,000 Sucker Rod 100 43

PRB 1,000 Submersible 100 300

San Juan 3,000 Sucker Rod 500 20

Source: U.S. DOE EIA, 2010e.

Based on these assumptions, U.S. DOE EIA (2010e) estimated two major cost categories 

associated with CBM production: equipment costs and operating and maintenance (O&M) costs. 

These costs are developed for the assumed 10-well leases in each of the four basins for 2002 and 

2006 through 2009 to assist in developing cost indices for CBM production. Table 3-16. 

summarizes these cost estimates for 2008 by basin. As the table shows, O&M costs are the 

lowest in the Appalachian Basin and highest in the San Juan Basin, while equipment costs are 

lowest in the Powder River Basin and highest in the San Juan Basin. U.S. DOE EIA (2010e) 

notes that produced water management costs make up a large portion of the estimated operating 

costs. Therefore, the high operating costs (as well as high equipment costs) seen in San Juan 

Basin are, in part, driven by the costs of the zero discharge management practices used there 

(injection, which drives both equipment and operating costs, and commercial disposal), even 

though volumes of produced water generated per well are relatively low. The relatively high 

operating costs in PRB are likely caused by managing the high volumes of produced water 

generated per well. Lower volumes of produced water per well in the Appalachian might help 

keep the operating costs in that basin low, while the predominance of surface water discharge in 
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the Black Warrior Basin might explain the more moderate operating costs estimated by U.S. 

DOE EIA in that basin. 

Table 3-16. Operating Costs and Costs of Equipment Assuming a 10-Well Lease in Four

Key CBM Basins (2008) 

Costs ($2008)

Basin

Appalachian Black Warrior PRB San Juan

Equipment

Producing Equipment $383,700 $426,700 $171,000 $868,700

Gathering Lines $218,000 $170,800 $237,100 $48,500

Lease Equipment $323,400 $443,100 $296,700 $373,500

Total Equipment $925,100 $1,040,600 $704,800 $1,290,700

Operating and Maintenance

Normal Daily Expense $32,300 $53,000 $48,300 $130,000

Surface Maintenance $43,800 $40,700 $37,000 $36,800

Subsurface Maintenance $11,700 $41,500 $86,600 $46,200

Total O&M $87,800 $135,200 $171,900 $213,000

Source: U.S. DOE EIA, 2010e. Assumptions used in these cost estimates appear in Table 3-15. 

3.5.3 Operators of CBM Projects

3.5.3.1 Numbers, Size, and Discharge Status of CBM Operators

Operators of any type of oil or gas project can be classified as either majors or 

independents. Majors are large, vertically integrated firms (i.e., they own production, 

distribution, and/or wholesale or retail distribution facilities). Generally, majors have the easily 

recognizable names associated with oil and gas production (e.g., Chevron, ConocoPhillips, 

Marathon), because these companies often own retail distribution firms. Independents focus 

primarily on the upstream activities associated with production. Most CBM operators are 

independents, but a few majors are involved in CBM production, including Chevron, 

ConocoPhillips, Marathon, EQT Corporation, Suncor Energy, Inc., and Williams Companies.16

EPA’s screener survey indicates that there were 252 operators of CBM projects in the 

United States in 2008 (U.S. EPA, 2010a). Operators of CBM projects can be the owners of the 

project or contract operators. Owner operators own some portion of the project, known as a 

“working interest,” which can range from 100 percent to a small fraction of the project. In this 

situation, the operator is responsible for a share of the cost, but also receives the an equivalent 

share of production and the resulting revenues. As noted earlier, even when an operator owns 

100 percent of the working interest, the operator does not own all production (and revenues) 

from a project. The nonworking interest owners (also known as owners of passive interests) also 

share in the production, but do not share in any of the costs of production. Nonworking interest 

 

 

16 Several sources identify majors, but they do not always agree on who is a major. Generally, majors are defined as 

large multinational firms with significant ownership of both upstream (production) and downstream (refining, 

distribution) assets. For this profile, ERG used Yahoo Finance (2010) and Reuters (2010). DOE also defines majors, 

but their definition is more related to size than to integration.
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owners include the mineral rights owners, who receive royalties. Additionally, state and local 

taxes on production are usually expressed in terms of a share of production (e.g., severance or ad 

valorem taxes), which also reduce the portion of production received by the working interest 

owner(s).

Contract operators, on the other hand, share none of the production or costs but are paid 

to operate the project for the working interest owners. This situation can happen when, for 

example, a working interest owner comprises a group of investors who themselves are not 

familiar with the production process. A preliminary investigation of EPA’s detailed survey 

questionnaire responses indicates that relatively few CBM operators are strictly contract 

operators. 

Another important distinguishing feature of CBM operators is whether they are small 

businesses, as defined by the Small Business Administration (SBA). EPA’s screener survey 

asked operators to self-identify as small or large businesses, using the SBA definitions of small 

business based on the type of business associated with their firm’s major source of income at the 

highest corporate level (e.g., a parent company). Most of the CBM operators are likely to be in 

the oil and gas production or well drilling industries (NAICS 211111 or 213111). Small firms in 

these industries must have fewer than 500 employees. For other industries (e.g., oil and gas 

support activities [NAICS 213112], which would include contract operators), small firms must 

have less than $7 million in revenues (SBA, 2008). 

Eight operators claimed that their screener survey responses included confidential 

information on the size of the firm (which could not be replaced with public data), which 

precludes using their responses in the discussion that follows. Thus, any discussion on size of 

firms focuses on 244 operators whose data can be released. According to the screener survey 

responses, 194 operators were small businesses and 50 operators were large businesses. Of these 

244 operators, the large majority was small operators with zero discharge projects (162 of 244, 

or 68 percent). Only 32 small operators operate discharging projects. Table 3-17 summarizes the 

numbers of small and large operators and the discharge status of their projects. 

Table 3-17. Number of CBM Operators by Size of Firm

Discharge Status Large Small Total

Discharging 21 32 55

Zero Discharge Only 29 162 197

Total a 50 194 252

Source: U.S. EPA, 2010a. 

a – The number of large and small operators by discharge status does not add to totals because eight operators are 

not included in the business size columns for CBI reasons, although their discharge status is not CBI. 

The discharge status of the eight CBI operators can be discussed, and EPA included these 

operators in Table 3-18. 17

 

17 Discharge status, even if claimed CBI, is not considered by EPA to be information subject to claims of 

confidentiality.

 Two CBI operators operate discharging projects and the other six 

operate only zero discharge projects. With these operators added in, 55 of 252 total operators (22 

percent) operate discharging projects.. 
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Table 3-18 provides the numbers of operators by their basin location and discharge status. 

Note this table double-counts a number of operators because many operators have projects in 

multiple basins, so overall totals for dischargers and nondischargers are not shown. 

Table 3-18. Numbers of Operators by Discharge Status and Basin

Basin Discharging Operators a Zero Discharge Operators Only Total

PRB 35 29 64

Green River 3 5 8

Raton 3 2 5

Black Warrior 7 1 8

Cahaba 3 0 3

Appalachian and IL 6 10 16

San Juan 0 56 56

Cherokee/Forest City 0 36 36

Uinta-Piceance 0 9 9

Arkoma 0 41 41

Anadarko 0 32 32

Other 0 4 4

Source: U.S. EPA, 2010a. 

a – Operators with at least one project in that basin directly or indirectly discharging at least some produced water to 

surface water.

3.5.3.2 Financial Characteristics of Firms Producing CBM

Table 3-19 summarizes key financial data from 2008 for public CBM firms using a 

compilation of financial information from nearly all publicly held U.S. oil and gas producing 

firms prepared by Oil & Gas Journal (OGJ, 2009). These firms are known as the OGJ 150 and 

the data on these firms also provide general financial benchmarks for the oil and gas industry for 

comparison to the CBM industry subset. EPA identified those firms among the OGJ 150 

operating or owning CBM wells and extracted their financial data. EPA added several additional 

foreign-owned or other firms that were not included in the OGJ compilation to Table 3-19 by 

extracting financial information from 20-F or 10-K forms available from the SEC. The year 2008 

is generally considered to be a better year for the oil and gas industry financially than 2009, due 

to higher gas prices realized during 2008 than 2009 (see Section 3.6.2), particularly in the first 

half of the year. However, as noted in the OGJ report (OGJ, 2009), despite increases in revenues, 

profits slid in the latter half of 2008 as prices and demand fell (OGJ, 2009), heading toward the 

low prices seen in 2009. 

EPA identified 34 publicly held firms that operate or own firms with CBM projects (and 

therefore are parent corporations). A few own more than one CBM operator. Of these 34 firms, 

seven are majors, 16 are large independents, and 11 are small independents (small defined by the 

SBA). A total of 16 firms are associated with firms that operate discharging projects; 18 are, or 

are associated with, firms that operate only zero discharge projects.

Table 3-19 indicates that majors and large independents in both groups (discharging and 

zero discharge) generally had positive net income. However, despite the high gas prices in 2008, 
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net income results for most small independents were poor. Only four small independents (all 

dischargers) in the publicly held group had positive net income in 2008. 

Table 3-19. Key Financial Information for Publicly Held CBM Firms (2008) 

Firms

Total 

Revenues 

($millions)

Net Income 

($millions)

Total Assets 

($millions)

Total Equity 

($millions)

Total Liabilities 

($millions)

Firms Owning Discharging Projects

Majors

Chevron U.S.A. $273,005 $23,931 $161,165 $86,648 $74,517

Suncor $28,637 $2,487 $32,528 $14,523 $18,005

The Williams Companies $3,121 $1,260 $10,286 NA NA

Large Independents

Anadarko $15,723 $3,261 $48,923 $18,795 $30,128

Devon $15,211 -$2,148 $31,908 $17,060 $14,848

El Paso $5,363 -$823 $23,668 $4,035 $19,633

Energen $1,569 $322 $3,775 $1,913 $1,862

Fidelity Exploration $712 $122 $1,793 NA NA

Range Resources $1,323 $346 $5,563 $2,458 $3,105

XTO a $7,695 $1,912 $38,254 $17,347 $20,907

Small Independents

Bill Barrett $620 $108 $1,995 $1,088 $907

Belden & Blake $158 -$29 $669 $77 $593

Continental Production 

Company

$960 $321 $2,216 $949 $1,267

Double Eagle Petroleum $50 $10 $172 $55 $117

GeoMet $69 -$22 $37, $192 $185

Penn Virginia $1,221 $124 $2,997 $1,019 $1,978

Firms Owning Only Zero Discharge Projects

Majors b

BP America $367,053 $21,666 $228,238 $92,109 $136,129

ConocoPhillips $246,182 -$16,998 $142,865 $55,165 $87,700

EQT $457 $253 $2,338 NA NA

Marathon Oil $78,569 $3,528 $42,686 $21,409 $21,277

Large Independents

Chesapeake $11,629 $723 $38,444 $16,297 $22,147

CNX $789 $239 $2,125 $1,385 $740

Dominion $4,312 $468 $11,100 NA NA

Layne Christianson $1,008 $27 $719 $456 $263

Newfield $2,225 -$373 $7,305 $3,257 $4,048

Noble Energy $3,901 $1,350 $12,384 $6,309 $6,075

Southwestern Energy $2,312 $568 $4,7608 $2,508 $2,2528

St. Mary Land & 

Exploration

$1,302 $92 $2,695 $1,127 $1,568
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Table 3-19. Key Financial Information for Publicly Held CBM Firms (2008) 

Firms

Total 

Revenues 

($millions)

Net Income 

($millions)

Total Assets 

($millions)

Total Equity 

($millions)

Total Liabilities 

($millions)

Unit Petroleum $1,358 $144 $2,582 $1,633 $949

Small Independents

Enerjex $4 -$5 $118 $1 $9

Petrohawk $1,095 -$388 $6,907 $3,405 $3,502

PetroQuest $314 -$97 $670 $237 $433

Rosetta Resources $501 -$188 $1,154 $726 $428

Warren Resources $109 -$242 $287 $112 $175

Source: OGJ, 2009; GeoMet, 2009; Suncor, 2009, BP, 2009; Reuters, 2010, Yahoo Finance, 2010. One company 

was eliminated as a major using corporate websites indicating that they considered themselves independents 

(Southwest Energy).

a – XTO was acquired by ExxonMobil in 2010. In 2008, it was considered an independent.

b – Majors were identified using Reuters, 2010, and Yahoo Finance, 2010, along with information on corporate 

websites indicating an integration or independent. 

