Identifying Opportunities 

for Methane Recovery at 

U.S. Coal Mines: 

Profiles of Selected Gassy 

Underground Coal Mines 

1999-2003 

EPA Publication: EPA 430-K-04-003 
Identifying Opportunities for Methane Recovery at 

U.S. Coal Mines: 

Profiles of Selected Gassy Underground Coal Mines 

1999-2003 

EPA 430-K-04-003 

September 2005 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

COVER PHOTOGRAPHS (clockwise from top): 1) Two 44 MW Gas-Combustion Turbines Operated by 

Allegheny Energy and Consol Energy (Photo courtesy of Consol) 2) 850 kW Caterpillar engine at O’Gara #8 

abandoned mine in Illinois Basin, Operated by Grayson Hill Farms (Photo Courtesy of Raven Ridge Resources, 

Incorporated) 3) BCCK Cryogenic Gas Processing Unit at JWR Blue Creek Mines (Photo courtesy of Jim 

Walters Resources) 
ACKNOWLEDGMENTS 

The U.S. EPA would like to thank the U.S. Mine Safety and Health Administration for the ventilation 

emissions data used in this document. Other industry experts, as well as various individuals at state 

and federal agencies, were also helpful during the preparation of this document. 

i 
Table of Contents 

Page #

Acknowledgements ............................................................................................................................. i 

List of Figures..................................................................................................................................... v 

List of Tables ...................................................................................................................................... v 

Frequently Used Terms......................................................................................................................vi 

Frequently Used Abbreviations.........................................................................................................vii 

1. Executive Summary 

Methane Emissions & Recovery Opportunities ..................................................................1-1 

CMM Recovery Opportunities.............................................................................................1-1 

Overview of CMM Recovery and Use Techniques.............................................................1-3 

Opportunities for Methane Recovery Projects....................................................................1-4 

Overview of Methane Liberation, Drainage and Use at Profiled Mines .............................1-4 

Overview of U.S. Mining Industry Since 2001 ....................................................................1-4 

Summary of Opportunities for Project Development..........................................................1-6 

2. Introduction 

Purpose of Report...............................................................................................................2-1 

Recent Developments in the Coal Mine Methane Industry................................................2-1 

Overview of Coal Mine Methane.........................................................................................2-2 

Methane Drainage Techniques...........................................................................................2-3 

Vertical Pre-Mining Wells........................................................................................2-4 

Gob Wells................................................................................................................2-5

Horizontal Boreholes ..............................................................................................2-6 

Longhole Horizontal Boreholes ..............................................................................2-6 

Cross-Measure Boreholes......................................................................................2-7 

 Utilization Options ...............................................................................................................2-7 

Pipeline Injection.....................................................................................................2-8 

Power Generation.................................................................................................2-10 

Ventilation Air Methane Use Technologies ..........................................................2-12 

Local Use ..............................................................................................................2-16 

Flaring ...................................................................................................................2-17 

Green Pricing Projects ......................................................................................................2-17 

Barriers to the Recovery and Use of Coal Mine Methane................................................2-17 

Ownership of Coalbed Methane...........................................................................2-18 

Power Prices.........................................................................................................2-18 

Production Characteristics of Coalbed Methane Wells........................................2-18 

3. Overview of Existing Coal Mine Methane Projects 

Alabama .............................................................................................................................3-1 

Jim Walter Resources..................................................................................................3-1 

Blue Creek No. 4, No. 5 and No. 7 Mines ..............................................................3-1 

U.S. Steel Mining ........................................................................................................3-2

Oak Grove Mine......................................................................................................3-2 

Drummond Coal ........................................................................................................3-2 

Shoal Creek Mine ...................................................................................................3-2 

Colorado..............................................................................................................................3-2 

Mountain Coal .............................................................................................................3-3 

West Elk Mine .......................................................................................................3-3 

ii 
 New Mexico.........................................................................................................................3-3 

BHP Billiton..................................................................................................................3-3

San Juan South Mine .............................................................................................3-3 

Pennsylvania.......................................................................................................................3-3 

Consolidation Coal Company......................................................................................3-3 

Blacksville No. 2 Mine.............................................................................................3-3 

Virginia....... ........................................................................................................................3-3 

CONSOL......................................................................................................................3-4 

Buchanan No. 1 Mine .............................................................................................3-4 

VP No. 8 Mine ........................................................................................................3-4 

 West Virginia ......................................................................................3-5 

Peabody Energy .........................................................................................................3-5 

Federal No. 2 Mine .................................................................................................3-5 

U.S. Steel Mining ........................................................................................................3-5

Pinnacle No. 50 Mine..............................................................................................3-5

 Summary.............................................................................................................................3-6 

4. A Key to Evaluating Mine Profiles 

 Operating Status .................................................................................................................4-1 

 Geographic Data.................................................................................................................4-1 

 Corporate Information .........................................................................................................4-2 

 Mine Address ......................................................................................................................4-2 

 General Information ............................................................................................................4-2

Production, Ventilation and Drainage Data ........................................................................4-3 

Energy and Environmental Value of Emissions Reduction................................................4-5 

Power Generation Potential................................................................................................4-6 

 Pipeline Potential ................................................................................................................4-8 

Other Utilization Possibilities...............................................................................................4-8 

Ventilation Air Methane Emission.......................................................................................4-9 

5. Mine Summary Tables 

Table 1: Mines Listed Alphabetically ..............................................................................5-1 

Table 2: Mines Listed by State/County...........................................................................5-2 

Table 3: Mines Listed by Coal Basin ..............................................................................5-3 

Table 4: Mines Listed by Coalbed ..................................................................................5-4 

Table 5: Mines Listed by Company ................................................................................5-5 

Table 6: Mines Listed by Mining Method .......................................................................5-8 

Table 7: Mines Listed by Primary Coal Use ...................................................................5-9 

Table 8: Mines Listed by 2003 Coal Production...........................................................5-10 

Table 9: Mines Employing Methane Drainage Systems ..............................................5-11 

Table 10: Mines Listed by Estimated Total Methane Liberated in 2003........................5-12 

Table 11: Mines Listed by Daily Ventilation Emissions in 2003 ....................................5-13 

Table 12: Mines Listed by Estimated Daily Methane Drained in 2003 ..........................5-14 

Table 13: Mines Listed by Estimated Specific Emissions in 200 ...................................5-15 

Table 14: Mines Listed by CO2 Equivalent of Potential Annual CH4

Emissions Reductions ....................................................................................5-16 

Table 15: Mines Listed by Electric Utility Supplier..........................................................5-17 

Table 16: Mines Listed by Potential Electric Generating Capacity.................................5-19 

Table 17: Mines Listed by Potential Annual Gas Sales..................................................5-20 

Table 18: Mine Shaft Emissions .....................................................................................5-21 

iii
6. Profiled Mines 

Data Summary 6-1 

 Alabama..................................................................................................................6-1 

 Colorado..................................................................................................................6-2

 Illinois ......................................................................................................................6-2

 Indiana ....................................................................................................................6-3 

 Kentucky .................................................................................................................6-3 

 New Mexico ............................................................................................................6-4 

 Ohio.........................................................................................................................6-4 

 Oklahoma................................................................................................................6-4 

 Pennsylvania...........................................................................................................6-5 

 Utah.........................................................................................................................6-6 

 Virginia ....................................................................................................................6-6 

 West Virginia...........................................................................................................6-7 

Mine Profiles (profiles appear in alphabetical order by state) 

Alabama Mines 

Blue Creek No. 4 Ohio 

Blue Creek No. 5 Powhatan No. 6 

Blue Creek No. 7 

North River Oklahoma 

Oak Grove Pollyanna No. 8 

 Shoal Creek 

Pennsylvania Mines 

Colorado Mines Bailey 

 Elk Creek Eighty-Four Mine 

West Elk Enlow Fork 

RAG Cumberland 

Illinois Mines RAG Emerald 

Elkhart 

Galatia Utah Mines 

Wabash Aberdeen 

Willow Lake Portal Dugout Canyon 

West Ridge 

Indiana Mines 

Gibson Virginia Mines 

Buchanan 

Kentucky Mines Deep Mine #26 

Baker Virginia Pocahontas No. 8 

Cardinal 

Clean Energy No. 1 [Continued on next page] 

E3RF 

Freedom Energy No. 1 

Mine #1 

No. 3 Mine 

Pontiki No. 2 

New Mexico Mines 

San Juan South 

iv 
West Virginia Mines 

 American Eagle 

 Beckley Crystal 

Blacksville No. 2 

Dakota No. 2 

Eagle 

Federal No. 2 

Justice #1 

Loveridge No. 22 

McElroy 

Pinnacle No. 50 

Robinson Run No. 95 

Sentinel 

Shoemaker 

Upper Big Branch - South 

Whitetail Kittanning 

7. References ................................................................................................................................7-1

List of Figures 

Page # 

Figure 2-1: Mines with Active Coal Mine Methane Recovery Projects..........................................2-2 

Figure 2-2: Estimated Annual Use of Methane Recovered From U.S. Coal Mines ......................2-2 

Figure 2-3: Vertical Pre-Mining, Gob, and Horizontal Boreholes ..................................................2-5 

Figure 2-4: Horizontal and Cross-Measure Boreholes ..................................................................2-6 

Figure 2-5: Thermal Flow Reversal Reactor................................................................................2-13 

List of Tables 

Table 1-1: U.S. Summary Table.....................................................................................................1-5 

Table 2-1: Summary of Drainage Methods....................................................................................2-7 

Table 2-2: Utilization Options for Coalbed Methane......................................................................2-8 

Table 2-3: Current Methane Pipeline Projects at Profiled Mines...................................................2-9 

Table 3-1: Summary of Existing Methane Recovery and Use Projects ........................................3-6 

Table 6-1: Alabama Mines .............................................................................................................6-1 

Table 6-2: Colorado Mines.............................................................................................................6-2 

Table 6-3: Illinois Mines..................................................................................................................6-3 

Table 6-4: Kentucky Mines.............................................................................................................6-4 

Table 6-5: Pennsylvania Mines......................................................................................................6-5 

Table 6-6: Utah Mines....................................................................................................................6-6 

Table 6-7 Virginia Mines................................................................................................................6-7 

Table 6-8: West Virginia Mines ......................................................................................................6-8 

v 
Frequently Used Terms 

Coalbed methane: Methane that resides within coal seams. 

Coal mine methane: As coal mining proceeds, methane contained in the coal and surrounding strata 

may be released. This methane is referred to as coal mine methane since its liberation resulted from 

mining activity. In some instances, methane that continues to be released from the coal bearing 

strata once a mine is closed and sealed may also be referred to as coal mine methane because the 

liberated methane is associated with past coal mining activity. 

Degasification system: A system that facilitates the removal of methane gas from a mine by 

ventilation and/or by drainage. However, the term is most commonly used to refer to removal of 

methane by drainage technology. 

Drainage system: A system that drains methane from coal seams and/or surrounding rock strata. 

These systems include vertical pre-mine wells, gob wells and in-mine boreholes. 

Ventilation system: A system that is used to control the concentration of methane within mine 

working areas. Ventilation systems consist of powerful fans that move large volumes of air through 

the mine workings to dilute methane concentrations. 

Methane drained: The amount of methane removed via a drainage system. 

Methane liberated: The total amount of methane that is released, or liberated, from the coal and 

surrounding rock strata during the mining process. This total is determined by summing the volume of 

methane emitted from the ventilation system and the volume of methane that is drained. 

Methane recovered: The amount of methane that is captured through methane drainage systems 

and is synonymous with “methane drained.” 

Methane used: The amount of methane put to productive use (.e.g., natural gas pipeline injection, 

fuel for power generation, etc) 

Methane emissions: This is the total amount of methane that is not used and therefore emitted to the 

atmosphere. Methane emissions are calculated by subtracting the amount of methane used from the 

amount of methane liberated (emissions = liberated – recovered/used). 

vi 
Frequently Used Abbreviations 

b Billion (109) 

Btu British Thermal Unit 

CAA Clean Air Act 

CAAA Clean Air Act Amendments 

cf Cubic Feet 

CH4 Methane 

CO2 Carbon Dioxide 

DOE Department of Energy 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

FOB Freight on Board 

GWP Global Warming Potential 

m (or M) Thousand (103

) 

mm (or MM) Million (106

) 

MSHA Mine Safety and Health Administration 

MW Megawatt 

NA Not Available (as opposed to Not Applicable) 

PUC Public Utility Commission 

t ton (short tons are used throughout this report) 

USBM U.S. Bureau of Mines 

UMWA United Mine Workers of America 

vii 
1. Executive Summary 
1. Executive Summary 

The purpose of this report is to provide information about specific opportunities to develop methane 

recovery projects at large underground coal mines in the United States. This report contains profiles 

of 50 U.S. coal mines that may be potential candidates for methane recovery and use, and details ongoing recovery projects at 12 of the mines. The United States Environmental Protection Agency (EPA) 

designed the profiles to help project developers perform an initial screening of potential projects. 

While the mines profiled in this report appear to be good candidates, a detailed evaluation would need 

to be done on a site-specific basis in order to determine whether the development of a specific 

methane recovery project is both technically and economically feasible. 

Since the last version of this report was published in July 2004, coalbed and coal mine methane 

recovery and use are unchanged with 2001 and 2003 methane recovery and use of approximately 40 

Bcf/yr in each year (methane recovery/use was up slightly in 2002 to 43 Bcf). Despite the recent trend, 

coal mine methane recovery and use have grown from an estimated 28 Bcf in 1997. At a gas price of 

$4.88/mcf, this means that coal mine methane developers increased annual revenues by an estimated 

$59 million between 1997 and 2003. 

Methane Emissions and Recovery Opportunities 

Non-CO2 gases play important roles in efforts to understand and address global climate change. The 

non-CO2 gases include a broad category of greenhouse gases other than carbon dioxide (CO2), such 

as methane, nitrous oxide and a number of high global warming potential (GWP) gases. The non-CO2 

gases are more potent than CO2 (per unit weight) and are significant contributors to global warming, 

thus, reducing emissions of non-CO2 gases can help prevent global climate change and produce 

broader economic and environmental benefits. 

Methane (CH4) is a greenhouse gas that exists in the atmosphere for approximately 9-15 years. As a 

greenhouse gas, CH4 is over 20 times more effective in trapping heat in the atmosphere than carbon 

dioxide – over a 100-year period – and is emitted from a variety of natural and human-influenced 

sources. Human-influenced sources include landfills, natural gas and petroleum systems, agricultural 

activities, coal mining, stationary and mobile combustion, wastewater treatment, and certain industrial 

processes. 

Methane is also a primary constituent of natural gas and an important energy source. As a result, 

efforts to prevent or utilize methane emissions can provide significant energy, economic and 

environmental benefits. In the United States, many companies are working with EPA in voluntary 

efforts to reduce emissions by implementing cost-effective management methods and technologies. 

U.S. industries along with state and local governments collaborate with the U.S. Environmental 

Protection Agency to implement several voluntary programs that promote profitable opportunities for 

reducing emissions of methane, an important greenhouse gas. These programs are designed to 

overcome a wide range of informational, technical, and institutional barriers to reducing methane 

emissions, while creating profitable activities for the coal, natural gas, petroleum, landfill, and 

agricultural industries. 

CMM Recovery Opportunities 

In the U.S., coal mines account for approximately 10% of all man-made methane emissions. Today, 

there are methane recovery and use projects at mines in Alabama, Colorado, New Mexico, Virginia, and 

West Virginia. As shown in this report, there are many additional gassy coal mines at which projects 

have not yet been developed that offer the potential for the profitable recovery of methane. 

1-1 
In addition to the direct financial benefits that may be enjoyed from the sale of coal mine methane, 

indirect financial and economic benefits may also be achieved. Degasification systems that are used to 

drain methane prevent gas from escaping into mine working areas, increase methane recovery, improve 

worker safety, and significantly reduce ventilation costs at several mines. Increased recovery also 

reduces methane-related mining delays, resulting in increased coal productivity. Furthermore, the 

development of methane recovery projects has been shown to result in the creation of new jobs, which 

has helped to stimulate area economies.1 Additionally, the development of local coal mine methane 

resources may result in the availability of a potentially low-cost supply of gas that could be used to help 

attract new industry to a region. For these reasons, encouraging the development of coal mine methane 

recovery projects is likely to be of growing interest to state and local governments that have candidate 

mines in their jurisdictions. 

For example, some of the mines profiled in this report have methane emissions in excess of ten million 

cubic feet per day (or nearly 4 billion cubic feet per year). To illustrate the impact of methane recovery, 

developing a project at a mine recovering two billion cubic feet per year would result in emissions 

reductions equating to 900,000 tonnes of CO2.

2 Because of the large environmental benefits that may 

be achieved, coal mine methane projects may serve as cost-effective alternatives for utilities and others 

seeking to offset their own greenhouse gas emissions. 

To realize continued emission reductions from the coal mining industry, EPA’s Coalbed Methane 

Outreach Program (CMOP) has worked voluntarily with the coal mining industry and associated 

industries since 1994 to recover and use methane released into and emitted from mines. 

CMOP’s efforts are directed to assist the mining industry by supporting project development, 

overcoming institutional, technical, regulatory and financial barriers to implementation, and educating 

the general public on the benefits of CMM recovery. More specifically, these efforts include: 

• identifying, evaluating and promoting methane reduction options including technological 

innovations and market mechanisms to encourage project implementation; 

• workshops to educate the mining sector on the environmental, mine safety and economic 

benefits of methane recovery; 

• preparing and disseminating reports and other materials that address topics ranging from 

technical and economic analyses to overviews of legal issues; 

• interfacing with all facets of the industry to advance real project development; 

• conducting pre-feasibility and feasibility studies for U.S. mines that examine a range of enduse options; and 

• managing a website that is an important information resource for the coal mine methane 

industry. 

1

 For example, see discussion on this subject in the report "The Environmental and Economic Benefits of Coalbed Methane 

Development in the Appalachian Region" (USEPA, 1994). 

2

 The carbon dioxide equivalent of methane emissions is calculated by determining the weight of methane collected (on a 

100% basis), using a density of 19.2 g/cf. The weight is then multiplied by the global warming potential (GWP) of methane, 

which is 21 times greater than carbon dioxide over a 100 year time period. 

1-2 
Overview of CMM Recovery and Use Techniques 

Methane gas (CH4) and coal are formed together during coalification, a process in which biomass is 

converted by biological and geological processes into coal. Methane is stored within coal seams and 

also within the rock strata surrounding the seams. Methane is released when pressure within a coalbed 

is reduced as a result of natural erosion, faulting, or mining. Deep coal seams tend to have a higher 

average methane content than shallow coal seams, because the capacity to store methane increases as 

pressure increases with depth. Accordingly, underground mines release substantially more methane 

than surface mines, per ton of coal extracted. 

Coal mine methane emissions may be mitigated by the implementation of methane recovery projects at 

underground mines. Mines can use several reliable degasification methods to drain methane. These 

methods have been developed primarily to supplement mine ventilation systems that were designed to 

ensure that methane concentrations in underground mines remain within safe concentrations. While 

these degasification systems are mostly used for safety reasons, they can also recover methane that 

may be employed as an energy resource. Degasification systems include vertical wells (drilled from the 

surface into the coal seam months or years in advance of mining), gob wells (drilled from the surface 

into the coal seam just prior to mining), and in-mine boreholes (drilled from inside the mine into the coal 

seam or the surrounding strata prior to mining). 

The quality (purity) of the gas that is recovered is partially dependent on the degasification method 

employed, and determines how the gas can be used. For example, only high quality gas (typically 

greater than 95% methane) can be used for pipeline injection. Vertical wells and horizontal boreholes 

tend to recover nearly pure methane (over 95% methane). In very gassy mines, gob wells can also 

recover high-quality methane, especially during the first few months of production. Over time, however, 

mine air may become mixed with the methane produced by gob wells, resulting in a lower quality gas. 

Even lower quality methane can be used as an energy source in various applications. Potential 

applications that have been demonstrated in the U.S. and other countries include: 

• electricity generation (the electricity can be used either on-site or can be sold to utilities); 

• as a fuel for on-site preparation plants or mine vehicles, or for nearby industrial or institutional 

facilities; and, 

• cutting-edge applications, such as in fuel cells and ventilation air methane (VAM) technologies. 

It is also possible to enrich lower quality gas to pipeline standards using technologies that separate 

methane from carbon dioxide, oxygen, and/or nitrogen. Several technologies for separating methane 

are under development. Another option for improving the quality of mine gas is blending, which is the 

mixing of lower quality gas with higher quality gas whose heating value exceeds pipeline requirements. 

Even mine ventilation air, which typically contains less than 1% methane, is being successfully used as 

combustion air in gas-fired internal combustion engines in Australia. The technology for using mine 

ventilation air as combustion air in turbines and coal-fired boilers also exists, and research on the use of 

thermal oxidizers and catalytic reactors to generate heat from methane in mine ventilation air is 

underway. The first commercial oxidizer in the world is under construction in Australia and is scheduled 

to begin operating in 2006. 

1-3 
Opportunities for Methane Recovery Projects 

While methane recovery projects already are operating at some of the gassiest mines in the U.S., there 

are numerous additional gassy mines at which recovery projects could be developed. This report 

profiles 50 mines that are potential candidates for the development of coal mine methane projects. At 

least 14 currently operate drainage systems, with drainage efficiencies in the range of 25 to 60 percent. 

Eleven of the draining mines already sell recovered methane.3 Mines that already use drainage systems 

may be especially good candidates for the development of cost-effective methane recovery projects. 

There are also projects at abandoned mines in the U.S.; however, this report only profiles active mines. 

Overview of Methane Liberation, Drainage and Use at Profiled Mines 

This report profiles mines located in 12 states. West Virginia has the largest number of profiled mines 

(15), followed by Kentucky (8), and Alabama (6). In 2003, the 50 mines profiled in this report liberated an 

estimated 347 mmcf/d of methane, or about 127 Bcf/yr (95% of all methane liberated from underground 

mines). Table 1-1 shows the number of profiled mines and the estimated total methane liberated from 

these mines, summarizing information presented in the state summaries and individual mine profiles 

(Chapter 6). Chapter 4 explains how these data were derived. 

Table 1-1 shows that about 31% of the total estimated methane liberated from all profiled mines is being 

used. Table 1-1 also shows estimated annual methane emissions from the mines that are operating but 

not using methane and the estimated annual methane emissions that would be avoided by implementing 

methane recovery and use projects at these mines, assuming a 20-60% range of recovery efficiency. 

Based on these recovery efficiencies, if methane recovery projects were implemented at profiled mines 

that are currently operating but do not recover methane, an estimated 9-27 Bcf/yr of methane emissions 

would be avoided. This is equivalent to about 4-12 mmt/yr of CO2. Moreover, there is significant 

potential for increased methane recovery at many of the mines that already have recovery projects. 

Overview of U.S. Mining Industry Since 2001 

Significant changes occurred in the U.S. mining industry between 2001 and 2003. Several noteworthy 

trends unfolded since the 2001 surge in coal production. In 2003, production levels returned to normal 

and the year was characterized by a decline in the overall number of mining operations in the U.S. 

Underlining the consolidation were mine closures and bankruptcy filings concentrated in the Eastern 

coal markets. Production in the Illinois Basin held steady while Western mines continued to produce at 

or above record levels. 

Regarding the mines profiled in this report, there are 11 mines that did not appear in the previous 

version of this report. Three new gassy mines have opened since 2001; they include Deep Mine #26 in 

Virginia, Elk Creek mine in Colorado, and Willow Lake Portal mine in Illinois. The other eight mines 

profiled in 2003, but not in 2001, generally saw a considerable increase in production, and all eight 

mines have become gassier. Since 2001, two additional CMM recovery and use projects came online 

as West Elk (CO) and San Juan South (NW) began recovering methane. As for the eleven mines 

profiled in 2001, but not in this version of the report, five have closed or been idled, and six are less 

gassy in 2003 than they were in 2001. 

Other developments having a significant impact on mining operations and/or production are highlighted 

below: 

• Fires affected production at three mines since 2001: CONSOL extinguished a fire at Mine No. 84, 

Loveridge was idled due to a fire in March of 2003, and JWR’s No. 5 mine suffered an explosion/fire 

in September of 2001 (production has since resumed). 

Please see Chapter 4 for a more detailed discussion of this issue. 

1-4 

3 
• CONSOL expanded its McElroy mine and spent $180 million to improve prep plant throughput 

capacity to 2000 tph. CONSOL also signed a 17 year supply deal with First Energy. 

• In Utah, Andalex Resources completed a move of longwall mining equipment from its Aberdeen 

mine to the West Ridge mine. 

• During the fall of 2001 U.S. Steel decided against closing its Oak Grove mine in Alabama. 

• Anker Coal Group filed for bankruptcy protection in 2002. They restructured debt and reopened the 

Sentinel Mine which had been idled since May of 2002. 

• BHP Billiton’s San Juan South mine – originally a surface mine – was added to Coal Age’s Longwall 

Census in 2002. 

• Baker mine in Kentucky was idled after Lodestar Energy ceased operations at the end of 2003. 