NA – Not available.

The magnitude of these losses can be gauged using financial ratios. Financial ratios allow 

various financial items to be compared across firms or to be compared to a benchmark, such as 

industry averages. They are routinely used by financial analysts, investment firms, and financial 

rating organizations to judge firm financial health and to consider investments in the companies 

under review. The data available from OGJ are limited, but do allow some assessments of 

profitability and debt loads. 

EPA compared three key financial ratios for public CBM firms for 2008 to the overall 

2008 average ratios (where available) from all public oil and gas firms listed in OGJ (2009). Two 

ratios indicate profitability—return on assets (ROA) and net profit margin—and one assesses 

debt (debt-to-asset ratio). 

ROA is defined as net income divided by assets. It reflects the ability of an investment to 

generate income and whether the investment is reasonable given other possible returns on 

investments of similar risk. These returns can be compared to returns on the stock market (a 

somewhat risky investment) or the percent interest from interest-bearing accounts (relatively 

low-risk investments) to determine whether the returns seem good or poor compared to other 

possible investments. 

Net profit margin is computed as net income divided by revenues. This ratio can indicate 

how well a company controls costs, but more importantly, how well a company might weather 

an economic downturn. Those firms with net losses or low profit ratios in 2008 were at a greater 

risk of continued, deeper losses, or at risk of crossing over into losses in 2009, as gas prices 

continued their drop. A “good” profit margin in one industry might not be a “good” profit margin 

in another, and profit margins need to be compared to averages for the industry. 
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Table 3-20. Key Financial Ratios for Public CBM Firms Compared to the OGJ 150 (2008)

Firm Size Return on Assets Net Profit Margin

Net Profit Margin 

Among Profitable Debt to Asset

CBM Operators

Firms With Discharging Projects

Major 13.57% 9.08% 9.08% 47.77%

Large Independent 1.94% 6.29% 22.07% 59.49%

Small Independent 6.07% 16.62% 19.73% 59.90%

Firms With Only Zero Discharge Projects

Major 2.03% 1.22% 5.70% 59.23%

Large Independent 3.94% 11.22% 13.56% 53.57%

Small Independent -10.18% -45.45% NA 50.36%

OGJ 150 a

Major 10.19% 6.00% 7.63% 52.51%

Large Independent 1.27% 3.22% 14.97% 57.26%

Small Independent -5.77% -14.19% 31.68% 59.48%

Source: Reuters, 2010; Yahoo Finance, 2010; OGJ, 2009; see Table 3-19. 

a – Majors were identified using Reuters, 2010, and Yahoo Finance, 2010, along with information on corporate 

websites indicating an integration or independent status in calculating ratios for the OGJ 150. Firms not classified as 

majors with assets above $2 billion were used to construct ratios for large independents. The remaining firms were 

considered small independents. 

NA – Not available

The third ratio, the debt to asset ratio is calculated as total liability divided by total assets. 

It measures the ability of companies to take on more debt and whether they could be in difficulty 

if creditors began calling in debts. Very high debt-to-asset ratios indicate highly leveraged firms, 

which might have trouble finding additional capital or have potential for corporate takeover. 

Very low ratios, however, could mean that the firm is not taking advantage of leverage for 

growth. Assessing debt-to-asset ratios should take into account how the industry as a whole 

operates. Those with much higher debt-to-asset ratios than is typical for the industry might be 

less resilient in a downturn, whereas those with much lower ratios, while less likely to fail, might 

not be growing as quickly as they could. 

Table 3-20 presents these three ratios for the public CBM firms as compared to the Oil & 

Gas industry. As the table shows, CBM firms with discharging projects, regardless of size, 

generally appear to have higher profit margins (that is, they were more profitable) and better 

ROA in 2008 than similar-sized firms that operate only zero discharge projects (except for large 

independents). Because of large losses for some firms, which tended to overwhelm the averages, 

EPA also calculated profit margins over those firms that reported positive net income. When the 

profit margin was calculated only over those firms with positive net income, firms with 

discharging projects still appeared to have been more profitable, on average, than similar firms 

with zero discharge projects (including large independents). Furthermore, for the most part, firms 

with discharging projects had similar to better profitability and ROAs than similar-sized firms 

among the OGJ 150. Firms with zero discharge projects (except for large independents) tended, 

on average, to perform worse than the OGJ firms on net profit and ROA. These firms with zero 
Coalbed Methane Extraction:Detailed Study Report December 2010

3-35 

discharge projects, however, would not be affected by any changes to requirements for managing 

produced water from CBM projects. 

In terms of debt loads, firms with discharging projects on average had similar debt-toasset ratios as the overall OGJ 150, although majors with discharging projects tended to be less 

leveraged than average, but not substantially so. A ratio under 50 percent indicates a firm that 

uses equity more than debt to fund capital expenditures. Among the firms with zero discharge 

projects, the majors were, on average, more leveraged, but the remaining firm sizes tended to 

have lower than average debt-to-asset ratios than the OGJ 150. Therefore, on average, the 

publicly held CBM firms are not excessively leveraged compared to the overall industry. 

3.6

This section discusses the future economics of CBM production, including national-level 

production trends, wellhead gas price projections, and factors affecting the costs of production 

that could change over time, and the potential for the reserves of CBM in the currently developed 

basins to be produced in the future. These types of information are critical for determining the 

overall economics of a depletable resource such as CBM.

Trends and Projections

3.6.1 The Present and Future of CBM

U.S. DOE EIA indicates that 2008 was a recent-year peak in domestic production and 

consumption of natural gas (including CBM) (U.S. DOE EIA, 2010e). However, in 2009, both 

production and consumption of natural gas fell. Production by type of natural gas is not yet 

available for 2009, so it is not possible to determine from U.S. DOE EIA data if CBM production 

also declined in 2009. However, the Wyoming Oil and Gas Conservation Commission 

(WOGCC) data indicate that production of CBM in the Wyoming portion of the PRB (by far the 

most productive portion of the basin and a major contributor to total CBM production in the 

United States) rose between 2008 and 2009 (WOGCC, 2010). EIA predicts a continuing decline 

in both domestic production and consumption of all natural gas for the next several years. By 

around 2015, consumption and domestic production will again begin to rise gently, with 

production slightly closing the gap with consumption and reducing imports. Figure 3-3 shows 

EIA’s predictions for the consumption and production of natural gas.

U.S. DOE EIA (2010e) also predicts that CBM production will remain roughly steady 

through 2035, despite the overall fall in production of natural gas predicted over the next few 

years. In the longer term, however, natural gas production of all types is expected to rise,

contributing to a slight decline in the percentage of natural gas attributable to CBM production. 

The largest growth categories of natural gas types are shale gas and conventional natural gas 

from Alaska (the result of predicted pipeline construction completion). Shale gas is by far the 

largest growth category and by 2035 might be close to total conventional onshore volumes (U.S. 

DOE EIA, 2010e). Figure 3-4 presents EIA’s predictions for production of natural gas by type. 
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Source: U.S. DOE EIA, 2010f.

Figure 3-3. Projections of Natural Gas Consumption and Supply

Source: U.S. DOE EIA, 2010f. 

Figure 3-4. Projections of Shares of Total Gas Production by Type 
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3.6.2 Wellhead Gas Price Projections

Wellhead gas prices reached an historic peak in 2008, averaging $7.96/Mcf in the United 

States (for all gas, regardless of origin). In 2009, partly due to the recession, prices fell to the low 

point of the decade (averaging $3.71/Mcf). U.S. DOE EIA (2010e) predicts that wellhead prices 

will begin to recover in 2010, rising to about $5/Mcf in 2012 and about $5.50/Mcf in 2015. 

Prices will reach $6/Mcf in about 2020 (see Figure 3-5). 

Source: U.S. DOE EIA, 2010e.

Figure 3-5. Projections of Natural Gas Wellhead Price 

For 2010, through April, EIA shows a modest increase in the average monthly wellhead 

price each month on a year-over-year basis (U.S. DOE EIA, 2010e). Wellhead gas prices usually 

rise in the winter and decline in the summer following spikes and troughs in demand. Therefore, 

the average wellhead prices for the same month each year (e.g., January 2009 to January 2010) 

should be compared to accurately assess any trends. Table 3-21 shows the recent data on average 

U.S. wellhead price from 2008 to April 2010. As the table shows, prices in early 2010 are nearly 

unchanged at about 70 cents/Mcf higher than they were in the same month in 2009, but still 

substantially below the wellhead prices shown for 2008. 

Basis differentials must be considered if projections of wellhead price are applied to 

individual projects in different parts of the United States. Basis differentials reflect the factors 

that make costs to individual projects different from the average U.S. wellhead prices shown in 

U.S. DOE data (e.g., transportation cost differences). Some of this differential can be seen in the 

differences between the U.S. average wellhead price and the wellhead prices by state shown in 

Table 3-12. 
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Table 3-21. Average Monthly U.S. Wellhead Price, 2008–2010

Month 2008 2009 2010

Difference 

2008-2009

% Change 

2008-2009

Difference 

2009-2010

% Change 

2009-2010

January $7.16 $5.15 $5.14 ($2.01) -28.1% ($0.01) -0.2%

February $7.71 $4.19 $4.89 ($3.52) -45.7% $0.70 16.7%

March $8.44 $3.72 $4.36 ($4.72) -55.9% $0.64 17.2%

April $9.04 $3.43 $3.92 ($5.61) -62.1% $0.49 14.3%

May $10.15 $3.45 ($6.70) -66.0%

June $10.79 $3.45 ($7.34) -68.0%

July $11.32 $3.43 ($7.89) -69.7%

August $8.34 $3.14 ($5.20) -62.4%

September $6.72 $2.92 ($3.80) -56.5%

October $5.50 $3.60 ($1.90) -34.5%

November $4.75 $3.64 ($1.11) -23.4%

December $5.52 $4.44 ($1.08) -19.6%

Source: U.S. DOE EIA, 2010c.