Table 1-1: U.S. Summary Table 

Number of Profiled Mines and Estimated Methane Liberated and Used in 20031 

Operating but not 

Using Methane 

Operating and Using 

Methane All Mines Profiled in This Report 

State Number 

of Mines 

Total 

Methane 

Liberated 

(mmcf/d) 

Number 

of Mines 

Total 

Methane 

Liberated 

(mmcf/d) 

Number 

of Mines 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Methane Use 

(mmcf/d) 

Alabama 1 4.2 5 74.0 6 78.2 28 

Colorado 1 1.1 1 27.2 2 28.3 0.1 

Illinois 4 7.1 0 0.0 4 7.1 0 

Indiana 1 2.4 0 0.0 1 2.4 0 

Kentucky 8 7.2 0 0.0 8 7.2 0 

 New Mexico 0 0 1 3.6 1 3.6 0.1 

Ohio 1 1.1 0 0.0 1 1.1 0 

Oklahoma 1 1.0 0 0.0 1 1.0 0 

Pennsylvania 5 56.9 0 0.0 5 56.9 0 

Utah 3 7.0 0 0.0 3 7.0 0 

Virginia 1 1.9 2 88.9 3 90.8 76 

West Virginia 12 32.4 3 31.2 15 63.6 6 

TOTAL2: 38 122.2 12 224.9 50 347.1 109 

Estimated Emissions and Avoided Emissions of Methane and CO2 

Equivalent from Operating Mines not Currently Using Methane 

(38 mines): 

Methane 

(Bcf/y) 

CO2 

(mmt/y) 

2003 Estimated Total Emissions 44.6 19.8 

Estimated Annual Avoided Emissions if Recovery Projects are 

Implemented 8.9 – 26.8 4.0 – 11.9 

1

Chapter 4 explains how these data were estimated. 

2

 Values shown here do not always sum to totals due to rounding. 

1-5 
Summary of Opportunities for Project Development 

Most underground coal mines still do not recover and use methane, however, the profiles indicate that 

many of these mines appear to be strong candidates for cost-effective recovery projects. Furthermore, 

this report contains information suggesting that substantial environmental, economic, and energy 

benefits could be achieved if mines that currently emit methane were to recover and use it. 

The mines profiled in this report are quite variable in terms of the amount of methane they liberate, their 

gassiness or "specific emissions" (methane liberated per ton of coal mined), and their annual coal 

production. The volume of methane liberated from each mine ranges from less than 0.7 mmcf/d to over 

40 mmcf/d. Similarly, specific emissions range from 84 cf/ton to approximately 9,000 cf/ton. Annual coal 

production ranges from approximately 300,000 tons at some mines to nearly 10 million tons per year at 

others. All these factors are important indicators of the potential profitability of developing a project at an 

individual mine. Furthermore, as shown in the profiles (Chapter 6), the candidate mines vary with 

respect to other important factors that affect profitability, such as the distance from the mine to a pipeline 

or the projected remaining productive life of the mine. Accordingly, the overall feasibility of developing a 

methane recovery project will likely vary widely among the candidate mines. 

Although a number of the mines profiled here show strong potential for profitable projects, methane 

ventures at these mines are not currently being developed, due to a number of barriers to coal mine 

methane development. Many of these barriers are being overcome. Gas prices have improved, 

increasing the economic benefits of coalbed methane recovery. Restructuring of the gas industry has 

created new market opportunities for coal mine methane, and the potential for distributed generation is 

increasing as a result of electricity industry restructuring. At the same time, utilities and other industries 

are seeking opportunities to offset greenhouse gas emissions and to develop "environmentally friendly" 

projects. If projects are initiated at even a few of the mines profiled here, substantial methane emissions 

reductions and increased profits for developers could be achieved, thereby benefiting the U.S. economy 

and the global environment. 

The following list summarizes the chapters in this report: 

• Chapter 2 provides an introduction to coal mine methane in the U.S., including a discussion of 

major developments in the burgeoning coal mine methane recovery industry that have transpired 

since publication of the previous version of this report in 2004. 

• Chapter 3 discusses current coal mine methane recovery projects in the U.S. 

• Chapter 4 provides a key to evaluating the mine profiles. 

• Chapter 5 presents the mine summary tables. 

• Chapter 6 lists state summaries and actual mine profiles, which should assist potential investors 

in assessing the overall potential project profitability. 

1-6 
2. Introduction 
_________________________________________________________________________________________ 

2. Introduction 

Purpose of Report 

This report provides information about specific opportunities to develop methane recovery and use 

projects at large underground mines in the United States. Groups that may be interested in identifying 

such opportunities include utilities, natural gas resource developers, independent power producers, 

and local industries or institutions that could directly use the methane recovered from a nearby mine. 

This introduction provides a broad overview of the technical, economic, regulatory, and environmental 

issues concerning methane recovery from coal mines. The report also presents an overview of 

existing methane recovery and use projects (Chapter 3). Chapter 4 contains Information that will 

assist the reader in understanding and evaluating the data presented in Chapters 5 and 6. Chapter 5 

contains data summary tables, and finally, Chapter 6 profiles individual underground coal mines that 

appear to be good candidates for the development of methane recovery projects. 

Recent Developments in the Coal Mine Methane Industry 

Since the last version of this document was published in July 2004, there have been significant 

developments in coal mine methane recovery, particularly in the number of active recovery and use 

projects. The number of mines with active methane recovery and use projects has increased from 10 

in 2001 to 12 in 2003. However, the amount of methane recovered has stayed nearly the same as in 

2001 at around 40 Bcf (43 Bcf recovered in 2002). At a gas price of $4.88/mcf4

, this means that coal 

mine methane developers had revenues of $195 million in 2003. The resulting decrease in methane 

emissions has yielded benefits to the global environment through a greenhouse gas emission 

reduction of 18 MMT/year of CO2 in 2003. Figure 2-1 shows the number of mines engaging in coal 

mine methane recovery since 1994 while Figure 2-2 shows the growth in the amount of gas being 

recovered. 

The growth in the amount of recovered methane since 1990 can be attributed to five primary factors: 

1) continued use in natural gas pipelines; 2) use for a variety of purposes besides pipeline injection; 3) 

legislation concerning ownership issues has been enacted in most coalbed methane producing 

states; 4) various projects have proven the profit-generating potential of coal mine methane recovery; 

and 5) growing awareness of the climate change impacts of methane emissions. Also, the issuance 

of FERC Orders 636 in 1992 and 888 in 1996 continues to remove barriers to free and open 

competition in the natural gas and electric utility industries, respectively. As a result of these orders, 

coal mine methane developers have been encountering fewer problems accessing the available 

capacity of the nation's gas and electric transmission lines. 

4

 EIA – average wellhead price for 2003. 

Introduction 2-1
_________________________________________________________________________________________ 

Figure 2-1: Mines with Active Coal Mine Methane Recovery Projects 

Methane Recovery Projects (by State) 

0 2 4 6 8 10 12 14 16 

Alabama 

Colorado 

New Mexico 

Pennsylvania 

Utah 

Virginia 

West Virginia 

Total 

Number of Mines with Methane Recovery Projects

 (based on publicly available information) 

2003 

2001 

1997 

1994 

Figure 2-2: Estimated Annual Use of Methane Recovered From U.S. Coal Mines 

(based on publicly available information) 

0 

10 

20 

30 

40 

50 

Methane Use (Bcf) 

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 

Year 

Overview of Coal Mine Methane 

Methane and coal are formed together during coalification, a process in which vegetation is converted 

by geological and biological forces into coal. Methane is stored in large quantities within coal seams 

and also within the rock strata surrounding the seams. Two of the most important factors determining 

the amount of methane that will be stored in a coal seam and the surrounding strata are the rank and 

the depth of the coal. Coal is ranked by its carbon content; coals of a higher rank have a higher 

Introduction 2-2 
_________________________________________________________________________________________ 

carbon content and generally a higher methane content.5 The capacity to store methane increases as 

pressure increases with depth. Thus, within a given coal rank, deep coal seams tend to have a higher 

methane content than shallow ones. 

Methane concentrations typically increase with depth, therefore underground mines tend to release 

significantly higher quantities of methane per ton of coal mined than do surface mines. In 2003, while 

only 33 percent of U.S. coal was produced in underground mines, these mines accounted for over 70 

percent of estimated methane emissions from coal mining (USEPA, 2005). Although the options for 

recovering and using methane are primarily available for underground mines, gas recovery at surface 

mines may also be feasible. Among underground mines, the largest and gassiest mines typically 

have the best potential for profitable recovery and utilization of methane. 

Methane emissions resulting from coal mining activities account for about 10 percent of annual global 

methane emissions from anthropogenic (man-made) sources. In 2001, The People's Republic of 

China was the largest emitter of coal mine methane, followed by the United States and then Russia, 

Ukraine and Australia (USEPA, 2001). In 2003, coal mining emissions were estimated to account for 

9.9 percent of total U.S. methane emissions (USEPA, 2005), down from 11.3 percent in 1995. 

In underground mines, methane poses a serious safety hazard for miners because it is explosive in 

low concentrations (5 to 15 percent in air). In the U.S., methane concentrations in the mine may not 

exceed one percent in mine working areas and two percent in all other locations. In many 

underground mines, methane emissions can be controlled solely through the use of a ventilation 

system, which pumps large quantities of air through the mine in order to dilute the methane to safe 

levels. The coal mine methane (CMM) released to the atmosphere by the mine ventilation system is 

typically below 1 percent. This methane vented from coal mine exhaust shafts constitutes the largest 

source of coal mine methane emissions in the U.S. In 2003, for example, 71 billion cubic feet (Bcf) or 

56% of the 127 Bcf released from underground mines was released through mine ventilation systems. 

In particularly gassy mines, however, the ventilation system must be supplemented with a drainage 

system. Drainage systems reduce the quantity of methane in the working areas by draining the gas 

from the coal-bearing strata before, during, or after mining, depending on mining needs. Emissions 

from drainage systems are estimated to account for approximately one third of the total methane 

emissions from underground coal mining. At least 17 of the mines profiled in this report have some 

type of drainage system. 

Methane Drainage Techniques 

Over the years, mine operators have realized the economic benefits of employing drainage systems. 

For mines that have drainage systems in place, the cost of ventilation is significantly reduced because 

the drainage systems recover a significant percentage of the associated methane. Use of methane 

drainage systems also help reduce production costs, as there are typically fewer methane-related 

delays at mines that employ drainage systems (Kim and Mutmansky, 1990). Today, methane 

drainage is a proven technology and much of the gas that is recovered can be used in various 

applications. 

While drainage systems are currently used primarily for economic and safety reasons to ensure that 

methane concentrations remain below acceptable levels, these systems recover methane that also 

 In descending order, the ranks of coal are: graphite, anthracite, bituminous, sub-bituminous, and lignite. Most U.S. 

production is bituminous or sub-bituminous. 

Introduction 2-3 

5
_________________________________________________________________________________________ 

can be employed as an energy source. The quantity and quality of the methane recovered will vary 

according to the method used. The quality of the recovered methane is measured by its heating 

value. Pure methane has a heating value of about 1000 British Thermal Units per cubic foot (Btu/cf), 

while a mixture of 50 percent methane and 50 percent air has a heating value of approximately 500 

Btu/cf. 

Drainage methods include vertical wells (vertical pre-mine), gob wells (vertical gob), longhole 

horizontal boreholes, and horizontal and cross-measure boreholes. The preferred recovery method 

will depend, in part, on mining methods and on how the methane will be used. In some cases, an 

integrated approach using a combination of the above drainage methods will lead to the highest 

recovery of methane. The key features of the methane recovery methods are discussed in more 

detail below and are summarized in Table 2-1. 

Vertical Pre-Mining Wells 

Vertical pre-mining wells are the optimal method for recovering high quality gas from the coal seam 

and the surrounding strata before mining operations begin. Pre-mine drainage ensures that the 

recovered methane will not be contaminated with ventilation air from mine working areas. Similar in 

design to conventional oil and gas wells, vertical wells can be drilled into the coal seam several years 

in advance of mining. Vertical wells, which may require hydraulic or nitrogen fracturing of the coal 

seam to activate the flow of methane, typically produce gas of over 90 percent purity. However, these 

wells may produce large quantities of water and small volumes of methane during the first several 

months they are in operation. As this water is removed and the pressure in the coal seam is lowered, 

methane production increases. 

The total amount of methane recovered using vertical pre-drainage will depend on site-specific 

conditions and on the number of years the wells are drilled prior to the start of mining. Recovery of 

from 50 to over 70 percent of the methane that would otherwise be emitted during mining operations 

is likely for operations in which vertical degasification wells are drilled more than 10 years in advance 

of mining. Although not previously used widely in the coal mining industry, vertical wells are 

increasing in popularity within the coal industry, and are used by numerous stand-alone operations6 

that produce methane from coal seams for sale to natural gas pipelines. In some very low 

permeability coal seams, vertical wells may not be a cost-effective technology due to limited methane 

flow. Vertical wells, however, will likely continue to be a viable recovery technology for most 

underground mines. 

Eight underground mines in the U.S. currently use vertical pre-mining wells. A majority of these mines 

already recover methane for pipeline sales (see section on existing methane recovery projects). 

Figure 2-3 illustrates a vertical pre-mine well. 

6

 The term "stand-alone" refers to coalbed methane operations that recover methane for its own economic value. In most 

cases, these operations recover methane from deep and gassy coal seams that are not likely to be mined in the near future. 

Introduction 2-4 
_________________________________________________________________________________________ 

Figure 2-3: Vertical Pre-Mining Gob, and Horizontal Boreholes 

 Gob Wells 

Gob wells are drilled from the surface to a point 10 to 50 feet above the target seam prior to mining. 