3.6.3 Trends in Costs of Production 

A number of trends could affect the costs of production, some long-term, some only 

short-term. Each of these types are discussed in the sections below. 

3.6.3.1 Short-term Trends

Short-term trends include easing of supply constraints on materials and labor triggered by 

low gas prices (there are few demands for drilling rigs, pipe, and operating labor when gas prices 

are low), but this is offset by tight credit, such as that experienced in the recent recession. As 

prices recover, supply might go down, driving up prices; continuing tight credit could diminish 

this short-run price effect, however. 

U.S. DOE EIA (2010e) discusses some trends in costs of CBM production over much of 

the last decade that provide some insight into potential short-term trends. According to this 

source, costs of production (as defined in Section 3.5.2.2), including lease equipment and O&M 

costs, have risen steadily. However, these costs fell in 2009 as the plunge in gas prices reduced 

demand for lease equipment. Operating costs were also reduced in most areas due to reduced fuel 

costs; well-servicing costs also generally fell. The only exception to the reduction in operating 

costs was the rising cost of electricity in the Powder River and the Appalachian Basins, which 

increased operating costs in these basins in 2009. In the four basins (Appalachian, Black 

Warrior, Powder River, and San Juan Basins) studied by U.S. DOE EIA (2010f), O&M costs 

rose overall an average of 8 percent in 2008 and fell by 1 percent in 2009. Equipment costs rose 

16 percent and fell 10 percent in 2009. 

As seen in the last two years, costs of production tend to rise and fall as gas prices rise 

and fall. This relationship between costs and gas price can also be seen in Figure 3-6, which 

shows the longer-term relationship between cost and price for conventional gas production (the 

same general principal should hold true for CBM). As the figure shows, in years with low gas 
Coalbed Methane Extraction:Detailed Study Report December 2010

3-39 

prices, costs tend to be lower, and in years with high prices, costs tend to be higher. Thus, 

assuming that credit eases, and given that prices are expected to rise modestly over the next few 

years, EPA expects that costs of production might also tend to rise modestly over the short run. 

Figure 3-6. Indices for Gas Equipment and Annual Operating Costs and Gas Prices in Real

1976 Dollars 

3.6.3.2 Long-term Trends

Key long-term factors affecting costs of production include availability of pipelines to 

transport CBM to central distribution hubs, the number of years over which development has 

occurred in a region, technology changes, and project-specific trends such as potential decreases 

in produced water production over time. 

The most important factors for analyzing long-term effects of increased costs of 

production due to potential new regulatory requirements are the long-term trends. These longterm trends, however, tend to move costs in opposite directions. Increased access to pipeline 

transportation tends to lower costs of transportation, as demand for pipeline capacity no longer 

outstrips its supply. This contributes to a lower basis differential and thereby a higher wellhead 

price by which to offset costs. 

Years of development in a basin also can affect long-term production costs. As easy-toreach coalbeds are tapped, future development relies on producing from deeper coalbeds, thinner 

coalbeds (e.g., those that are only a few feet thick), “tighter” coalbeds (those with fewer spaces 

that allow gas to escape easily), or coalbeds with lower-rank coals (with less gas), all of which 

can be more expensive to produce and/or generate lower revenues. Deeper coalbeds require 

deeper wells, taking longer to drill and requiring more piping and often more energy to bring the 

gas to the surface. Tighter coalbeds might require special treatment before they are produced 

(hydrofracturing—a method of opening up additional cracks in the coal seam to allow gas to 
Coalbed Methane Extraction:Detailed Study Report December 2010

3-40 

escape more readily—is an additional expense if tighter coalbeds are to be produced 

economically [U.S. EPA, 2004b]). 

Also affecting long-term trends in costs are changes in technologies in producing CBM 

(e.g., multiseam completions and horizontal drilling), although these changes can have an 

uncertain effect on long-term cost trends. These technology changes can increase total costs, but 

reduce costs per Mcf of gas produced. Multiseam completions allow several coalbeds at varying 

depth to be produced at the same time (U.S. DOE, 2003) or can be used to add CBM to a 

conventional oil and gas project when the well passes through a coal seam. Horizontal wells can 

be drilled laterally through a coalbed, increasing the length of well in contact with the coalbed 

(E&P, 2007). This latter method can allow thin coalbeds, once dismissed as uneconomical, to be 

produced. Both of these technologies can be used to produce more gas from one well, potentially 

lowering the cost per Mcf to produce the gas. 

3.6.4 The Future of Existing Basins

EPA investigated the potential for CBM production in the key discharging basins to 

consider the potential for new projects and continued long-term production from existing 

projects. Table 3-22 summarizes estimates of the technically recoverable resources within each 

of the major discharging basins (except Green River) and presents information on recent well 

drilling and production trends and expected future trends. Additionally, it summarizes an 

assessment of how accessible the remaining resources are and how accessible the gas is to key 

market hubs (ARI, 2010b). 

In general, the PRB is the discharging basin with the most resource potential, even under 

conservative estimates. Adding major pipeline capacity (especially the recent 1.8 Bcf/day 

addition) has increased the access of PRB CBM to major markets, increasing the potential for 

production. The Appalachian and Raton Basins also show increases in drilling and production 

trends, but Black Warrior/Cahaba, the basin with some of the oldest CBM development, might 

be at or close to a peak in drilling and production (ARI, 2010b). 

Table 3-22. Summary of Information Important to Future Production Trends in the 

Major Discharging Basins 

Basin

Resource 

Potential Well Drilling Production Resource Access Market Access

PRB ~14-52 Tcf 

might be 

technically 

recovered, 

mostly in the 

Big George 

coal horizon 

in Wyoming.

After reaching a 

peak of over 3,500 

wells drilled in 

2001, drilling has 

remained at 2,000– 

2,500 wells/year 

for the past six 

years.

Rapid increase 

1997–2000 with

slower growth 

2001–2006 as 

produced water 

issues limited new 

drilling. As drilling 

resumed, 

production 

increased again.

43% of CBM 

resource underlies 

federal lands; 6% of 

the CBM resource in 

PRB is off limits to 

all development; 

21% is subject to 

federal leasing 

restrictions that limit 

development during 

certain months.

In 2000, Cheyenne Hub 

began gas transport but 

access to markets was 

limited by lack of 

capacity and 

unfavorable basis 

differentials. Addition 

of Rockies Express 

Pipeline has added 

substantial capacity.
Coalbed Methane Extraction:Detailed Study Report December 2010

3-41 

Table 3-22. Summary of Information Important to Future Production Trends in the 

Major Discharging Basins 

Basin

Resource 

Potential Well Drilling Production Resource Access Market Access

Appalachian~8.4–9.3 Tcf 

might be 

technically 

recoverable 

from West 

Dunkard and 

Pocahontas 

formations.

Drilling was 

steady 1997 to 

2003, rising in 

2004 and peaking 

in 2006, but 

expected to remain 

high.

Rising since 2003, 

and should 

continue. Activity 

mostly in Central 

Appalachian Basin.

2% underlies federal 

lands; 1% is 

inaccessible and 1% 

is accessible with 

restrictions on 

drilling. A small 

portion of the 

resource underlies 

state government 

lands.

Favorably located near 

major pipelines to 

northeastern markets; 

near Dominion South 

Point Hub. Usually a 

negligible or slightly 

positive basis 

differential.

Black 

Warrior/

Cahaba

~5.1–7.0+ Tcf 

might be 

technically 

recoverable.

Drilling increased 

steadily 1997–

2006, then 

declined. Expected 

to remain 

relatively high.

Remained steady 

from 1997–2006. 

May not be 

sustainable in the 

future.

4% classified federal 

lands, 2% 

inaccessible to 

leasing. Small 

portion underlies 

state government 

lands.

Favorably located near 

major pipelines 

transporting gas from 

Gulf Coast to 

northeastern markets.

Raton ~1.59–8.2 Tcf 

might be 

technically 

recoverable. 

Drilling increased 

steadily 1998–

2007, after which 

it has declined.

Steady increase 

1998–2007; peak 

should be 

maintained for 

foreseeable future.

Much CBM 

resource underlies 

federal lands, some 

inaccessible, some 

accessible under 

development 

restrictions.

Pipeline expanded in 

2005 from the Raton 

Basin into Oklahoma 

panhandle, and then 

again in 2008 from Las 

Animas County area to 

the Cheyenne Hub.

Source: ARI, 2010b.
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4-1 

4. ENVIRONMENTAL ASSESSMENT CONSIDERATIONS

CBM produced water is released to the environment when it is discharged directly to 

surface waters, managed using land application or irrigation, or stored in impoundments or 

constructed wetlands. The following sections describe the documented and potential 

environmental impacts associated with the discharge of CBM produced water and zero discharge 

with beneficial use management options. 

EPA conducted a broad, nationwide literature review of environmental impacts from 

CBM produced water discharges to identify the impacts discussed in this chapter. EPA identified 

and reviewed documents from the following information sources: 

• Peer-reviewed literature;

• State and federal agency reports;

• CBM site visit reports;

• CBM stakeholder meeting notes; 

• CBM permits;

• Nongovernmental organization (NGO) reports; 

• Industry publications; 

• News organization publications; and 

• University research.

In total, EPA identified over 1,000 documents and performed a detailed review of 452 of these. 

EPA selected publicly available peer-reviewed literature as well as state, federal, university, and 

news/industry/NGO articles that were publicly available. Table 4-1 summarizes the results of 

literature review by search category and type of environmental impact. 

Table 4-1. Summary of Literature Review Results by Search Category and Type of 

Environmental Impact 

Information 

Source

Number of 

Documents 

Identified

Number of 

Documents 

Examined 

in Detail

Number of 

Unique 

Documents 

That Discussed 

Environmental 

Impacts

Number of Documents by Impact Type a

Documented Potential

Nonsurface 

Water 

No 

Impact

PeerReviewed 

Literature

46 19 6 1 3 4 1

State and 

Federal

Agency 

Reports

467 116 38 1 25 24 8

CBM Site 

Visit Reports

22 22 5 0 2 2 3

CBM 

Stakeholder 

Meeting

Notes

41 41 5 0 3 1 3
Coalbed Methane Extraction:Detailed Study Report December 2010

4-2 

Table 4-1. Summary of Literature Review Results by Search Category and Type of 

Environmental Impact 

Information 

Source

Number of 

Documents 

Identified

Number of 

Documents 

Examined 

in Detail

Number of 

Unique 

Documents 

That Discussed 

Environmental 

Impacts

Number of Documents by Impact Type a

Documented Potential

Nonsurface 

Water

No 

Impact

NGO, News 

and Industry 

Publications

428 195 47 2 26 34 2

University 

Research

74 57 23 2 15 18 0

Total 1,078 451 124 6 74 83 17

a – Note that a document may discuss more than one impact type. Therefore, the sum of the number of documents 

by impact type may exceed the number of unique documents identified for a given information source.

4.1

EPA defines a documented environmental impact as an impact to stream water quality, 

morphology, or aquatic community that resulted from or was contributed to by the direct 

discharge of CBM produced water to a receiving stream. EPA’s literature review identified only 

a limited number of scientific studies documenting the environmental impacts of CBM produced 

water discharges on aquatic ecosystems (see 

Documented Impacts From the Direct Discharge of CBM Produced Water

Table 4-2). Several authors in the research field 

acknowledge that few studies have been conducted to specifically address the effects of CBM 

produced water on receiving streams (Davis et al., 2006; MacDonald, 2007; Wang et al., 2007). All 

of the identified studies concerned the PRB in Wyoming and Montana and the Black Warrior 

Basin in Alabama.

Some of the documented impacts focused on changes to fish species population diversity 

due to CBM produced water discharges. Two related papers, Davis et al., 2006, and Davis, 2008, 

investigated the impact of CBM discharges on fish assemblages in the PRB. Based on her review 

of relevant research and her own research, Davis found conflicting results regarding the impacts 

of CBM produced waters on fish. In her master’s thesis, Davis observed that CBM produced 

waters had some impact on fish assemblages (Davis, 2008). Specifically, she found decreased 

abundance of certain fish in streams with elevated bicarbonate. She also found decreasing biotic 

integrity18

 

18 Biotic integrity is the capability to support and maintain a balanced, integrated, adaptive community of organisms 

having a species composition, diversity, and functional organization comparable to that of the natural habitat of the 

region (Karr, 1981).

 in streams with increasing conductivity. (Increased conductivity and bicarbonate are 

characteristics of some CBM produced waters.) However, the same study found that species 

richness and biotic integrity were similar between sites with and without CBM discharges 

nearby. Davis also observed a weak relationship or none at all between overall index of biotic 

integrity scores and the number or density of CBM wells in a drainage area (Davis, 2008). These 

findings suggest that while CBM discharges overall had little effect on the fish present in the 
Coalbed Methane Extraction:Detailed Study Report December 2010

4-3 

receiving streams, elevated bicarbonate or conductivity—which are on average higher in streams 

that receive CBM produced water—may negatively affect fish assemblages over time. 

Table 4-2. Summary of Documented Impacts From the Direct Discharge of CBM 

Produced Water Cited in Peer-Reviewed Literature

Citation Impact Type Summary

O’Neil et al., 1991a 

(cited in Davis et al. 

2006)

Changes in 

communities of 

aquatic organisms

O’Neil et al. observed changes in fish species abundance and 

reproduction in response to water quality alterations resulting from 

CBM produced water discharges in the Black Warrior Basin. This 

suggests that CBM discharges are altering the aquatic environment 

and may cause permanent changes in species assemblages.

Davis, 2008 Changes in 

communities of 

aquatic organisms

In Davis’s comparison of streams in the PRB with and without 

CBM development, some results indicated that CBM discharges 

were impacting fish assemblages, while others showed no impact. 

Impacts tied to CBM produced water discharges included a 

correlation of increased conductivity with decreased biotic integrity, 

a correlation between decreased abundance of certain fish with an 

increase in bicarbonate, and the presence of the salt-tolerant 

northern plains killifish only in streams receiving CBM produced 

water discharges.

Confluence 

Consulting, 2004b 

(cited in Confluence 

Consulting, 2004a)

Changes in aquatic 

organisms and 

riparian plant 

communities

In a study of the effects of CBM development on fish and water 

quality, Confluence Consulting observed elevated levels of 

dissolved solids, reduced numbers of sturgeon chub in the Powder 

River, and a prevalence of salt-tolerant shrubs.

Vickers, 1990 Changes in 

communities of 

aquatic organisms 

In a study determining the effects of CBM produced water on 

surface waters of the Black Warrior Basin in Alabama, researchers 

from the University of Alabama observed a decrease of total 

macroinvertebrates as the in-stream chloride concentration at Shoal 

Creek increased. The decrease in taxa was not completely 

dependent upon chloride concentration, but may have been 

influenced by in-stream components and subsequent mixtures.

Mount et al., 1992 Changes in 

communities of 

aquatic organisms

In an in-stream study of surface waters in the Cedar Cove 

degasification field, the Geological Survey of Alabama (GSA) 

found no significant effects in streams on native invertebrates (acute 

toxicity of Ceriodaphnia) at chloride concentrations of 519 mg/L 

and below and consistent effects at chloride concentrations of 615 

mg/L and above.

O’Neil et al., 1993 Changes in 

communities of 

aquatic organisms

A GSA study found that environmental effects caused by CBM 

water discharges were related to TDS rather than metals or other 

constituents. This study concluded that elevated chloride levels in 

CBM produced waters from coal seams in Alabama were the main 

driver behind deleterious effects on stream conditions. Specifically, 

an in-stream limiting chloride concentration of < 565 mg/L had no 

significant effect on the community structure of benthic 

macroinvertebrates. In contrast, chloride concentrations of > 565 

mg/L in produced water always degraded or impaired the benthic 

macroinvertebrate community.

In a related review paper, Davis et al., 2006, cited a number of studies performed in the 

Black Warrior Basin in Alabama, where fish species diversity and biomass remained unchanged 
Coalbed Methane Extraction:Detailed Study Report December 2010

4-4 

following the discharge of CBM produced water (O’Neil et al., 1989, cited in Davis et al., 2006; 

O’Neil et al., 1991a, cited in Davis et al., 2006; Shepard et al., 1993, cited in Davis et al., 2006). 

However, O’Neil et al., 1991a (cited in Davis et al., 2006) observed water quality alterations 

from CBM discharges, resulting in changes in fish species abundance and reproduction that 

could cause permanent impacts to communities. 

These examples from Davis highlight both the limited number of scientific studies that 

have investigated the environmental impacts of CBM produced waters and their conflicting 

results. Overall, the data suggest that environmental impacts from CBM produced water 

discharges are likely to be site-specific and dependent upon the water quality of the produced 

water, type of species present, and the metrics used to evaluate the impacts on aquatic organisms.

Confluence Consulting, 2004b (cited in Confluence Consulting, 2004a) describes a study 

of the effects of CBM development on fish and water quality. Sampled sites along the Powder 

River with CBM discharges contained elevated dissolved solids concentrations compared to baseline 

conditions for the Powder River (USGS, 2006a). Sampling results also showed a rarity of sturgeon 

chub, a species of special concern, and encroachment of tamarisk, a salt-tolerant, introduced shrub 

that could outcompete the more desirable cottonwoods.

The remaining documented impacts focused on problems with the salinity of CBM 

produced water and its impact on aquatic vegetation and macroinvertebrate communities. The 

Geological Survey of Alabama (GSA) completed a study in 1993, which documented CBM 

produced water data collected during the late 1980s (O’Neil et al., 1993). The study tested 

numerous water quality parameters including dissolved oxygen, five-day biochemical oxygen 

demand (BOD5), TDS, turbidity, bicarbonate, carbonate, alkalinity, silica, metals (e.g., arsenic, 

barium, cadmium, chromium, cobalt, iron, lead, manganese, mercury, selenium, silver, 

strontium, zinc), calcium, magnesium, sodium, potassium, sulfate, chloride, fluoride, nitrate, 

ammonia, and orthophosphate. Dr. Pat O’Neil, GSA, stated that the study found that

environmental effects caused by CBM water discharge were related to TDS rather than metals or 

other constituents (U.S. EPA, 2007). Specifically, this study concluded that elevated chloride 

levels (above 565 mg/L) in CBM produced waters were the main cause of harmful effects on 

stream conditions. Dr. O’Neil noted that only small streams were included in this study, and 

postulated that any CBM produced water discharges into large rivers would be diluted, which 

may dampen any deleterious effects (U.S. EPA, 2007). 

Vickers (1990) describes a study conducted at an Amoco project area by the University 

of Alabama, Department of Mineral Engineering and Department of Biology, in 1989. The study 

found that, as the in-stream chloride concentration at Shoal Creek increased, total

macroinvertebrate taxa decreased. However, this was not found at the Fox Creek Test Site. 

Taxonomic richness (total species) was not affected by chloride in-stream concentrations at 

either site. Moreover, the study found that the decrease in total taxa did not completely depend 

upon chloride concentration, but may have been influenced by in-stream components and 

subsequent mixtures. Mount et al. (1992) describes an in-stream study of surface waters in the 

Cedar Cove degasification field conducted by the GSA from 1986 to 1988. Study results found 

no significant effects on native invertebrates in streams (acute toxicity of Ceriodaphnia) at 

chloride concentrations of 519 mg/L and below, and consistent effects at concentrations of 615 

mg/L chloride and above. 
Coalbed Methane Extraction:Detailed Study Report December 2010

4-5 

One of the limitations of studies conducted in CBM production basins is a lack of 

baseline conditions of streams established prior to CBM development and the discharge of 

produced water. Without adequate baseline information, the degrees of aquatic impacts are 

difficult to ascertain, especially given the seasonal variability of rainfall and consequent stream 

flow fluctuations (particularly in arid regions such as the PRB) and the natural occurrence of 

many contaminants of concern in produced water (e.g., chlorides and sodium) (Davis, 2008). 

4.2

EPA defines a potential environmental impact as an impact to stream water quality, 

morphology, or aquatic community that could potentially result from or be contributed to by the 

direct discharge of CBM produced water to a receiving stream. EPA’s literature review identified 

74 scientific studies, reports, and other sources describing potential environmental impacts from 

CBM produced discharges. The primary potential impacts include those to vegetation, water 

quality, and organisms due to changes in stream volume, turbidity, salinity, sodicity, SAR, TDS, 

specific conductance, toxicity, temperature, and pH. Some of these potential impacts are based 

on knowledge or observations of unrelated discharges with similar pollutant levels and the 

impacts from those pollutants.

Potential Environmental Impacts From the Direct Discharge of CBM Produced 

Water

A number of sources expressed concern over the potential for changes in stream water 

volume caused by CBM discharges to alter aquatic habitats. A higher receiving water volume 

can increase suspended sediment and streambed erosion, which can affect the aquatic organisms 

that inhabit these waters (Arthur, 2001; ALL, 2003; Arthur et al., 2001). Erosion can destroy 

vegetation within streams (ALL, 2003; Fisher, 2001; Regele and Stark, 2000), impacting aquatic 

biota that have particular flow requirements for food, habitat, and reproduction (RawnSchatzinger et al., 2004; Davis et al., 2006; Regele and Stark, 2000). Flow volume changes from 

CBM discharges can also increase turbidity, which might help invasive species outcompete 

native species under the new flow conditions (Davis et al., 2006; Bonner and Wilde, 2002, cited 

in Davis et al., 2006; Gradall and Swenson, 1982, cited in Davis et al., 2006). 

Another concern expressed in the literature is the potential for CBM discharges to alter 

salinity levels in receiving streams (also discussed with documented impacts in Section 4.1). 

Rawn-Schatzinger et al. (2004) suggest that salinity, along with sodicity and toxicity, are the 

biggest issues with CBM produced water discharges. Saline discharges from CBM produced 

waters can alter plant communities as native species are replaced with salt-tolerant species (Keith 

et al., 2003). However, not all locations are impacted equally by such water quality changes. For 

example, Stanford and Hauer (2003) noted that because the Tongue River is more dilute than the 

Powder River, CBM discharges with high salinity concentrations are more likely to cause 

detrimental effects on the Tongue River than the Powder River. Conversely, CBM produced 

water discharges can also impact aquatic species by diluting receiving waters with large volumes 

of less saline CBM produced water, thus altering the habitat for aquatic species that are 

acclimated to more saline waters (Clearwater et al., 2002, cited in MacDonald, 2007).