As mining advances under the well, the methane-charged strata that surround the well fracture. 

Relaxation and collapse of strata surrounding the coal seam creates a fractured zone known as the 

"gob" area, which is a significant source of methane. Methane emitted from the gob flows into the gob 

well and up to the surface. A vacuum is frequently used on the gob wells to prevent methane from 

entering mine working areas. 

Initially, gob wells produce nearly pure methane. Over time, however, additional amounts of mine air 

can flow into the gob area and dilute the methane. The heating value of "gob gas" normally ranges 

between 300 and 800 Btu/cf. In some cases, it is possible to maintain nearly pure methane production 

from gob wells through careful monitoring and management. Jim Walter Resources, CONSOL, and 

Peabody are all using techniques for producing high-quality gas from gob wells. Gas production rates 

from gob wells can be very high, especially immediately following the fracturing of the strata as mining 

advances under the well. Jim Walter Resources reports that gob wells initially produce at rates in 

excess of two million cubic feet per day. Over time, production rates typically decline until a relatively 

stable rate is achieved, typically in the range of 100 mcf/d. Depending on the number and spacing of 

the wells, gob wells can recover an estimated 30 percent to over 50 percent of methane emissions 

associated with coal mining (USEPA, 1990). 

Seventeen U.S. mines currently use surface gob wells to reduce methane levels in mine working 

areas. Most mines release methane drained from gob wells into the atmosphere. Figure 2-3 

illustrates a vertical gob well. 

Introduction 2-5 
_________________________________________________________________________________________ 

Gob

 Horizontal Boreholes 

Horizontal boreholes are drilled inside the mine (as opposed to from the surface) and they drain 

methane from the unmined areas of the coal seam, or from blocked out longwall panels shortly before 

mining takes place. These boreholes are typically 400 to 800 feet in length. Several hundred 

boreholes may be drilled within a single mine and connected to an in-mine vacuum piping system, 

which transports the methane out of the mine and to the surface. Most often, horizontal boreholes are 

used for short-term methane emissions relief during mining. Because methane drainage only occurs 

from the mined coal seam (and not from the surrounding strata), the recovery efficiency of this 

technique is low – approximately 10 to 18 percent of methane that would otherwise be emitted 

(USEPA, 1990). However, this methane typically can have a heating value of over 950 Btu/cf 

(USEPA, 1991). Approximately 16 underground mines in the U.S. currently use this technique to 

reduce the quantity of methane in mine working areas. Figures 2-3 and 2-4 illustrate horizontal 

boreholes. 

Figure 2-4: Horizontal and Cross-Measure Boreholes 

Cross Measure Boreholes 

Horizontal Boreholes 

GOB 

Longhole Horizontal Boreholes 

Like horizontal boreholes, longhole horizontal boreholes are drilled from inside the mine in advance of 

mining. They are greater than 1000 feet in length and are drilled in unmined seams using directional 

drilling techniques. Longhole horizontal boreholes produce nearly pure methane with a recovery 

efficiency of about 50% and therefore can be used when high quality gas is desired. This technique is 

most effective for gassy, low permeability coal seams that require long diffusion periods. Both West 

Elk Mine in Colorado and San Juan South Mine in New Mexico have employed longhole horizontal 

boreholes in their drainage programs. 

Introduction 2-6
_________________________________________________________________________________________ 

 Cross-Measure Boreholes 

Cross-measure boreholes degasify the overlying and underlying rock strata surrounding the target 

coal seam. These boreholes are drilled inside the mine and they drain methane with a heating value 

similar to that of gob wells. Cross-measure boreholes have been used extensively in Europe and Asia 

but are not widely used in the United States where surface gob wells are preferred. West Elk Mine in 

Colorado has employed cross-measured boreholes in the past. Figure 2-4 illustrates cross-measure 

boreholes. 

Table 2-1 

Summary of Drainage Methods 

Method Description Gas Quality Drainage Current Use in U.S. 

Efficiency

a Coal Minesb 

Vertical Pre- Drilled from surface Produces nearly up to 70% Used by 8 mines. 

Mine Wells to coal seam months pure methane. 

or years in advance 

of mining. 

Gob Wells Drilled from surface Produces methane up to 50% Used by 17 mines. 

to a few feet above that is sometimes 

coal seam just prior contaminated with 

to mining. mine air. 

Horizontal Drilled from inside Produces nearly up to 20% Used by 16 mines. 

Boreholes the mine to degasify pure methane. 

the coal seam 

shortly prior to 

mining. 

Longhole Drilled from inside Produces nearly up to 50% Used by at least 2 

Horizontal the mine to degasify pure methane. mines. 

Boreholes the coal seam 

shortly prior to 

mining. 

Cross-measure Drilled from inside Produces methane Up to 20% Not widely used in 

Boreholes the mine to degasify that is sometimes the U.S.c 

surrounding rock contaminated with 

strata shortly prior to mine air. 

mining. 

Source: USEPA (1993) & USEPA (2005) 

a

 Percent of total methane liberated that is drained. 

b

 Accurate only at the time of publication of this report, may vary often as mining progresses. c

 Used at West Elk Mine at one time. 

Utilization Options 

Once recovered, coal mine methane is an energy source available for many different applications. 

Potential utilization options are pipeline injection, electricity generation, and direct use in on-site prepplants or to fuel mine vehicles, or at nearby industrial or institutional facilities. Following is a 

discussion of various utilization methods. Table 2-2 shows the recovery methods that may be 

employed for each utilization option. 

Introduction 2-7
_________________________________________________________________________________________ 

Table 2-2 

Utilization Options for Coalbed Methane 

Utilization Options Range of Btu 

Quality 

(Btu/cf) 

Recovery Method 

Pipeline Injection 

Power Generation 

Local Use (at on-site coal prep plant or to fuel 

mine vehicles, or at nearby industrial or 

institutional facilities) 

> 950 Vertical Wells 

(Pre-mining 

degasification) 

Pipeline Injection – requires: 300 to 950 Gob Wells 

(1) maintaining pipeline quality, or 

(2) gas enrichment 

Power Generation 

Local Use 

Pipeline Injection 

Power Generation 

Local Use 

up to 950 In-Mine Boreholes 

Use ventilation air methane as combustion air 

in gas-fired IC engines, gas turbines or coalfired boilers; thermal oxidation; catalytic 

reactors; VOC concentrators; lean fuel gas 

turbines 

1 to 20 Ventilation Air 

Sources: USEPA (1990); USEPA (1991); USEPA (2005) 

 Pipeline Injection 

Methane liberated during coal mining may be recovered and collected for sale to pipeline companies. 

The key issues that will determine project feasibility are: 1) whether the recovered gas can meet 

pipeline quality standards; and 2) whether the costs of production, processing, compression and 

transportation are competitive with other gas sources. 

U.S. experience demonstrates that selling recovered methane to a pipeline can be profitable for 

mining companies and is by far the most popular use method. As shown in Table 2-3, 11 of the 

profiled mines currently sell methane from their drainage systems to local pipeline companies. 

Chapter 3 contains additional information on these projects. 

 Technical Feasibility 

The primary technical consideration involved in collecting coal mine methane for pipeline sales is that 

the recovered methane must meet the standards for "pipeline quality" gas. First, it must have a 

methane concentration of at least 95 percent and contain no more than a 2 percent concentration of 

gases that do not burn (i.e., carbon dioxide, nitrogen, helium). Additionally, any non-methane 

hydrocarbons are usually removed from the gas stream for other uses. Hydrogen sulfide (which 

mixes with water to make sulfuric acid) and hydrogen (which makes pipes brittle) must also be 

removed before the gas is introduced into the pipeline system. Finally, any water or sand produced 

with the gas must be removed to prevent damage to the system. While coalbed methane requires 

water removal, it is often free of hydrogen sulfide and other impurities typically found in natural gas. 

Introduction 2-8 
_________________________________________________________________________________________ 

With proper recovery and treatment, coalbed methane can meet the requirements for pipeline quality 

gas. 

Table 2-3 

Current Coal Mine Methane Pipeline Projects at Profiled Mines 

Number of Mining Company State Active Mines 

Jim Walter Resources 3 Alabama 

U.S. Steel Mining 2 Alabama, West Virginia 

Drummond Coal 1 Alabama 

CONSOL 1 West Virginia/Pennsylvania* 

Eastern Associated Coal 1 West Virginia 

(Peabody) 

BHP Billiton 1 New Mexico 

CONSOL Coal Group 2 Virginia 

* While the main entries for this mine and two abandoned mines (which are part of a 

single methane recovery project) are located in West Virginia, significant portions of 

the mines extend into Pennsylvania, and most of the gas production is from 

Pennsylvania. 

Vertical degas wells are the preferred recovery method for producing pipeline quality methane from 

coal seams because pre-mining drainage ensures that the recovered methane is not contaminated 

with ventilation air from the working areas of the mine. Gob wells, in contrast, generally do not 

produce pipeline quality gas as the methane is frequently mixed with ventilation air. In certain cases, 

however, it is possible to maintain a higher and more consistent gas quality through careful monitoring 

and adjustment of the vacuum pressure in gob wells. 

It is also possible to enrich gob gas to pipeline quality by using technologies that separate methane 

from carbon dioxide, oxygen, and/or nitrogen. Several technologies for separating methane are under 

development and may prove to be economically attractive and technically feasible with additional 

research (USEPA Technical Option Series). One such project currently operating is at the Blue Creek 

#4, #5, and #7 mines operated by JWR where a cryogenic gas processing unit was installed in 2000 

to upgrade medium-quality gas, recovered from gob wells, to pipeline quality gas. Pressure swing 

adsorption is also being utilized. 

Another option for improving the quality of mine gas is blending, which is the mixing of lower Btu gas 

with higher Btu gas whose heating value exceeds pipeline requirements. As a result of blending, the 

Btu content of the overall mixture can meet acceptable levels for pipeline injection. For example, 

CONSOL is blending gob gas recovered from the VP #8 and Buchanan mines in Virginia with coalbed 

methane production for pipeline injection. 

Horizontal boreholes and longhole horizontal boreholes also can produce pipeline quality gas when 

the integrity of the in-mine piping system is closely monitored. However, the amount of methane 

produced from these methods is sometimes not large enough to warrant investments in the necessary 

surface facilities. In cases where mines are developing utilization strategies for larger amounts of gas 

Introduction 2-9 
_________________________________________________________________________________________ 

recovered from vertical or gob wells, it may be possible to use the gas recovered from in-mine 

boreholes to supplement production. 

Profitability 

The overall profitability of recovering methane for pipeline injection will depend on a number of 

factors. These factors include the amount and quality of methane recovered (as discussed above), 

the capital and operating costs for wells, water disposal, compression and gathering systems, and 

most importantly, the price at which the recovered gas may be sold. 

The costs for disposal of production water from vertical wells may be a significant factor in 

determining the economic viability of a project, as discussed later in this chapter ("Production 

Characteristics of Coalbed Methane Wells"). The cost of gas gathering lines is another 

consideration. Because costs for laying gathering lines are high, proximity to existing commercial 

pipelines is a significant factor in determining the economic viability of a coalbed methane project. 

Most coal mines are located within 20 miles of a commercial pipeline (See Chapter 6). However, in 

some cases, existing pipelines may have limited capacity for transporting additional gas supplies. 

Costs for laying gathering lines vary widely depending, in part, on terrain. The hilly and mountainous 

terrain in many mining areas increases the difficulty, and thus the cost, of installing gathering lines. 

Another determinant of the overall profitability of a pipeline injection project is a mine's ability to find a 

purchaser for its recovered gas. A methane recovery project will also need to demonstrate that its 

recovered methane is of the requisite pipeline quality. 

 Power Generation 

Coalbed methane may also be used as a fuel for power generation. Unlike pipeline injection, power 

generation does not require pipeline quality methane. Gas turbines can generate electricity using 

methane that has a heat content of 350 Btu/cf. Mines can use electricity generated from recovered 

methane to meet their own on-site electricity requirements and can sell electricity generated in excess 

of on-site needs to utilities. An example is an 88 MW power generation station developed by 

CONSOL Energy and Allegheny Energy, placed near the VP #8 and Buchanan mines, fueled by 

coalbed methane and coal mine methane. Power generated is sold to the competitive wholesale 

market. The 88 MW project, though, is currently the world’s largest CMM-fired power plant. More 

typical are projects in the 1-10 MW range, and there is currently a 1.2 MW project using internal 

combustion engines at the Federal No. 2 Mine in West Virginia. In addition to the two U.S. projects, 

power generation projects are reported to be operating at coal mines in several other countries 

including China, Australia, UK and Germany. 