An elevated SAR value in CBM discharges can also affect aquatic systems (Confluence 

Consulting, 2004a; Osborne and Adams, 2005). Other components in CBM produced waters that 

are toxic to native plants and animals at elevated concentrations include ammonia, hydrogen 

sulfide, bicarbonate, selenium, TDS, chloride, and boron (Fisher, 2001; MacDonald, 2007; Rice 

et al., 2000, cited in Davis et al., 2006; ALL, 2003). Depending on species tolerance, impacts to 
Coalbed Methane Extraction:Detailed Study Report December 2010

4-6 

aquatic organisms can vary greatly with some species able to acclimate to the new environment 

more quickly than others (Davis, 2008; MacDonald, 2007). 

Several studies identified toxicity concerns from CBM produced water constituents 

ranging from sodium bicarbonate to pH to metals. Elevated concentrations of and exposure time 

to sodium bicarbonate, (a major constituent of CBM produced water in the Tongue and Powder 

River drainage basins) decreased fathead minnow survival, increased incidence of lesions and 

kidney damage, and may impact freshwater ecosystems by interfering with ion uptake by fish 

(USGS, 2006b). Increased water-quality variation from CBM discharges to a receiving stream, 

particularly with regard to pH, could potentially cause physiological stress to aquatic organisms 

(O’Neil et al., 1991b). In addition, streams receiving produced water tend to have increased 

concentrations of metals such as selenium, chromium, cadmium, copper, aluminum, and iron. 

Elevated selenium concentrations can potentially bioaccumulate in fish and migratory aquatic 

birds, causing effects such as low reproduction, increased mortality, and embryonic deformities 

(Ramirez, 2005, citing Ohlendorf et al., 1988). In PRB receiving wetlands, the U.S. Fish and 

Wildlife Service (U.S. FWS) measured cadmium and chromium concentrations that exceed the 

thresholds considered hazardous to aquatic life (U.S. DOI, 2005). The same study found iron, 

manganese, lead, and copper in CBM produced water discharges that were above concentrations 

that would impact fish and birds (U.S. DOI, 2005). 

A joint study by the Montana Department of Environmental Quality, Montana Fish and 

Wildlife, and EPA Region 8 estimated future water quality for streams receiving CBM produced 

water discharges in the PRB (Horpestad et al., 2001). To perform their analysis, the researchers 

estimated the potential number of new wells in PRB over a 20-year period and used historical 

data to estimate typical flow, discharge, conveyance loss, electric conductivity (EC), and SAR 

values for surface waters. The modeling results from the analysis suggest that CBM produced 

water discharges will significantly alter water quality in five of the seven rivers in the PRB over 

a 20-year period. The study concluded that the impacted rivers would likely be rendered 

unsuitable for irrigation based on predicted ratios of EC and SAR values in the receiving water, 

which exceed the threshold levels for no reduction in infiltration (Horpestad et al., 2001). 

Table 4-3. Scientific Studies Evaluating Potential Environmental Concerns From the 

Direct Discharge of CBM Produced Water

Citation Impact Type Summary

Clearwater et al., 2002 

(cited in MacDonald., 

2007)

Changes in water 

quality and aquatic 

communities

Changes in volume and salinity of water in receiving streams in the 

PRB can impact resident biota by disrupting environmental cues, 

which can alter reproduction and normal species behavior.

Patz et al., 2004 (cited 

in Davis et al., 2006)

Changes in water 

quality

The pH of CBM produced water may fluctuate due to atmospheric 

exposure following discharge to a receiving water in the PRB. 

These changes in pH can make downstream impacts difficult to 

pinpoint.

Horpestad, 2001 (cited 

in Todd, 2006)

Changes in water 

quality

In areas with minimal precipitation, such as eastern Montana, salts 

from CBM produced water can accumulate in surface waters.

Klarich et al., 1980 

(cited in Regele and 

Stark, 2000)

Changes in water 

quality

Raising the salinity of southeastern Montana waters above 1,200 

micromhos will potentially affect the biological health in streams 

receiving produced waters.
Coalbed Methane Extraction:Detailed Study Report December 2010

4-7 

Table 4-3. Scientific Studies Evaluating Potential Environmental Concerns From the 

Direct Discharge of CBM Produced Water

Citation Impact Type Summary

Forbes et al., 2002, and 

Forbes et al., 2001 

(cited in MacDonald et 

al., 2007)

Changes in water 

quality and aquatic 

communities

The water quality of CBM produced water and PRB receiving 

waters were linked to acute and chronic toxicity effects in 

Ceriodaphnia dubia, Daphnia magna, and fathead minnows.

Skaar et al., 2004 

(cited in Davis et al.,

2006)

Changes in water 

quality and aquatic 

communities

Exposure to sodium bicarbonate in reconstituted Tongue and 

Powder River water resulted in chronic and acute toxicity and 

mortality in fathead minnows.

Skaar et al., 2005 Changes in water 

quality and aquatic 

communities

Chronic exposure to sodium bicarbonate from simulated Tongue 

and Powder River water resulted in gill lesions, gill necrosis, and 

kidney damage in fathead minnows.

Ramirez, 2005 Changes in water 

quality, aquatic 

communities, and 

migratory bird 

communities 

The U.S. FWS (citing Ohlendorf et al., 1988) reported that streams 

receiving produced water tend to have increased selenium 

concentrations, which can impact fish and migratory aquatic birds 

due to bioaccumulation. Birds with increased selenium 

concentrations can have low reproduction, increased mortality, and 

embryonic deformities. In addition, any prior impoundment of the 

produced water before discharge to receiving waters can increase 

selenium concentrations even further due to evaporation.

Ramirez, 2005 Changes in water 

quality and aquatic 

communities

U.S. FWS (citing Eisler, 2000) found that cadmium concentrations 

in aquatic invertebrates from some CBM produced water receiving 

sites exceeded the 0.1 μg/g “view with caution” level. Chromium in 

tiger salamanders at a number of sites ranged from 18.6 to 137 μg/g, 

and chromium in fathead minnows ranged from 24.4 to 307 μg/g. 

(Chromium concentrations of 4 μg/g or greater are considered 

evidence of chromium contamination.)

USGS, 2006b Changes in water 

quality and aquatic 

communities

In a laboratory study, the USGS found that increased concentrations 

of, and exposure time to, sodium bicarbonate, a major constituent of 

CBM produced water in the Tongue and Powder River drainage 

basins, decreased fathead minnow survival, increased incidence of 

lesions and kidney damage, and interfered with ion uptake by fish.

USDOI, 2005 Changes in water 

quality and aquatic 

communities

The U.S. FWS measured cadmium concentrations ranging from 6.7 

to 9.3 μg/L in wetlands in the PRB that receive CBM produced 

waters, exceeding the threshold of 3 μg/L considered hazardous to 

aquatic life. Chromium concentrations were typically low, except 

for one wetland site where concentrations in fathead minnows 

ranged from 24.4 μg/g to 307 μg/g, greatly exceeding the 4 μg/g 

threshold considered hazardous.

USDOI, 2005 Changes in water 

quality, aquatic 

communities, and 

bird communities

In a PRB study by U.S. FWS that took place from 2000 to 2002, 

concentrations of iron, manganese, lead, and copper in CBM 

produced water discharges were above concentrations that would 

impact fish and birds.

Jackson and Reddy,

2007

Changes in water 

quality and aquatic 

communities

Most CBM produced water being discharged at outfalls into the 

PRB was considered unsuitable for aquatic life due to aluminum 

and copper concentrations greater than the water quality standards 

for aquatic life.
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Table 4-3. Scientific Studies Evaluating Potential Environmental Concerns From the 

Direct Discharge of CBM Produced Water

Citation Impact Type Summary

Mount et al., 1992 Changes in water 

quality

The results of a study funded by the Gas Research Institute at the 

Cedar Cove degasification field indicated that laboratory toxicity 

tests could be used to predict in-stream effects of CBM produced 

water. The study reported that the TDS concentration, specifically 

the chloride concentration, accounted for most of the toxicity 

associated with CBM produced water at the site.

O’Neil et al., 199b Changes in aquatic 

communities

CBM produced water discharges may account for some observed 

changes in fish abundance in the receiving waters of the Cedar 

Cove degasification field; however, the changes were within the 

range of variation observed under natural conditions.

Gore, 2002 Changes in water 

quality, aquatic 

communities, and 

morphology

A study by Columbus State University used model simulations to 

evaluate the impact of increased flows from CBM produced water

on aquatic communities. The modeling results determined that all 

study locations would lose habitat, impacting and possibly 

destroying macroinvertebrates and western silvery minnows and 

destabilizing the river ecosystem. Small increases in flow over a 

long period of time flushed organisms, decreased organic matter, 

changed channel morphology, and increased sedimentation, which 

could cause declines in the macroinvertebrate community, 

decreasing fish populations and decreasing diversity in the 

ecosystem.

4.3

EPA defines a nonsurface water environmental impact as an impact caused by CBM 

produced water that did not result from the direct discharge of produced water to a receiving 

stream. Nonsurface water environmental concerns discussed in the literature can be divided into 

two broad categories: (1) environmental impacts caused by the land application (e.g., irrigation 

or dust control) of CBM produced water and (2) environmental impacts that resulted from 

impounded CBM produced water (e.g., impoundment control technologies, livestock watering 

impoundments, and constructed wetlands). 

Nonsurface Water Environmental Impacts Associated With CBM Produced Water

Nonsurface water impacts were the predominant type of environmental impact described 

in the literature (see Table 4-1). EPA did not distinguish between documented and potential 

nonsurface water impacts. The most prevalent issues cited were groundwater issues, such as 

groundwater contamination resulting from both CBM produced water land application and 

impoundments, but irrigation and soil toxicity impacts were also frequently discussed. 

4.3.1 Land Application Impacts 

The land application of CBM produced water for activities such as irrigation and dust 

control can cause pollutants in CBM produced water to infiltrate into local groundwater systems. 

Pollutants that can infiltrate into groundwater include heavy metals, salts, ions, and organic 

material often present in CBM produced water (ALL, 2006b; Fisher, 2001), which can 

contaminate drinking water supplies (Veil et al., 2004). 
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Elevated SAR and salinity in CBM produced water applied to land can alter the soil 

structure of fine-textured soils by causing swelling and dispersion, which decreases pore size and 

reduces water infiltration rates (USGS, 2006a; ALL, 2002; ALL, 2003). Reduced soil porosity 

increases runoff of rain and irrigation waters, which can decrease the ability of soils to support 

plant life (Arthur, 2001; USGS, 2006a). CBM produced waters with elevated salinity can also 

decrease air and water permeability in soil. Fine clayey soils, of which the PRB is primarily 

composed, are particularly prone to impacts from the saline and high SAR content of CBM 

produced water discharges (USGS, 2006a; ALL, 2002). 

Even in nonsensitive soils, the increased salinity of CBM discharges can be toxic to 

plants and decrease crop yield (Veil et al., 2004; Regele and Stark, 2000). If soil water is too 

saline, plants must exert more energy to extract waters from soils, decreasing productivity (ALL, 

2003), which can cause plant communities to shift to more salt-tolerant species, decreasing 

diversity and altering the ecosystem (Arthur et al., 2001). In one paper, Stanford and Hauer 

(2003) observed areas in Montana where land irrigated with CBM produced water contained 

very little or no vegetation. In areas with abundant rainfall, salts from CBM produced water can 

leach from the soil; however, in more arid regions (e.g., Montana), salts can accumulate with 

each application of CBM water (Veil et al., 2004) and render the soil unfit to support vegetation. 

In addition to the articles discussed above, EPA identified several published scientific 

studies investigating the potential nonsurface water impacts from land application of CBM 

produced water (see Table 4-4). These studies primarily focus on groundwater and soil impacts 

due to CBM activities.

Table 4-4. Scientific Studies Evaluating Nonsurface Water Environmental Concerns 

Associated With Land Application of CBM Produced Water

Citation Impact Type Summary

Buchanan, 2005 Soil High concentrations of salts and sodium in CBM produced waters pose 

a potential risk to soil structure and porosity when used for irrigation. 

Finer, more clayey soils exhibited a more significant change in 

hydraulic properties when irrigated with CBM produced water than 

coarser soils. Irrigation using CBM produced water with high sodium 

concentrations increased runoff volumes and decreased infiltration rates.

Ganjegunte et al., 

2005

Soil Irrigation with CBM water can significantly impact certain soil 

properties, such as infiltration and conductivity.

Rice et al., 2002 

(cited in Kirkpatrick, 

2005)

Soil CBM waters in the northwest PRB had high SAR and TDS 

concentrations. Surface discharge of this water could change soil 

permeability.

Robinson, 2002 

(cited in Kirkpatrick, 

2005)

Soil Repeated wetting and drying cycles from applying CBM produced 

water can result in greater SAR levels in soils due to concentration of 

ions from evaporating water. The increase in soil SAR values can alter 

soil properties (e.g., soil pore size) and decrease the infiltration of water 

over time.

Todd, 2006 Soil Irrigation with CBM water can have long-term impacts on soil and plant 

productivity. Experimental irrigation with CBM produced waters 

decreased forage yield, height, and nitrate concentrations of crops.
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Table 4-4. Scientific Studies Evaluating Nonsurface Water Environmental Concerns 

Associated With Land Application of CBM Produced Water

Citation Impact Type Summary

McBeth et al., 2003 Soil Study results suggest that in arid and semiarid regions, land disposal of 

CBM produced waters may cause precipitation of calcium carbonate in 

soils, which can decrease infiltration rates and increase runoff and 

erosion rates.

Robinson et al., no 

date

Soil A study published by Montana State University and funded by several 

conservation districts in the state concluded that CBM produced water

used for irrigation purposes can negatively affect soils. EC, SAR, and 

exchangeable sodium percentage (ESP) values were significantly 

elevated, with approximately 50% of the resultant values exceeding the 

reported thresholds for salt injury to crops (i.e., alfalfa, corn, and 

specialty crops) commonly grown in the area and the thresholds for soil 

dispersion.

Ramirez, 2005 Soil The U.S. FWS report on CBM produced water contaminants contends 

that irrigation with high-saline produced waters causes salt to 

accumulate, which destroys soil structure and inhibits plant uptake of 

water. The SAR of produced water is typically 10 to 12 times the level 

for soil to support plants.

Ramirez, 2005 Bioaccumulation In an assessment of CBM contaminants, the U.S. FWS reported that the 

land application of CBM produced water with elevated levels of 

selenium on marine Cretaceous shales (found in the eastern and western 

boundaries of the PRB) can mobilize selenium present in the shale. 

Selenium can bioaccumulate in the food chain up to 2,000 times the 

level present in water. Bioaccumulation is most likely to occur in areas 

with selenium sources, high evaporation rates, and closed containment 

reservoirs.

Ramirez, 2005 Groundwater The U.S. FWS reported that infiltration of CBM produced water can 

rapidly contaminate groundwater by leaching salts and trace elements 

from the ground in addition to the water’s original elevated salt and 

trace element concentrations.

4.3.2 Impoundment Control Technology Impacts 

Surface impoundment impacts include groundwater impacts due to infiltration, the 

concentration or bioaccumulation of pollutants (e.g., salts, heavy metals) due to evaporation, and 

the potential creation of new aquatic habitats resulting in the introduction or proliferation of 

species in the area (e.g., West Nile Virus vector mosquitoes). In addition to the initial 

contamination, evaporation from impoundments can further concentrate pollutants in CBM 

produced water, decreasing the quality of water released to the environment through infiltration 

or discharge (ALL, 2002). If connected to surface water bodies, impoundment discharges can 

also degrade water quality in receiving waters (Roulson, 2007; ALL, 2003). 

Impoundments can also create new habitats in CBM production areas (Doherty, 2007), 

which can introduce new species or cause the proliferation of species already in the area (Davis 

et al., 2006; Doherty, 2007). The proliferation of species such as West Nile virus vector 

mosquitoes due to CBM discharge ponds can cause human and wildlife health risks (Doherty, 

2007). 
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As in impoundments, the salt concentrations in constructed wetlands can increase due to 

evaporation, which can impact soils and wetland plant survival (Kirkpatrick, 2005). Elevated salt 

concentrations can prevent the vegetation growth on the land once the CBM well is depleted, as 

the elevated salinity would prevent all but salt-tolerant plants from reestablishing (Kirkpatrick, 

2005). 

Table 4-5 lists several published scientific studies identified by EPA that investigate the 

potential nonsurface water impacts from control technologies for CBM produced water. 

Table 4-5. Scientific Studies Evaluating Nonsurface Water Environmental Concerns 

Associated With Control Technologies for CBM Produced Water 

Citation Impact Type Summary

ALL, 2007 Impoundments, 

Groundwater

In a study funded by U.S. DOE’s Office of Fossil Energy (Tulsa) and the 

Montana Board of Oil and Gas Conservation, ALL used subsurface 

hydrogeologic data to investigate the effects of CBM impoundments on 

shallow groundwater. In the study, ALL observed a chemical shift in salt 

ions present in downgradient bedrock samples over background water 

quality.

Jackson and 

Reddy, 2007

Impoundments Researchers from the Department of Renewable Resources at the 

University of Wyoming determined that arsenic is soluble and mobile in 

semiarid alkaline watersheds with mineral oxides and hydroxides and 

increases in concentration in disposal ponds over time.

Zou et al., 2006 

(cited in Doherty, 

2007)

Impoundments, 

Constructed 

Wetlands

In a GIS analysis of potential mosquito larval habitats in the PRB, Zou et 

al. determined that CBM development increased the habitat available for 

West Nile virus vector mosquitoes by 75% from 1999 to 2004.

Kirkpatrick, 2005 Constructed 

Wetlands

Some native PRB plants are naturally salinity-tolerant. However, the 

elevated salinity and sodicity associated with constructed wetlands for 

CBM disposal might prevent even salt-tolerant native species from 

reclaiming the area.

4.4

EPA identified several articles and documents that included general statements that CBM 

produced water discharges were not likely to cause an environmental impact; however, these 

statements were not substantiated by rigorous scientific research. EPA also identified several 

studies that concluded if the appropriate controls are in place (e.g., certain management practices 

or prior soil investigation), there will likely be minimal or no impacts from CBM produced water 

discharges.

Assertions of No Environmental Impact Caused by CBM Produced Water

A number of state and federal documents included statements of no environmental impact 

resulting from CBM produced water discharges. The majority of these statements were from 

National Environmental Policy Act (NEPA) Final Environmental Impact Statements (FEIS) and 

Environmental Assessments (EA) documents from the Bureau of Land Management (BLM); the 

remaining no impact claims were from a series of reports written by the BLM on the impacts of 

coal activities in the PRB, referred to as the PRB Coal Review. The NEPA documents usually 

prefaced statements of no environmental impact with some acknowledgment of the potential for 

CBM discharges to cause environmental harm; however, these potential impacts were not 

considered serious enough to stop the development of the CBM project and the overall 
Coalbed Methane Extraction:Detailed Study Report December 2010

4-12 

operations were deemed not to cause any environmental impacts of concern (BLM, 2001, 2003a, 

2003b, 2003c, 2004, 2005a). The PRB Coal Report discusses potential environmental impacts, 

but also discusses studies by the BLM demonstrating that CBM produced waters have not 

impacted the environment. For example, one BLM study concluded that, in Antelope Creek, 

Little Powder, Upper Belle Fourche, and Upper Cheyenne subwatersheds, CBM discharges 

would have minimal effect on permanent streams (BLM, 2005b). Another noted that as of 2002, 

CBM discharges to streams had not impacted surface waters farther than a few miles from the 

outfall, and discharges to unlined impoundments had no impact on groundwater or surface water 

farther than 25 feet away (BLM, 2006). 

The GSA’s long-term monitoring of fish and benthic communities in Little Hurricane 

Creek during controlled discharge of produced water has shown no effect on benthic invertebrate 

community structure at chloride concentrations below 600 mg/L. GSA believes this demonstrates 

that produced water can be discharged to a surface water without adverse effect if its potential 

toxicity is properly assessed and the discharge is managed and monitored accordingly (Mount et 

al., 1992). 
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water interacting with semi-arid ephemeral stream channels. Journal of the American 

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Evaporation Ponds in Wyoming. WWRC-85-21. Available online at: 

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Natural Gas in the Powder River Basin, Wyoming. Preliminary compositional data. 

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74. Rice, C.A., T.T. Bartos, and M.S. Ellis, 2002. Chemical and isotopic composition of 

water in the Fort Union and Wasatch Formation of the Powder River Basin, Wyoming 

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Nuccio, V.F. (eds.), Coalbed Methane of North America, I., Rocky Mountain Association 

of Geologists. p.53-70 (cited in Kirkpatrick 2005). EPA-HQ-OW-2008-0517, DCN 

07229. 

75. Robinson, K. 2002. Soil Behavior Upon Wetting with Saline-sodic Water: Part 1 and 2. 

Available online at http://waterquality.montana.edu/docs/methane (cited in Kirkpatrick, 

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Saline-Sodic Water Part 1 and Part 2. Department of Land Resources and Environmental 

Sciences, Montana State University, Bozeman, MO. EPA-HQ-OW-2008-0517, DCN 

07229. 

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American Fisheries Society, to Alan Olson, Federal Relations, Energy and 

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07229. 

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0517, DCN 07229. 

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report prepared for U.S. Environmental Protection Agency, Helena (cited in Davis et al., 

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Solutions. A White Paper. Flathead Lake Biological Station Division of Biological 

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83. Suncor. 2009. Suncor Energy, Inc., Form 20-F, 2008. EPA-HQ-OW-2008-0517, DCN 

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Methane Discharge Water. M.S. Thesis, Montana State University, Bozeman, MO. EPAHQ-OW-2008-0517, DCN 07229. 
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85. U.S. DOE. 2003. Multi-Seam Well Completion Technology: Implications for Power 

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DCN 07356. 

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DCN 03480. 

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online at: http://tonto.eia.doe.gov/dnav/ng/NG_ENR_CBM_A_EPG0_R52_BCF_A.htm. 

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Program Plan. EPA-821-R-04-014. Washington, D.C. (August). DCN 01088. 