 Technical Feasibility 

A methane/air mixture with a heating value of at least 350 Btu/cf is a suitable gaseous fuel for 

electricity generation. Accordingly, vertical degas wells, gob wells, and in-mine boreholes are all 

acceptable methods of recovering methane for generating power. Gas turbines, internal combustion 

(IC) engines, and boiler/steam turbines can all be adapted to generate electricity from coalbed 

methane. Fuel cells may also prove to be a promising option and are currently being tested at the 

Nelms Portal Mine7

 in Ohio where a 250 kW Direct FuelCell®, manufactured by FuelCell Energy, Inc., 

will be set up to deliver power to the local utility. This project is being cost-shared by the Department 

of Energy. 

7

 Not profiled in this edition of the report. 

Introduction 2-10 
_________________________________________________________________________________________ 

Currently, the most likely generator choice for a coalbed methane project would be either a gas 

turbine or an IC engine. Boiler/steam turbines are generally not cost effective in sizes below 30 MW, 

while gas turbines are not the optimal choice for projects requiring 1.5 MW or less. However, when 

used in the right applications gas turbines are smaller and lighter than IC engines and historically 

have had lower operation and maintenance costs. 

While maintaining pipeline quality gas output from gob wells can be difficult, the heating value of gob 

gas is generally compatible with the combustion needs of gas turbines. One potential problem with 

using gob gas is that production, methane concentration, and rate of flow are generally not 

predictable; wide variations in the Btu content of the fuel may create operating difficulties. Equipment 

for blending the air and methane may be needed to ensure that variations in the heating value of the 

fuel remain within an acceptable range – approximately ten percent allowable variability for gas 

turbines. 

A potential advantage of using vertical pre-mine wells as the recovery method for power generation is 

that the quantity and quality of methane produced is more consistent than that of gob wells. Thus, 

problems stemming from variations in the heating value of the fuel would be minimized where vertical 

wells are employed. Another option is to blend high quality gas from vertical wells with lower quality 

gas from gob wells to ensure consistent quality. Horizontal boreholes also can produce gas of 

consistently high quality. The limited quantity of gas produced by this method would likely need to be 

supplemented by larger quantities of methane from vertical or gob wells, however. 

The level of electric capacity that may be generated depends on the amount of methane recovered 

and the "heat rate" (i.e., Btu to kWh conversion) of the generator. For example, simple cycle gas 

turbines typically have heat rates in the range of 10,000 Btu/kWh, while combined cycle gas turbines 

could have heat rates of 7,000 Btu/kWh. Assuming a conservative heat rate of 11,000 Btu/kWh and 

assuming that mines could recover 35 percent of total emissions, the level of electric capacity that 

could be sustained by the top twenty methane-emitting mines would likely exceed 10 MW per mine. 

Profitability: Power Generation for On-Site Use 

Given their large energy requirements, coal mines may realize significant economic savings by 

generating power from recovered methane. Nearly every piece of equipment in an underground mine 

operates on electricity, including mining machines, conveyor belts, ventilation fans, and elevators. 

Much of the equipment at typical mines is operated 250 days a year, two shifts per day. Ventilation 

systems, however, must run 24 hours a day, 365 days a year, and they demand a considerable 

amount of electricity – up to 60 percent of the mine's total needs (USBM, 1992). 

A mine's total electricity needs can exceed 24 kWh per ton of coal mined. Since many of the largest 

underground mines in the U.S. produce more than 3 million tons of coal annually, they may purchase 

over 72 million kWh of electricity annually. At average industrial electricity rates of five cents per kWh, 

a mine's electricity bill can exceed several million dollars a year. 

Coal preparation plants, which are frequently located near large mines, also consume a great deal of 

energy. Preparation involves crushing, cleaning, and drying the coal before its final sale. Coal drying 

operations require thermal energy, which could be generated by a turbine or engine in a cogeneration 

cycle. Coal preparation generally requires an additional 6 kWh per ton of coal (ICF Resources, 

1990a). CONSOL currently recovers approximately 2 mmcf/d from the VP #8 and Buchanan mines 

for use in their thermal dryer. 

Introduction 2-11 
_________________________________________________________________________________________ 

Among the main factors in determining the economic viability of generating power for on-site use are 

the total amount and flow of the methane recovered, the capital costs of the generator, the expected 

lifetime of the project, and the price the mine pays for the electricity it uses. A mine would need to be 

fairly large to recover an amount of methane that would justify the capital expenditures for a generator 

and other equipment needed for utilizing power on-site. Moreover, because the $/kW capital cost of a 

generator is relatively high in terms of the overall economics of a coalbed methane power project, the 

mine would need to generate power for several years in order to justify the capital investment. A final 

economic consideration is the cost of back-up power, which is typically supplied by a utility and is 

essential for mining operations given their safety considerations. 

Profitability: Off-Site Sale to a Utility 

Large and gassy coal mines may be able to generate electric power from recovered methane in 

excess of their own power requirements. In such cases, a mine may be able to profit from selling 

power to a nearby utility. Additionally, under some circumstances, a mine might arrange to sell 

electricity to a utility, but continue to purchase electricity from the utility for its own on-site use. The 

economic feasibility of selling power off-site would depend on the amount of electricity that could be 

generated, the incremental costs of selling power to a utility, and the price received for the electricity. 

If a mine is generating power to meet its own electricity needs, the incremental costs of selling excess 

power off-site are relatively low. Normally, a coal mine already has a large transmission line running 

from a main transmission line to the mine substation. In most cases, this same line could be used to 

transmit power from the mine back to the utility. For some mines, an interconnection facility or line 

upgrades may be needed to feed this additional power into the main line. 

Ventilation Air Methane Use Technologies 

Ventilation air methane (VAM) is now recognized as an unused source of energy and a potent 

atmospheric greenhouse gas (GHG). A host of recently introduced technologies can reduce 

ventilation air methane emissions, while harnessing methane’s energy, and can offer significant 

benefits to the world community. 

USEPA (2000) identified two technologies for destroying or beneficially using the methane contained 

in ventilation air: the VOCSIDIZER,8

 a thermal flow-reversal reactor developed by MEGTEC Systems 

(De Pere, Wisconsin, United States), and a catalytic flow-reversal reactor developed expressly for 

mine ventilation air by Canadian Mineral and Energy Technologies (CANMET—Varennes, Quebec, 

Canada). Both technologies employ similar principles to oxidize methane contained in mine ventilation 

airflows. Based on laboratory and field experience, both units can sustain operation (i.e., can maintain 

oxidation) with ventilation air having uniform methane concentrations down to approximately 0.1 

percent. For practical field applications where methane concentrations are likely to vary over time, 

however, this analysis assumes that a practical average lower concentration limit at which oxidizers 

will function reliably is 1.5 percent. 

In addition, a variety of other technologies such as boilers, engines, and turbines may use ventilation 

airflows as combustion air. At least two other technology families may also prove to be viable 

candidates for beneficially using VAM. These are VOC concentrators and new lean fuel gas turbines. 

8

 VOCSIDIZER is a registered trademark of MEGTEC Systems.

Introduction 2-12
_________________________________________________________________________________________ 

Thermal Flow Reversal Reactor 

Figure 2.5 shows a schematic of the Thermal Flow Reversal Reactor (TFRR). The equipment consists 

of a bed of silica gravel or ceramic heat-exchange medium with a set of electric heating elements in 

the center. The TFRR process employs the principle of regenerative heat exchange between a gas 

and a solid bed of heat-exchange medium. To start the operation, electric heating elements preheat 

the middle of the bed to the temperature required to initiate methane oxidation (above 1,000°C 

[1,832°F]) or hotter. Ventilation air at ambient temperature enters and flows through the reactor in one 

direction and its temperature increases until oxidation of the methane takes place near the center of 

the bed. 

The hot products of oxidation continue through the bed, losing heat to the far side of the bed in the 

process. When the far side of the bed is sufficiently hot, the reactor automatically reverses the 

direction of ventilation airflow. The ventilation air now enters the far (hot) side of the bed, where it 

encounters auto-oxidation temperatures near the center of the bed and then oxidizes. The hot gases 

again transfer heat to the near (cold) side of the bed and exit the reactor. Then, the process again 

reverses. 

TFRR units are effectively employed worldwide to oxidize industrial VOC streams. Recently, their 

ability to oxidize VAM has been demonstrated in the field. 

Catalytic Flow Reversal Reactor 

Catalytic flow reversal reactors adapt the thermal flow reversal technology described above by 

including a catalyst to reduce the auto-oxidation temperature of methane by several hundred degrees 

Celsius (to as low as 350°C [662°F]). CANMET has demonstrated this system in pilot plants and is 

now in the process of licensing Neill and Gunter of Dartmouth, Nova Scotia, to commercialize the 

design (under the name VAMOX). 

Figure 2-5. Thermal Flow-Reversal Reactor 

Air, CO 2, 

Air & H 2O & 

CH 4 Heat* 

Valve 1 

Valve #1 open = 

Valve #2 open 

=*Heat recovery piping not 

shown 

Valve 2 

Valve 2 Valve 1 H eat Exchange 

M edium 

Heat 

Exchanger 

H eat Exchange 

M edium 

CANMET is also studying energy recovery options for profitable turbine electricity generation. 

Injecting a small amount of methane (gob gas or other source) increases the methane concentration 

in ventilation air and can make the turbine function more efficiently. Waste heat from the oxidizer is 

also used to pre-heat the compressed air before it enters the expansion side of the gas turbine. 

Introduction 2-13 
_________________________________________________________________________________________ 

Energy Conversion from a Flow-Reversal Reactor 

There are several methods of converting the heat of oxidation from a flow-reversal reactor to electric 

power, which is the most marketable form of energy in most locations. The two methods being studied 

by MEGTEC and CANMET are: 

• Use water as a working fluid. Pressurize the water and force it through an air-to-water heat 

exchanger in a section of the reactor that will provide a non-destructive temperature 

environment (below 800o

C [1472oF]). Flash the hot pressurized water to steam and use the 

steam to drive a steam turbine-generator. If a market for steam or hot water is available, send 

exhausted steam to that market. If none is available, condense the steam and return the water 

to the pump to repeat the process. 

• Use air as a working fluid. Pressurize ventilation air or ambient air and send it through an air-toair heat exchanger that is embedded in a section of the reactor that stays below 800o

C (1472oF). 

Direct the compressed hot air through a gas turbine-generator. If gob gas is available, use it to 

raise the temperature of the working fluid to more nearly match the design temperature of the 

turbine inlet. Use the turbine exhaust for cogeneration, if thermal markets are available. 

Since affordable heat exchanger temperature limits are below those used in modern prime movers, 

efficiencies for both of the energy conversion strategies listed above will be fairly modest. The use of 

a gas turbine, the second method listed, is the energy conversion technology assumed for the cost 

estimates in this report. At a VAM concentration of 0.5 percent one vendor expects an overall plant 

efficiency in the neighborhood of 17 percent after accounting for power allocated to drive the fans that 

force ventilation air through the reactor. 

Other Technologies 

USEPA has also identified other technologies that may be able to play a role in and enhance 

opportunities for VAM oxidation projects. These are briefly described below. 

Concentrators 

Volatile organic compound (VOC) concentrators offer another possible economical option for 

application to VAM. During the past 10 years the use of such units to raise the concentration of VOCs 

in industrial-process air exhaust streams that are sent to VOC oxidizers has increased. Smaller 

oxidizer units are now used to treat these exhaust streams, which in turn has reduced capital and 

operating costs for the oxidizer systems. Ventilation air typically contains about 0.5 percent methane 

concentration by volume. Conceivably, a concentrator might be capable of increasing the methane 

concentration in ventilation airflows to about 20 percent. The highly reduced gas volume with a higher 

concentration of methane might serve beneficially as a fuel in a gas turbine, reciprocating engine, etc. 

Concentrators also may prove effective in raising the methane concentration of very dilute VAM flows 

to levels that will support oxidation in a TFRR or CFRR. 

Introduction 2-14 
_________________________________________________________________________________________ 

Lean Fuel Gas Turbines 

A number of engineering teams are striving to modify selected gas turbine models to operate directly 

on VAM or on VAM that has been enhanced with more concentrated fuels, including concentrated 

VAM (see “Concentrator” section above) or gob gas. These efforts include: 

• Carbureted gas turbine. A carbureted gas turbine (CGT) is a gas turbine in which the fuel enters 

as a homogeneous mixture via the air inlet to an aspirated turbine. It requires a fuel/air mixture of 

1.6 percent by volume, so most VAM sources would require enrichment. Combustion takes place 

in an external combustor where the reaction is at a lower temperature (1200°C [2192°F]) than for 

a normal turbine thus eliminating any NOx emissions. Energy Developments Limited (EDL) of 

Australia is testing the CGT on ventilation air at the Appin coal mine in New South Wales, 

Australia. 

• Lean-fueled turbine with catalytic combustor. CSIRO Exploration & Mining of Australia, a 

government research organization, is developing a catalytic combustion gas turbine (CCGT) that 

can use methane in coal mine ventilation air. The CCGT technology being developed oxidizes 

VAM in conjunction with a catalyst. The turbine compresses a very lean fuel/air mixture and 

combusts it in a catalytic combustor. CSIRO hopes to operate the system on a 1.0 percent 

methane mixture to minimize supplemental fuel requirements. 