97. U.S. EPA. 2004b. Evaluation of Impacts to Underground Sources of Drinking Water by 

Hydraulic Fracturing of Coalbed Methane Reservoirs (June). 

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99. U.S. EPA. 2006. Technical Support Document for the 2006 Effluent Guidelines Program 

Plan. EPA 821R-06-018 (December). 

100. U.S. EPA. 2007. Final Meeting Notes from U.S. Fish and Wildlife, Daphne Field Office 

and Geological Survey of Alabama Meeting. EPA-HQ-OW-2006-0771-0903. 

101. U.S. EPA. 2009. Site Visit Report: Drake Water Technologies, Inc. June 16, 2009, 

Powder River Basin, WY. EPA-HQ-OW-2008-0517, DCN 05243. 

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103. U.S. EPA. 2010b. Detailed Questionnaire Data (CBI). EPA-HQ-2008-0517, DCN 07375. 

104. USGS. 2000. Water Produced with Coal-Bed Methane. USGS. Fact Sheet FS-156-00 

(November). DCN 03487. 
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River Basin, Montana and Wyoming. Fact Sheet 2006–3137 (November). EPA-HQ-OW2008-0517, DCN 07229. 

106. USGS. 2006b. Toxicity of Sodium Bicarbonate to Fish from Coal-Bed Natural Gas 

Production in the Tongue and Powder River Drainages, Montana and Wyoming. EPAHQ-OW-2006-0771-0943. 

107. Veil, J.A., M.G. Puder, D. Elcock, and R.J. Redweik, Jr. 2004. A White Paper Describing 

Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane. 

Prepared for the U.S. Department of Energy (January). EPA-HQ-OW-2008-0517, DCN 

07229. 

108. Vickers, D.T. 1990. Disposal practices for waste waters from coalbed methane extraction 

in the Black Warrior Basin, Alabama. In: Proceedings of the First International 

Symposium on Oil and Gas Exploration and Production Waste Management Practices. 

EPA-HQ-OW-2008-0517, DCN 07229. 

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result of coalbed methane development in a Rocky Mountain watershed. Journal of the 

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0517, DCN 07229. 

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Methane Regional Ground-water Monitoring Report: Northern Portion of the Powder 

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DCN 03474. 

111. WOGCC. 2010. Wyoming CBM Production. Available online at: 

http://wogcc.state.wy.us/StateCbmGraph.cfm. EPA-HQ-OW-2008-0517, DCN 07364. 

112. Yahoo Finance. 2010. Industry Center—Major Integrated Oil and Gas. Available online 

at: http://biz.yahoo.com/ic/120_cl_all.html. EPA-HQ-OW-2008-0517, DCN 07365. 

113. Zimpfer, G.L., E.J. Harmon, and B.C. Boyce, 1988. Disposal of production waters from 

oil and gas wells in the Northern San Juan Basin, Colorado. In: Fassett, J.E. Fassett, ed., 

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and Colorado, 1988 CBM Symposium. Denver, CO: Rocky Mountain Association of 

Geologists. pp. 183-198. DCN 01190. 

114. Zou, L., S.N. Miller and E.T. Schmidtmann. 2006. Mosquito larval habitat mapping using 

remote sensing and GIS: Implications of coalbed methane development and West Nile 

Virus. Journal of Medical Entomology 43:1034-1041 (cited in Doherty, 2007). EPA-HQOW-2008-0517, DCN 07229. 
Coalbed Methane Extraction:Detailed Study Report December 2010

Appendix A

SUMMARY OF PERMITTING PRACTICES AND REQUIREMENTS
Coalbed Methane Extraction:Detailed Study Report December 2010

A-1 

 Alabama 

The Alabama Department of Environmental Management (ADEM)’s Industrial/Mining 

Section began permitting CBM produced water discharges in the mid-1980s and has drafted or 

issued 77 individual CBM discharge permits. As of August 2009, there were 24 active CBM 

discharge permits in Alabama. ADEM indicated that conductivity and chlorides (both in CBM 

produced water and receiving streams) are of the greatest concern (ERG, 2009a). EPA reviewed 

the active CBM discharge permits; Table A-1 lists the monitored parameters, limits, and 

monitoring frequencies that were included in all the permits.

Table A-1. Alabama’s Individual Permit Limitations

Parameter

Daily

Minimum

Daily 

Maximum

Monthly 

Average

Monitoring 

Frequency

Flow- and Conductivity-Related Parameters

Flow (mgd) NA Monitor Monitor Continuous

Conductivity NA Monitor Monitor Continuous

Metals

Total Iron (mg/L) NA 6 3 Weekly

Total Manganese (mg/L) NA 4 2 Weekly

Other Pollutants

BOD (mg/L) NA 45 30 Weekly

Dissolved Chlorides (mg/L) NA Monitor Monitor Weekly

Dissolved Oxygen (mg/L) 5 NA NA Weekly

In-Stream Chlorides (mg/L) NA 230 NA Weekly

Oil and Grease (mg/L) NA 15 NA Weekly

pH (s.u.) 6 9 NA Daily

NA – Not applicable.

Alabama’s permits require permittees to continuously measure flow and conductivity and 

to use a continuous flow measurement device and an ADEM-approved discharge diffuser to limit 

chloride concentrations in the receiving stream. Permittees are required to submit and implement 

a Best Management Practices Plan to minimize the potential for accidental discharges of process 

liquids or solids. 

Permittees must monitor conductivity and use the following correlation between 

conductivity and chlorides (chloride [mg/L] = conductivity × 0.287) to determine the amount of 

chlorides that can be discharged from the CBM well. Permittees are required to continuously 

monitor the conductivity and chloride concentrations both upstream and downstream from each 

CBM outfall in both the river and its tributaries. If chloride concentrations exceed 210 mg/L in 

the receiving stream or 190 mg/L in its downstream tributaries, permittees must cease 

discharging. The permits require monitoring of in-stream dissolved oxygen concentrations 

depending on the produced water discharge concentration. Permittees must also perform both 48-

hour acute and short-term chronic WET tests at a minimum of once per quarter. Acute toxicity 

tests must result in greater than 90 percent survival; less than 90 percent survival indicates 

noncompliance. Chronic toxicity tests must result in greater than 80 percent survival. 
Coalbed Methane Extraction:Detailed Study Report December 2010

A-2 

Permittees are also required to monitor any stormwater discharges associated with 

construction and operation of their facilities. Monitored parameters for stormwater include flow, 

pH, total iron, total manganese, dissolved chlorides, BOD5, COD, oil and grease, TSS, and 

turbidity. The discharge limit for turbidity is 50 n.t.u. above background levels in the receiving 

stream. 

 Colorado 

For the past 10 years, Colorado has regulated all discharges to surface water (from 

approximately 20 CBM operations) under a general permit for produced water discharges from 

oil-and-gas-producing formations. However, the Colorado Department of Public Health and 

Environment (CDPHE) is currently reissuing all CBM permits as individual permits at the end of 

their respective permit cycles. CDPHE indicated that sodium is the primary issue of concern with 

CBM discharges in Colorado. Other concerns include dewatering of domestic wells, discharge of 

high volumes of water into dry creeks, downcutting, erosion, and an increase in sediment 

deposition (ERG, 2009b). 

Colorado issued a new general permit for produced water discharges from oil-and-gasproducing formations in September 2009 for those CBM permittees yet to be covered by an 

individual permit. The limitations and monitoring requirements therein, effective September 

2009, are based on state water quality standards, effluent and watershed limitations, and policies. 

Table A-2 lists the permitted parameters, limits, and monitoring frequencies included in 

Colorado’s general CBM permit. 

Table A-2. Colorado’s General Permit Limitations

Parameter

Monthly 

Average

Weekly 

Average

Daily 

Maximum

Monitoring 

Frequency

Flow- and Conductivity-Related Parameters

SAR 2.5 a NA NA Weekly

Flow (mgd) Limit NA Report Continuous

Conductivity (dS/m) 0.70 NA NA Weekly

Metals

Inorganic Metals (μg/L) Site Specific NA Site Specific Flow Based

Radium 226+228 (pCi/L) NA NA 5 Flow Based

Other Pollutants

Benzene (μg/L) NA NA Site Specific Flow Based

Chloride (mg/L) 250 NA NA Flow Based

Ethylbenzene (μg/L) NA NA Site Specific Flow Based

Oil and Grease (mg/L) NA NA 10 Flow Based

Other Nonmetal Inorganic Chemicals 

(μg/L)

Site Specific NA Site Specific Flow Based

Other Organic Chemicals (μg/L) Site Specific NA Site Specific Flow Based

Other Radionuclides (pCi/L) Site Specific NA Site Specific Flow Based

pH (s.u.) NA NA 6.5–9.0 Weekly

Sulfate (mg/L) 250 NA NA Flow Based

TDS (mg/L) Site Specific NA NA Weekly
Coalbed Methane Extraction:Detailed Study Report December 2010

A-3 

Table A-2. Colorado’s General Permit Limitations

Parameter

Monthly 

Average

Weekly 

Average

Daily 

Maximum

Monitoring 

Frequency

Temperature (oC) NA 9.0–24.2 13.0–28.6 Flow Based

Toluene (μg/L) NA NA Site Specific Flow Based

Total Xylene (μg/L) NA NA Site Specific Flow Based

TSS (mg/L) 30 45 NA Weekly

Note: “Flow Based” indicates that monitoring frequency is weekly (over 100,000 gpd), bimonthly (50,001–100,000 

gpd) or monthly (less than 50,000 gpd) based on discharge volumes.

a – SAR of 2.5 is acceptable provided EC is 0.70.

NA – Not applicable. 

The flow limit in the general permit is based on the design capacity of CBM produced 

water treatment process. Many parameters such as TDS, metals, and radionuclides are assigned 

on a site-specific basis, based on:

• Water quality standards in specific locations;

• Designed beneficial uses;

• Limitations for discharges to specific watersheds;

• Receiving water characteristics; and

• Produced water quality. 

Colorado also requires a chronic WET test in which there can be no statistically 

significant differences between control and effluent concentrations. 

 Montana 

The Montana Department of Environmental Quality (MTDEQ) has been issuing 

individual CBM permits since the mid-1990s, with the requirement that CBM discharges not be 

any more or less pure than the natural conditions of the receiving stream. Currently, there are 

three active CBM permits in Montana; however, EPA was able to review only two of them. 

Montana only has three operators, two of which do not discharge produced water directly. All 

three permits belong to the sole direct discharging operator, and those permits cover hundreds of 

wells. EC and SAR are of the biggest concern to Montana because typical surface waters have 

high levels of background salts, and increased concentrations of EC and SAR can precipitate the 

salt out of the waters. MTDEQ indicated that they are concerned with using CBM produced 

water for irrigation, through either the direct beneficial use of CBM waters or the use of surface 

waters influenced by upstream CBM discharges, as there is a potential for disaggregation of the 

soil. MTDEQ is also concerned about water rights and altered downstream conditions (ERG, 

2009c). 