• Lean-fueled catalytic microturbine. Two U.S. companies, FlexEnergy and Capstone Turbine 

Corporation, are jointly developing a line of microturbines, starting at 30 kW that will operate on a 

methane-in-air mixture of 1.3 percent. 

• Hybrid coal and VAM-fueled gas turbine. CSIRO is also developing an innovative system to 

oxidize and generate electricity with VAM in combination with waste coal. CSIRO is constructing a 

1.2-MW pilot plant that cofires waste coal and VAM in a rotary kiln, captures the heat in a hightemperature air-to-air heat exchanger, and uses the clean, hot air to power a gas turbine. 

Depending on site needs and economic conditions, VAM can provide from about 15 to over 80 

percent (assuming a VAM mixture of 1.0 percent) of the system’s fuel needs, while waste coal 

provides the remainder. 

VAM Used as an Ancillary Fuel 

VAM can also be used as an ancillary or supplemental fuel. Such technologies rely on a primary fuel 

other than VAM and are able to accept VAM as all or part of their combustion air to replace a small 

fraction of the primary fuel. The largest example of ancillary VAM use occurred at the Appin Colliery in 

Australia, where 54 one-MW Caterpillar engines used mine ventilation air containing VAM as 

combustion air. Similarly, the Australian utility, Powercoal, is installing a system to use VAM as 

combustion air for a large coal-fired steam power plant. In addition, the U.S. Department of Energy 

funded a research project to use VAM in concentrations up to 0.5 percent as combustion air in a 

turbine manufactured by Solar. Even the CSIRO hybrid coal and VAM project described in the 

preceding paragraph falls in the category of ancillary VAM use when waste coal combustion is 

maximized and VAM use is limited to prescribed levels of combustion air. 

Introduction 2-15 
_________________________________________________________________________________________ 

Project Economics for Ventilation Air Methane Use Technologies 

Many of the technologies for VAM use are still in the developmental stage, and cost information is still 

limited. The costs for simply using the VAM as combustion air either in reciprocating engines or 

turbines is negligible, the only costs being construction and operation of equipment to move the air to 

the generator sets. Additional maintenance of the engines or turbines may be necessary if excess 

moisture and dust are present in the mine ventilation air. Developers of the lean-burn turbines are 

reporting that they can produce 30-100 kW units for about $1,000-2,000 per kW while commercial 

production of larger scale units (200 kW – 2 MW) would drive down the costs significantly to $600­

$1,000 per kW. 

The majority of economic data available is for the flow reversal reactors. Field-scale and bench-scale 

tests of the MEGTEC TFRR and the CANMET CFRR, respectively, have provided more reliable cost 

data than other technologies. In 2003, EPA released the report, “Assessment of the Worldwide 

Potential for Oxidizing Coal Mine Ventilation Air Methane,” the most comprehensive assessment to 

date of the marginal abatement costs of VAM use technologies. With methane abatement costs at 

$3.00 per tonne of CO2e, VAM-derived power projects in the U.S. could theoretically create 457 MW 

of net useable capacity. If the equipment value for each project were rounded to $10 million, the total 

equipment market estimate for the U.S. would be over $1.2 billion. Finally, the annual revenues that 

could accrue from such power sales in the country could amount to over $120 million (USEPA, 2003). 

 Local Use 

In addition to pipeline injection, power generation, and ventilation air methane use, coal mine 

methane may be used as a fuel in on-site preparation plants or vehicle refueling stations, or it can be 

transported to a nearby coal-fired boiler or other industrial or institutional facilities for direct use. 

Nearly all large underground coal mines have preparation plants located nearby. Mines have 

traditionally used their own coal to fuel these plants, but there is the potential to use recovered 

methane instead. Currently, CONSOL uses recovered methane to fuel the thermal dryer in one of its 

preparation plants. In Poland, several coal mines have used recovered methane to fuel their coal 

drying plants. 

Another option for on-site methane use may be as a fuel for mine vehicles. Natural gas is much 

cheaper and cleaner than diesel fuel or gasoline, and internal combustion engines burn it more 

efficiently. 

In addition to on-site methane use, selling recovered methane to a nearby industrial or institutional 

facility may be a promising option for some mines. An ideal gas customer would be located near the 

coal mine (within five miles) and would have a continuous demand for gaseous fuel. Coal mine 

methane could be used to fuel a cogeneration system, to fire boilers or chillers, or to provide space 

heating. In some cases, local communities may find that the availability of an inexpensive fuel source 

from their local mine can help them attract industry and generate additional jobs. 

Additionally, there are numerous international examples of mine gas being used for industrial 

purposes. For example, in Ukraine and Russia, recovered methane is used in coal-fired boilers 

located at the mine-site. In the Czech Republic, coal mine methane is used in nearby metallurgical 

plants. In Poland, recovered methane is used as a feed-stock fuel in a chemical plant. In China, 

methane has been used in carbon black plants. 

Introduction 2-16 
_________________________________________________________________________________________ 

Finally, co-firing methane with coal in a boiler is another potential utilization option, particularly for 

mines that are located in close proximity to a power plant. A few of the mines profiled in this report 

are located within a few miles of a coal-fired plant (for example, Robinson Run is located about three 

miles from Allegheny Power's Harrison Plant).

 Flaring 

Environmentally, flaring methane is nearly as beneficial as utilizing the methane as fuel, since flaring 

changes the majority of the methane to carbon dioxide. Emitting carbon dioxide is much less harmful 

in terms of the impact on global warming than is the direct emission of methane. For purposes of 

greenhouse gas reductions, the value of recovering one ton of methane and using it to generate 

energy (in lieu of burning natural gas from a traditional source) is equivalent to a 21 ton reduction in 

carbon dioxide emissions. If mine emissions are flared without using the combustion to displace 

energy from other sources, flaring yields greenhouse gas reductions equal to 87.5% of those 

achievable through recovery and use (Lewin, 1997). 

Although there are flares at a closed mine in the U.S., to date, flaring has not been implemented at 

active mines in the U.S. The principal concern expressed by the coal industry is that it is not safe to 

pipe the gas to a point where it would be flared because of the potential for the flame to propagate 

back down to the mine and to cause an underground explosion (Lewin, 1995). If agreement on the 

safe practice of flaring methane recovered from coal mines is reached, flaring could become an 

additional option for mitigating methane emissions, however, the flaring option still requires 

acceptance of miners, MSHA, union parties, and mine owners. Through a series of reports, EPA has 

outlined the benefits of flaring and addressed these concerns by offering a conceptual flare design 

(USEPA, 1999). 

Green Pricing Projects 

With the advent of competition in the electric utility industry, utilities are recognizing the need to 

provide new services to customers. One such service is "green pricing". Under green pricing, 

customers can choose the type of electricity they purchase. Customers can choose conventional 

power, which they can purchase at a standard rate, or they can purchase green power at a slightly 

higher rate. As part of the green pricing program, for every customer who commits to pay the higher 

rate, the utility pledges to buy enough "environmentally friendly" energy to completely offset the 

customer's share of conventionally generated electricity. In 2000, the State of Pennsylvania Public 

Utility Commissions included CMM as a renewable energy source as part of their green pricing 

program. 

Another result of electric utility industry deregulation is the emergence of laws and regulations to 

encourage investment in renewables. Twenty-one States and the District of Columbia have enacted 

“renewable portfolio standards” (RPS), which require electric utilities to generate a portion of their 

electricity through qualifying renewable technologies by a specific date in the future. The 

requirements under the various standards and the definition of renewable energy vary by state. 

Currently, Pennsylvania is the only state with an RPS to include CMM as a qualifying renewable 

source. 

Barriers to the Recovery and Use of Coal Mine Methane 

While a number of U.S. coal mines are already selling recovered methane to pipelines, numerous 

seemingly profitable projects have not been undertaken at other mines. Currently, a number of 

problems and disincentives exist that distort the economics of coal mine methane projects, with the 

Introduction 2-17 
_________________________________________________________________________________________ 

result that many potentially profitable investments are not being developed. These obstacles include 

unresolved legal issues concerning ownership of the coalbed methane resource, power prices and 

pipeline capacity constraints, among other technical challenges. 

Ownership of Coalbed Methane 

Unresolved legal issues concerning the ownership of coalbed methane resources have constituted 

one of the most significant barriers to coalbed methane recovery. Ambiguity in certain state legal 

systems provides a disincentive for investment in coalbed methane projects because of the 

uncertainties as to which parties may demand compensation for development of the resource. 

Although ownership legislation has improved the investment climate, coalbed methane industry 

forums have still identified ownership issues as serious obstacles to methane recovery. Courts are 

being called upon on a case-by-case basis to determine the ownership of coalbed methane in 

situations where mining and mineral rights have been severed from land ownership. The issue is 

simply whether the owner of the rights to the coal and/or gas also owns the coalbed methane rights. 

Resolution can happen only after all the facts are considered in each case. 

 Power Prices 

Another factor contributing to the slow development of CMM-fueled power generation is the low prices 

of electricity in many U.S. coal producing regions. When comparing the economics of power 

generation to other alternatives, low electricity prices have resulted in power projects not being as 

attractive, regardless of the designated end-use for the power, whether it be on-site at the mine to 

offset electricity purchases, or to sell the power to the local utility. 

Production Characteristics of Coalbed Methane Wells 

 Gas Production 

Coalbed methane degasification wells have production characteristics that differ from conventional 

gas wells in a variety of respects. One important difference is the amount of control the developer has 

in terms of the gas flow. With conventional gas wells, the gas flow may be controlled, or completely 

halted, at the discretion of the operator. This provides the operator with flexibility as to when the gas 

is sold. Vertical pre-mine degasification wells can be controlled as their production is not directly 

related to mining activities. In-seam and gob wells, however, are not subject to the same control by 

virtue of their purpose. These wells are used primarily to drain a mine of methane for safety reasons. 

As such, the feasibility of turning off and on an in-seam or gob well depends on safety first and gas 

production second. 

The production characteristics of coalbed methane wells present difficulties in the context of the 

natural gas and pipeline industries. Much of the consumer demand for natural gas is seasonal in 

nature. In addition, in situations of limited pipeline capacity, local pipelines may not be able to accept 

the gas supplied from coalbed methane projects on a continuous, uninterrupted basis. In particular, 

some areas of the Appalachian region have limited pipeline capacity. Storage of coalbed methane in 

depleted natural gas reservoirs or abandoned mines is an excellent means of overcoming problems 

related to fluctuations in demand or pipeline capacity. EPA has investigated the potential for storing 

methane recovered from active coal mines in nearby abandoned coal mines, concluding that if the 

abandoned mine were to meet certain criteria a project could be sustainable (USEPA, 1998). 

Introduction 2-18 
_________________________________________________________________________________________ 

 Water Production 

Another area in which technical challenges may arise is water disposal. In many instances, vertical 

coalbed methane wells will produce water from the coal seam and surrounding strata. Water is also 

produced during conventional mining operations, but some states have adopted separate regulations 

for water produced in association with coalbed methane operations and for water produced as a result 

of mining operations. For mines located near fresh water bodies or other vulnerable areas, surface 

water disposal may not be environmentally acceptable. Several alternative disposal and treatment 

methods are in use or under development, including deep well injection and other surface treatment 

approaches. These treatments may have higher costs associated with them, and in some cases 

additional research is needed to address technical issues. 

Introduction 2-19
3. Overview of Existing Coal Mine Methane Projects 
_________________________________________________________________________________________ 

3. Overview of Existing Coal Mine Methane Projects 

Coal mine methane recovery and use is a proven technology. This chapter discusses methane 

recovery and use projects at 12 mines profiled in Chapter 6. In 2003, total methane sales from coal 

mine methane projects at profiled mines was nearly 40 billion cubic feet, which is the equivalent of 

nearly 18 million tons of carbon dioxide.9 At the current wellhead gas price of roughly $6 per 

thousand cubic feet10, and assuming that all recovered gas was sold to a pipeline, these projects 

collectively will have grossed approximately $240 million dollars in annual revenues. Additionally, by 

working to maximize the amount of gas recovered from their drainage systems, these projects have 

greatly reduced mine ventilation costs and have improved safety conditions for miners. 

The projects in Alabama, Colorado, New Mexico, Pennsylvania, Virginia, and West Virginia employ a 

variety of degasification techniques, including vertical wells (pre-mining degasification), gob wells, and 

in-mine boreholes. Regardless of the degasification system employed, all mines have been able to 

recover large quantities of gas suitable for use in various applications. Following is a brief overview of 

the existing projects, arranged by location. Table 3-1, at the end of this chapter, summarizes the 

major characteristics of the existing projects. 

Alabama 

Five mines in Alabama recover and sell methane: Blue Creek No. 4, Blue Creek No. 5, Blue Creek 

No. 7, Oak Grove and Shoal Creek. The Blue Creek No. 4, No. 5 and No. 7 mines are owned by Jim 

Walter Resources (JWR), while the Oak Grove Mine is owned by U.S. Steel Mining, and the Shoal 

Creek Mine is owned by Drummond Coal. 