Permit parameters found in both of the reviewed individual permits include EC, SAR, 

pH, oil and grease, TSS, TDS, total recoverable cadmium, total recoverable selenium, total 

recoverable mercury, and total recoverable arsenic. Both permits included summer (March 

through October) and winter (November through February) limits for EC and SAR, although the 

actual limits differed. Table A-3 lists the permitted parameters, limits, and monitoring 

frequencies included in Montana’s two reviewed CBM permits. 
Coalbed Methane Extraction:Detailed Study Report December 2010

A-4 

Table A-3. Montana’s Individual Permit Limitations and Monitoring Frequencies

Parameter

Daily 

Minimum Daily Maximum

Monthly 

Average

Monitoring 

Frequency

Flow- and Conductivity-Related Parameters

SAR NA Mar–Oct: 2.6/4.5

Nov–Feb: 6.6/7.5

Mar–Oct: 

1.3/3.0

Nov–Feb: 

3.3/5.0

Weekly, Monthly

Flow (mgd) NA Apr–Aug: 0

Sep–Mar: 0.19–

0.32/NA

NA Continuous

Conductivity (μS/cm) NA Mar–Oct: 

964/1,500

Nov–Feb: 

1,265/2,500

Mar–Oct: 

480/1,000

Nov–Feb: 

631/1,500

Continuous, Monthly

Metals

Dissolved Aluminum (mg/L) NA NA NA Semiannual

Calcium (mg/L) NA NA NA Weekly

Magnesium (mg/L) NA NA NA Weekly

Sodium (mg/L) NA NA NA Weekly

Total Recoverable Arsenic (mg/L) NA Cannot exceed 

upstream 

concentrations/ 

NA

NA Monthly/Semiannual

Total Recoverable Barium (mg/L) NA NA NA Semiannual

Total Recoverable Cadmium (mg/L) NA 0.48/NA 0.054/NA Monthly/Semiannual

Total Recoverable Copper (mg/L) NA NA NA Semiannual

Total Recoverable Iron (mg/L) NA NA 0.6 Weekly, Monthly

Total Recoverable Lead (mg/L) NA NA NA Semiannual

Total Recoverable Manganese 

(mg/L)

NA NA NA Semiannual

Total Recoverable Mercury (mg/L) NA Cannot exceed 

upstream 

concentrations/

NA

NA Monthly/Semiannual

Total Recoverable Radium (pCi/L) NA Cannot exceed 

upstream 

concentrations

NA Monthly

Total Recoverable Selenium (μg/L) NA 3.0 0.75 Monthly

Total Recoverable Zinc (mg/L) NA NA NA Semiannual

Total Strontium (mg/L) NA NA NA Semiannual

Other Pollutants

Ammonia (mg/L) NA 0.26 0.13 Weekly, Semiannual

BOD (mg/L) NA NA N/A Semiannual

Nitrite and Nitrate (mg/L) NA NA NA Semiannual

Oil and Grease (mg/L) NA 10 NA Monthly
Coalbed Methane Extraction:Detailed Study Report December 2010

A-5 

Table A-3. Montana’s Individual Permit Limitations and Monitoring Frequencies

Parameter

Daily 

Minimum Daily Maximum

Monthly 

Average

Monitoring 

Frequency

pH (s.u.) 6.5 9.0/8.4 NA Continuous, 

Weekly/Daily

TDS (mg/L) NA NA NA Weekly, Monthly

Temperature (oF) NA NA NA Continuous, Weekly

Total Cyanide (mg/L) NA NA NA Semiannual

Total Kjeldahl Nitrogen (mg/L) NA NA NA Semiannual

Total Nitrogen (mg/L) NA NA NA Semiannual

Total Phenols (mg/L) NA NA NA Semiannual

Total Phosphorus (mg/L) NA NA NA Semiannual

Total Recoverable Boron (mg/L) NA NA NA Semiannual

Total Recoverable Fluoride (mg/L) NA NA 0.5 Weekly, Monthly

TSS (mg/L) NA 40/30 17/25 Monthly/Weekly

NA – Not applicable. 

 Pennsylvania 

CBM development began in Pennsylvania in the 1970s and began increasing in the mid1990s, especially in southwestern Pennsylvania. The Pennsylvania Department of Environmental 

Protection (PADEP) currently has 12 active CBM individual permits, eight pending permits, and 

five permits pending renewal with varying site-specific monitoring and discharge limitations. 

EPA, however, was unable to review any of these permits and received all data concerning these 

permits via telephone conversations with PADEP staff. PADEP indicated that CBM produced 

water is not of good quality and it is most concerned with elevated levels of chlorides and iron in 

the water. Pennsylvania currently sets discharge limits for TDS, iron, flow, TSS, oil and grease, 

and osmotic pressure and requires monitoring of acidity, alkalinity, and chlorides (ERG, 2009d). 

West Virginia

The West Virginia Department of Environmental Protection (WVDEP) has issued two 

individual permits for CBM produced water direct discharge to surface waters; however, neither 

of the operations has actually discharged produced waters. One operator reported surface water 

discharge in the screener survey, and possibly holds a permit, but apparently has not discharged 

produced water yet (the operator reported a number of other management practices) (U.S. EPA, 

2010a). In West Virginia, CBM operations tend to land apply their produced waters rather than 

discharge to surface waters and might occasionally discharge to a POTW (ERG, 2009e). One 

operator indicated in the screener survey that indirect discharge is one method they use (U.S. 

EPA, 2010a). Land application permits are handled under a general permit by West Virginia’s 

Office of Oil and Gas. EPA was unable to determine how many land application permits have 

been issued to CBM operations, although two operators in EPA’s screener survey indicated that 

they do practice land application of produced water (U.S. EPA, 2010a). 
Coalbed Methane Extraction:Detailed Study Report December 2010

A-6 

 Wyoming 

The Wyoming Department of Environmental Quality (WYDEQ) began issuing individual 

CBM discharge permits in the mid-1990s, with the majority issued within the past 10 years. 

WYDEQ has issued approximately 1,000 CBM permits, with approximately 800 current permits. 

As these individual CBM permits expire, WYDEQ plans to reissue them as watershed-based 

permits because there can be several dozen CBM dischargers in a given watershed (ERG, 2009f). 

Currently, WYDEQ has issued about 11 watershed-based permits. Wyoming’s watershed-based 

permitting program is focusing on areas with increasing or heavy CBM development. 

WYDEQ identified TDS, EC, SAR, dissolved iron, total recoverable arsenic, barium, 

cadmium, and selenium as constituents of concern and has set permit limits for each of these 

constituents. WYDEQ is concerned about stream downcutting and flooding associated with 

large-volume discharges, but does not have a regulatory mechanism to control CBM discharge 

volumes (ERG, 2009f). 

EPA reviewed Wyoming’s 11 watershed-based permits and determined that limits varied 

by the type of discharge category, of which there are four based on the type of receiving water 

body and containment practices: 

• Category 1—direct discharges to stream channels with no containment 

requirements.

• Category 2—discharges are contained in on-channel reservoirs with regular 

overtopping of stream banks due to precipitation allowed. 

• Category 3—discharges to on-channel headwater reservoirs or playa lakes with 

required containment for the 50-year or 100-year 24-hour storm event. 

• Category 4—discharges to constructed off-channel pits. These discharges are not 

allowed under the watershed permits and require individual permits. 

All watershed-based permits contain identical general language prohibiting the following: 

the discharge of floating solids; any visible foam or sheen; discharges that cause erosion, 

scouring, or damage to the outfall stream; discharges that cause aesthetic or habitat degradation; 

and discharge of toxic substances.

Table A-4 lists Wyoming’s watershed-based permit limitations by discharge category. In 

addition to the discharge limits and prohibitions, Wyoming has watershed-specific monitoring 

requirements including monitoring of steam headcuts, channel stability station monitoring, water 

quality station monitoring, WET testing, Category 2 flow monitoring, downstream irrigation 

monitoring, and Category 1 stream flow limits.
Coalbed Methane Extraction:Detailed Study Report December 2010

A-7 

Table A-4. Wyoming’s Watershed-Based Permit Limitations by Discharge Category

Parameter

Category 1

Daily 

Maximum

Category 2

Daily 

Maximum

Category 3

Daily 

Maximum

Category 4 a

Daily 

Maximum

Measurement

Frequency

Flow- and Conductivity-Related Parameters

SAR 1 -13, SAR < 

7.10 × EC – 

2.48

8–10 NA NA Biweekly–Annually

Flow (mgd) 0.36–9.70 NA NA NA Monthly–Annually

Conductivity 

(μmohs/cm)

450–7500 1330–7500 7500 7500 Biweekly–Annually

Metals

Dissolved Cadmium 

(μg/L)

0.1–4.0 0.6–4 NA NA Annually

Dissolved Calcium 

(mg/L)

NA NA NA NA Biweekly–Annually

Dissolved Copper 

(μg/L)

4–13.2 10 NA NA Annually

Dissolved Iron (μg/L) 74–1000 300–1000 1000 NA Every 3 mo.–Annually

Dissolved Lead (μg/L) 2–4 2–4 NA NA Annually

Dissolved Magnesium 

(mg/L)

NA NA NA NA Biweekly–Annually

Dissolved Manganese 

(μg/L)

50 NA NA NA Annually

Dissolved Silver (μg/L) 7.5 NA NA NA Annually

Dissolved Sodium 

(mg/L)

60–170 NA NA NA Biweekly–Annually

Dissolved Zinc (μg/L) 80–100 80–100 NA NA Annually

Total Radium 226 

(pCi/L)

3 NA 60 60 Annually

Total Radium 226 + 

Total Radium 228 

(pCi/L)

1–60 5 NA NA Annually

Total Recoverable 

Aluminum (μg/L)

490–750 NA 750 NA Annually

Total Recoverable 

Arsenic (μg/L)

2.4–8.4 7–10 150–180 150 Annually

Total Recoverable 

Barium (μg/L)

360–1800 1800–2000 1800 1800 Annually

Total Recoverable 

Selenium (μg/L)

2–5 5 NA NA Annually

Other Pollutants

Ammonia (mg/L) 0.4–6.8 NA NA NA Weekly–Annually

Bicarbonate (mg/L) NA NA NA NA Monthly–Annually

Chlorides (mg/L) 50–230 150–230 230–2000 230–2000 Monthly–Annually

Dissolved Boron (μg/L) NA NA NA NA Annually

Dissolved Fluoride 

(μg/L)

2000–4000 4000 2000–4000 2000–4000 Annually
Coalbed Methane Extraction:Detailed Study Report December 2010

A-8 

Table A-4. Wyoming’s Watershed-Based Permit Limitations by Discharge Category

Parameter

Category 1

Daily 

Maximum

Category 2

Daily 

Maximum

Category 3

Daily 

Maximum

Category 4 a

Daily 

Maximum

Measurement

Frequency

pH (s.u.) 6.5–9.0 6.5–9.0 6.5–9.0 6.5–9.0 Monthly–Annually

Sulfate (mg/L) 412–3000 NA 3000 3000 Biweekly–Annually

TDS (mg/L) 300–5000 NA 5000 5000 Biweekly–Annually

Temperature (oC) NA NA NA NA Monthly–Every 6 mo.

Total Alkalinity (mg/L) NA NA NA NA Monthly–Annually

a – Category 4 discharges require an individual permit. Limits are displayed here for comparison purposes.

NA – Not applicable.