Jim Walter Resources (JWR) 

Blue Creek No. 4, No. 5, and No. 7 Mines 

Located in Jefferson County, Alabama, the JWR mines are among the deepest and gassiest mines in 

the country. Opened in the early to mid-1970’s, the mines cover an 80,000 acre area and have 

vertical shafts ranging from 1,300 to 2,100 feet in depth. The in-situ gas content of coal is about 500 

to 600 cubic feet per ton and the total amount of methane liberated from these mines is estimated to 

be between 1,800 – 3,900 cubic feet per ton of coal produced. 

JWR has been a leader in the development of coal mine methane recovery projects in the United 

States. The company's Blue Creek mines – the Nos. 4, 5, and 7 mines – are currently recovering and 

selling approximately 23 million cubic feet of gas per day. Methane is produced using three recovery 

methods: 1) vertical degasification (holes drilled from the surface into the virgin coalbed); 2) horizontal 

degasification (holes drilled in the coalbed from active workings inside the mine); and 3) a gob 

degasification program (holes drilled from the surface into the caved area behind the longwall faces). 

Since the late 1980s, JWR has been producing between 25 – 35 mmcf/d of methane. As of December 

2001, there were 256 wells producing approximately 27 mmcf/d. Since then, production has declined 

to 23 mmcf/d in 2003. The quantity of methane recovered in 2003 represents 46 percent of total 

methane liberated from the mines. Depending on the mine, recovery from vertical pre-mine wells in 

9

 Methane emissions may be converted to a measure equivalent to carbon dioxide, since methane is 21 times more potent 

than carbon dioxide over a 100 year time frame. 

10 EIA - Average price for July 2005. 

Overview 3-1 
_________________________________________________________________________________________ 

2003 made up approximately 5 - 25 percent of production, while gob wells and in-mine boreholes 

made up the remaining 75 - 95 percent of production. 

U.S. Steel Mining 

Oak Grove Mine 

U.S. Steel Mining's (USM's) Oak Grove Mine produces methane for pipeline sales. USM is a 

subsidiary of USX, Incorporated (formerly U.S. Steel Corporation). Oak Grove is located in the eastcentral portion of the Black Warrior Basin of Jefferson County, Alabama. The target seam for mining 

is the Blue Creek bed of the Mary Lee coal group. The coal is mined at a depth of approximately 

1,150 feet. 

The effectiveness of a large-scale pattern of stimulated vertical wells in reducing the gas content of a 

coalbed was first demonstrated at the Oak Grove Mine in 1977. This was the first large-scale coal 

seam degasification project in the United States using vertical wells, as well as one of the first coalbed 

methane production projects. After 10 years, the original wells had produced a total of 3.2 Bcf (billion 

cubic feet) of methane that will never need to be controlled in the underground mine environment. 

Most of the wells in the field, however, are well beyond the near-term mine plan. In 2003, predrainage wells that are scheduled to be mined-through during the next few years produced nearly 4 

mmcf/d. In addition to the vertical wells drilled in advance of mining, Oak Grove Mine also has utilized 

both horizontal and gob wells for methane drainage, primarily to increase the safety of the 

underground mine. Since 1997, as many as 15 gob and horizontal wells have been in production in a 

given year. In 2003, nine of these wells remained in production, producing 150 mcf/day. 

Because the sole goal of other companies drilling in the Oak Grove Degasification Field is commercial 

methane production, rather than reducing emissions from future mining operations, most of the wells 

drilled since 1985 have been spaced on a 160-acre (or greater) pattern. While these wells do drain 

methane from the area to be mined, the wider well spacing does not drain the coal as effectively as 

would a true vertical pre-mine drainage program. 

Drummond Coal 

Shoal Creek Mine 

Drummond Coal's Shoal Creek Mine began producing coal in 1994. The mine entry is located in the 

Oak Grove Field, but mining will progress into the White Oak Field. Currently, Shoal Creek is using 

vertical pre-mine, horizontal and gob wells to drain methane. The pre-mine wells in the White Oak 

Field are operated by Saga Petroleum, Amoco Production Co., McKenzie Methane Co., Kukui 

Operating Co., and El Paso Production Co. Nearly 37 wells produced about 1 mmcf of methane per 

day for pipeline sales in 2003. In 2003, there were six gob wells, which produced 415 mcf/d, in 

addition to 31 horizontal wells that produced 580 mcf/d. 

Colorado 

There is one methane recovery and use project underway in Colorado. The project is taking place at 

the West Elk mine, which is owned by Mountain Coal. 

Overview 3-2 
_________________________________________________________________________________________ 

 Mountain Coal (a subsidiary of Arch Coal Co,)

 West Elk 

West Elk began recovering methane in 2003 to heat mine ventilation air on site. 

New Mexico 

There is one methane recovery and use project underway in New Mexico. The project involves the 

San Juan South mine, which is owned by a subsidiary of BHP Billiton. 

San Juan Coal Co. (a subsidiary of BHP Billiton) 

San Juan South 

This longwall mine opened in 2002 and initiated methane recovery for pipeline sales in 2003. San 

Juan South represents a surface mine that decided to continue operations underground. 

Pennsylvania 

There is one methane recovery and use project underway in Pennsylvania. The project involves three 

mines owned by CONSOL. Because the main portals for these mines are in West Virginia, they are 

categorized as West Virginia mines in Chapter 6 (the individual mine profiles section of this 

document). However, significant sections of the mines extend into Pennsylvania, and the majority of 

the gas produced is from coal and strata in Pennsylvania, therefore this methane recovery and use 

project is classified as a Pennsylvania project. Of the three mines, two are abandoned; therefore this 

report will only focus on the active mine. 

Consolidation Coal Company (a subsidiary of CONSOL Energy) 

Blacksville No. 2 

CONSOL and CBE Inc. are undertaking a gas enrichment and sales project at the Blacksville No. 2 

Mine. In 1997, CBE began selling enriched gas directly to the pipeline. The project captured as 

much as 4 mmcf/day from the mine, and removed carbon dioxide, oxygen and nitrogen from the gas 

using catalytic, amine and cryogenic processes respectively. Columbia Energy Services purchases 

the resulting pipeline-quality gas. The enrichment plant is able to process 5-6 mmcf/d of gas whose 

methane content (prior to enrichment) is about 80-85%. The project can be expanded to process 10­

12 mmcf/d. Operational problems in 2000 and 2001 have kept the project from maintaining its 

maximum output. Since that time, CONSOL has assumed full responsibility for the project and 

expects to optimize the production. 

Virginia 

The commercial potential of coalbed methane recovery in Virginia has long been recognized, but 

complicated issues regarding gas ownership, as well as the lack of pipeline capacity in southwest 

Virginia, delayed commercial coalbed methane recovery in this area until the early 1990's. There are 

two methane recovery and use projects currently underway in Virginia. These projects are taking 

place at the Buchanan and VP No. 8 mines. The CONSOL Coal Group owns both mines. 

Overview 3-3 
_________________________________________________________________________________________ 

 CONSOL 

CONSOL recovers methane from two of the gassiest mines in the southwestern region of Virginia: 

Buchanan and VP No. 8. One of these mines, VP No. 8 was born out of the consolidation of the VP 

No. 5 and VP No. 6 mines in 1994. CONSOL has operated the adjacent Buchanan No. 1 Mine since 

1983. The company has developed extensive degasification programs on both their properties, and 

continues to invest in vertical pre-mine wells. Although more gas can be successfully drained if a 

vertical pre-mine well has been in place for a long period, CONSOL has been opting for an advance 

drainage time frame that adequately balances the risk of investing in a vertical pre-mine drainage 

system with that of the company’s mining plans. Thus, the company uses a three to five year 

advance degasification program to the extent that this can be feasibly coordinated with the company’s 

overall mining strategies. 

Currently, CONSOL produces gas for pipeline sales, on site use, and power generation. The total 

methane drained at the two CONSOL Virginia mine properties totaled nearly 76 mmcf/d in 2003. This 

number significantly exceeds ventilation emissions of 15 mmcf/d, which indicates that much of the 

produced gas comes from virgin coals that CONSOL may mine in the future, and/or that recovery 

efficiencies are higher than standard EPA assumptions. 

Of the 76 mmcf/d of methane that CONSOL currently recovers, approximately 74 mmcf/d can be 

attributed to emissions reduction at the mines, with an additional 2 mmcf/d being used on-site in a 

thermal dryer. Of the total recovered methane, gob wells and in-mine horizontal boreholes account 

for approximately 67 percent of methane production at the mines. Vertical pre-mine wells that have 

been mined through and impact emissions reductions at the mines account for the remaining 33 

percent. This production from the vertical wells represents only about one third of the total gas sales 

occurring in the coals being drained ahead of mining. 

Buchanan Mine 

A deep and gassy mine, Buchanan is actively mining at a depth of about 1,500 feet and has an in-situ 

gas content of about 3,318 cf/ton. Beginning in May 1995, Buchanan began using recovered 

methane, instead of coal, as fuel in its thermal dryer. As of May 1997, the thermal dryer consumed 

approximately 1.5 mmcf/d, or 547.5 mmcf/year (CONSOL, 1997). In addition, over 7 mmcf/d was 

recovered from gob and horizontal wells at the mine in 2001. After 2001, CONSOL began reporting 

methane recovered from the Buchanan and VP No. 8 projects together. 

VP No. 8 Mine 

Gas sales started in May 1992 at a rate of 3 mmcf/d. Over the next twelve months, production had 

grown to more than 30 mmcf/d (about 11 Bcf per year). In 2001, gas sales exceeded 60 mmcf/d via 

three methods, vertical pre-drainage wells, horizontal boreholes, and gob wells. Additionally, 

CONSOL recovers methane from abandoned areas at the VP and Buchanan mines. Once a methane 

drainage program from an abandoned area is completed, that area is sealed and no further methane 

extraction takes place (CONSOL, 1997). After 2001, CONSOL began reporting methane recovered 

from the Buchanan and VP No. 8 projects together. 

Overview 3-4 
_________________________________________________________________________________________ 

West Virginia 

There are two methane recovery and use projects currently underway in West Virginia11. These 

projects are taking place at the Federal No. 2 and Pinnacle No. 50 mines. The Federal No. 2 Mine is 

owned by Peabody Coal and the Pinnacle No. 50 Mine is owned by U.S. Steel Mining.

 Peabody Energy 

Federal No. 2 Mine 

Federal No. 2 currently drains methane using vertical gob wells. The mine markets gas recovered 

from some higher quality gob wells to a natural gas pipeline. This gas project is a joint venture with 

Dominion Gas Company. Dominion recovered approximately 0.8 mmcf/d in 2003. The project at 

Federal No. 2 continues to expand as more sealed longwall panels become available to drain. 

Eastern Associated Coal and Northwest Fuel Development are involved in a Department of Energy 

funded effort to evaluate the use of an integrated power generation system comprised of IC engines 

and gas turbines (USDOE, 2000). This combination of equipment will allow low quality and variable 

quality gob gas to be used as a fuel. The electricity produced will power CNG’s existing coalbed 

methane pipeline injection operations at the mine site. A generation capacity of 1.2 MW is planned. 

The Federal No. 2 power project will build upon an aggressive coalbed methane degasification and 

commercialization project that likely will involve in-seam horizontal boreholes, gob wells, and vertical 

pre-mine wells. 

U.S. Steel Mining Co. (a subsidiary of USX Corp.) 

Pinnacle No. 50 Mine 

USM's Pinnacle No. 50 Mine, located in West Virginia, produces methane for pipeline sale. Currently, 

the mine sells recovered coal mine gas to a local pipeline company. Until recently, methane recovery 

in the area had been hindered by high road and location costs. As a result, CDX Gas, LLC now uses 

a unique horizontal borehole drainage system called the Z-Pinnate Horizontal Drilling and Completion 

technology. Under this dual system approach, a vertical well was drilled first and the target coal seam 

was cavitated. Then a horizontal hole was kicked off from a second well, which intersected the cavity 

of the first well. The cavity acts as a down-hole water separator, retaining water while gas flows to the 

production well. Finally, a lateral well was drilled through the cavity along the coal seam for up to 

4800 feet. When the drill was pulled back along this main branch, paired branches were drilled at 45 

degrees to the main, yielding a “barbed” appearance from a plan view. This process continued back 

toward the production well, creating a series of barbed branches that CDX calls a “pinnate” drilling 

pattern. Four of these patterns can be drilled from a central well. 

In 2003 the Pinnacle Mine recovered and sold approximately 1.5 mmcf/d of gas from its pre-mine 

drainage wells. In addition, the mine uses gob vent boreholes to drain methane, but currently does not 

recover this gas. 

11 Another project involving three West Virginia mines is discussed under the "Pennsylvania" section earlier in this chapter, 

for reasons explained in therein. 

Overview 3-5 
_________________________________________________________________________________________ 

Summary 

Table 3-1 summarizes the methane recovery and use projects discussed in this chapter. 

Table 3-1: Summary of Existing Methane Recovery and Use Projects 

Mine Name Mine 

Location 

(State) 

Approximate 

Amount of Gas 

Used in 2003 

Methane Use 

Option 

Notes 

Blue Creek No. 4 

Blue Creek No. 5 

Blue Creek No. 7 

Alabama 23 mmcf/day Pipeline Sales The three mines collectively 

produced 23 mmcf/day 

of gas in 2003. 

Oak Grove Alabama 4 mmcf/day Pipeline Sales Most of the production in the 

Oak Grove Field is beyond the 

limits of the mine plan. 

Shoal Creek Alabama 1 mmcf/day Pipeline Sales Most of the production from the 

White Oak Field is outside the 

limits of the mine plan. 

West Elk Colorado 110 mcf/day On-Site Use 

Heaters 

Began recovering methane in 

2003. 

San Juan South New Mexico 110 mcf/day Pipeline Sales Mine opened in 2002 and 

methane recovery began in 

2003. 

Buchanan 

VP #8 

Virginia 76 mmcf/day Pipeline Sales 

On-Site Use 

Power 

Generation 

These two mines collectively 

produced 76 mmcf/day of gas 

in 2003, of which 74 mmcf/d 

contributes to emissions 

reduction at the mines. A small 

portion (2 mmcf/d) of the total 

gas production is used 

on-site in a thermal dryer. 

Blacksville No. 2 Pennsylvania 3 mmcf/day Pipeline Sales Gas is produced from two 

abandoned mines that are part 

of the project, but over 3 

mmcf/d is from the active mine 

alone. 

Federal No. 2 West Virginia 820 mcf/day Pipeline Sales Project continues to expand as 

more longwall panels become 

available to drain. 

Pinnacle No. 50 West Virginia 2 mmcf/day Pipeline Sales A unique, horizontal pre-mine 

drainage program is utilized. 

Overview 3-6 
4. A Key to Evaluating Mine Profiles 
_________________________________________________________________________________________ 

4. A Key to Evaluating Mine Profiles 

This report contains profiles of coal mines that are potential candidates for the development of 

methane recovery and use projects. Also included are mines that already have installed methane 

recovery and use systems. The mines that are profiled were selected primarily on the basis of their 

annual methane emissions from ventilation systems as recorded in a Mine Safety and Health 

Administration database (MSHA, 2004). While this report is thought to contain a comprehensive 

listing of the best candidates for cost-effective methane recovery projects, it is possible that some 

promising candidate mines have not yet been identified. 

The mine profiles presented in this report are designed to assist interested parties in identifying mines 

that can sustain a profitable methane recovery and use project. Each mine profile is comprised of the 

following sections: 

• geographic data 

• corporate information 

• mine address 

• general information 

• production, ventilation and drainage data 

• energy and environmental value of emission reductions 

• power generation potential 

• pipeline sales potential 

• other utilization possibilities 

The mine profiles are ordered alphabetically by state, then by mine name. Following this chapter are 

summary tables that list key data elements shown in the mine profiles. Summary Table 1 lists all 

profiled mines in alphabetical order. The individual mine profiles follow the summary tables. 

Operating Status 

Each mine's operating status as of December 2003 is listed at the top right-hand corner of each 

profile. The operating status may be listed as described below: 

Active: These mines are currently producing coal. 

Idle: A mine that is open but not currently producing coal. 

The current operating status was determined by reviewing coal industry publications that track the 

production status of coal mines, and through discussions with MSHA district offices and sources in 

the coal industry. No closed or abandoned mines are included in this report. 

Geographic Data 

The first section of each profile gives the geographic location of the mine, including the state, county, 

coal basin where the mine is located, and the coalbed(s) from which it produces coal. The sources 

for this information were MSHA (2004) and the Keystone Coal Industry Manual (Keystone, 2004). 

State: Mines included in this report are located in the following states -- Alabama, Colorado, Illinois, 

Indiana, Kentucky, New Mexico, Ohio, Oklahoma, Pennsylvania, Utah, Virginia, or West Virginia. 

Summary Table 2 shows the mines listed by state. 

Key 4-1 
_________________________________________________________________________________________ 

County: A relatively small number of counties contain a majority of the gassy mines in the country. 

Summary Table 2 shows the mines listed by state and by county. 

Coal Basin: Mines are located in one of five major coal producing regions: the Black Warrior Basin, 

the Central Appalachian Basin, the Northern Appalachian Basin, the Illinois Basin, or one of the 

“Western basins” (Central Rockies, San Juan, or Uinta Basin), which are located in the states of 

Colorado, Utah and New Mexico. Major geological characteristics of coal seams, including methane 

content, sulfur content, depth, and permeability tend to vary by basin. Summary Table 3 lists the 

mines by basin and 2003 estimated specific emissions per ton of coal mined for each listed mine. 

Coalbed: Substantial and detailed information has been published on the geological and mining 

characteristics of major coalbeds occurring in the United States. Summary Table 4 lists mines 

according to the seam from which they produce their coal. 

Corporate Information 

Current Owner: Current owner refers to the mining company that owns the mine. Summary Table 5 

lists mines by mining company. The sources for this information were the MSHA database (MSHA, 

2004) and the Keystone Coal Industry Manual (Keystone, 2004). 

Parent Company: Many coal companies are owned by a parent company. In addition to showing the 

coal companies, Summary Table 5 also shows the parent corporation of the mining company. This 

information was taken from Keystone (2004). 

Previous Owner: The names of previous mine owners are useful as some of the coal mines profiled 

here have had numerous owners. This information, along with the previous or alternate name of the 

mine, is based on previous editions of the Keystone Coal Industry Manual. 

Previous or Alternate Name: Mines frequently undergo name changes, particularly when they are 

purchased by a new company. This section lists previous or alternate mine names. 

Mine Address 

This section includes the phone number and mailing address of the mine and a contact name. The 

principal source of this information was the Keystone Coal Industry Manual. The phone numbers and 

mailing addresses are believed to be current. The contact names, however, may be somewhat out of 

date because the most recent editions of the Keystone Coal Industry Manual have not included this 

information for all of the mines. If contact information was not available in the Keystone Coal Industry 

Manual, contact information from the Energy Information Administration’s (EIA) Coal Production Data 

Files for the year 2003 was used (EIA, 2003). 

General Information 

Number of Employees: This field shows the number of people employed by the mine, as reported in 

the Keystone Coal Industry Manual. If employment information was not listed in the Keystone Coal 

Industry Manual, the MSHA Data Retrieval System was consulted and the number of employees 

corresponding to year 2003 was used. 

Year of Initial Production: Year of initial production indicates the age of the mine, as reported in the 

Keystone Coal Industry Manual. 

Key 4-2 
_________________________________________________________________________________________ 

Life Expectancy Life expectancy can be an important factor in determining whether a mine is a good 

candidate for a methane recovery and use project. Information on life expectancy was collected from 

various Keystone Coal Industry Manuals. However, given the difficulty in predicting mine life this 

statistic is perhaps only marginally useful, and care should be exercised in basing decisions on this 

factor. 

Prep Plant Located On Site: The profile indicates whether a preparation plant is located at the mine, 

based on the Keystone Coal Industry Manual’s and Coal Age magazine's annual prep plant surveys. 

At the preparation plant, coal is crushed, cleaned and dried. Most large mines have a prep plant 

located within close proximity. In some cases, a prep plant will process coal not only from the on-site 

mine, but also from other nearby mines. Information regarding whether the mine has a prep plant, 

and the amount of coal processed, is of importance in determining the mine's total electricity and fuel 

demands. 

Mining Method: Mines are classified as longwall or continuous (room-and-pillar), based on Coal Age 

magazine's annual longwall survey and on information in coal industry publications. The mining 

method used is important for several reasons. First, longwall mines tend to emit more methane than 

do room-and-pillar mines, as the longwall technique tends to cause a more extensive collapse of, and 

relaxation of the methane-rich strata surrounding the coal seam. Furthermore, longwall mining has 

higher up-front capital costs. Thus, a company is not likely to invest in a longwall at a mine that is not 

expected to have a fairly long life. Finally, while continuous mining is the more common method, the 

number of longwall mines is growing. In fact, the longwall technique seems to be the preferred mining 

method at the largest and gassiest mines. All mines not listed on the longwall survey were assumed 

to be continuous. Summary Table 6 lists mines by mining method. 

Primary Coal Use: Coal may be used for steam and/or metallurgical purposes. Steam coal is used 

by utilities to produce electricity, while metallurgical coal is used to produce coke. The primary coal 

use is based on information in the Keystone Coal Industry Manual. Summary Table 7 lists mines by 

primary coal use. 

Btus/lb: Btus (British Thermal Units) per pound of coal produced indicates the heating value of the 

coal. This statistic, which was taken from the Keystone Coal Industry Manual, is used in comparing 

the energy value of the coal to the energy value of the methane recovered (see section on 

Environmental and Energy benefits below). Heating values were not available for all mines. Where 

coal analysis for individual mines was not available, mean heating values for the basin/seam were 

used. 

Production, Ventilation and Drainage Data 

This section presents the quantity of methane emitted from, and the amount of coal produced by, the 

profiled mines for each of the years 1999 to 2003. 

Coal Production:

12 Most of the mines profiled in this report are large, with production exceeding one 

million tons per year. Annual coal production is an important factor in determining a mine's potential 

for profitable methane recovery. Generally, larger mines will be better candidates because of the 

potential for high methane production and because they are more likely to be able to finance the large 

capital investments required for a methane recovery and utilization project. Coal production was 

based primarily on annual Energy Information Administration (EIA) reports, but was supplemented 

12 In the July 2004 edition of this report the coal production values listed in the Profiled Mines Section (Section 6) for year 

2001 were actually production values for year 2000. However, the coal production values in Table 8 were correct. This error 

has been corrected in the current report. 

Key 4-3 
_________________________________________________________________________________________ 

with data from coal producing states. Summary Table 8 lists the coal mines by the amount of coal 

they produced in 2003. 

Estimated Total Methane Liberated: Methane liberation is the total volume of methane that is 

removed from the mine by ventilation and drainage. Liberation differs from emissions in that the term 

emissions, as used in this report, refers to methane that is not used and is therefore emitted to the 

atmosphere. Estimated total methane liberated is the sum of "emissions from ventilation systems" 

and "estimated methane drained." For mines that do not use or sell any of their methane, estimated 

total methane liberated equals estimated methane emissions to the atmosphere. The volume of 

methane liberated is shown for the years 1999-2003. Summary Table 10 shows mines listed by their 

estimated total daily methane liberation for 2003. 

Emissions from Ventilation Systems: Methane released to the atmosphere from ventilation systems is 

emitted in very low concentrations (typically less than one percent in air). MSHA field personnel test 

methane emissions rates at each coal mine on a quarterly basis. Testing is performed underground 

at the same location each time. However, MSHA does not necessarily conduct the tests at precise 

three-month intervals, nor are they always taken at the same time of day. The ventilation emissions 

data for a given year are therefore averages of the four quarterly tests, and are accurate to the extent 

that the data collected at those four times are representative of actual emissions. Summary Table 11 

lists the mines by their 2003 ventilation emissions, based on MSHA data. 

Estimated Methane Drained: Mines that employ degasification systems emit large quantities of 

methane in high concentrations. Summary Table 12 lists mines according to the estimated methane 

drained. In contrast to ventilation emissions, no agency requires mines to report the amount of 

methane they drain, and actual methane drainage data are therefore unavailable. Thus, EPA has 

estimated the volume of methane drained based on estimated drainage efficiency, as defined below. 

Based on information obtained from MSHA district offices, EPA has developed a list of 17 U.S. mines 

that have drainage systems in place. A list of the mines that have drainage systems is shown in 

Summary Table 9. For the purpose of estimating emissions from drainage systems, if a mine is listed 

as having a drainage system in place, it was assumed that the system was in place from 1993 

onward. 

Specific Emissions:

13 "Specific emissions" refer to the total amount of methane liberated per ton of 

coal that is mined. Specific emissions are an important indicator of whether a mine is a good 

candidate for a methane recovery project. In general, mines with higher specific emissions tend to 

have stronger potential for methane recovery. Summary Table 13 shows a list of mines ordered 

according to specific emissions. Note that the coal production and methane liberation values shown 

in this report have been rounded, whereas the data actually used to calculate the specific emissions 

values have not been rounded. Therefore, the specific emissions data shown in this report may differ 

from results that the reader would obtain by dividing the methane liberation values by the coal 

production values. This difference is strictly due to rounding, and does not reflect any error in the 

calculation of methane recovered. 

Estimated Current Drainage Efficiency: In order to estimate the amount of methane emitted at mines 

that are believed to have drainage systems, it was assumed that these emissions would represent 

from 20-60 percent of total methane liberated from the mine. Thus, for mines that have drainage 

systems, ventilation emissions were assumed to equal 40-80 percent of total liberation, with 

emissions from drainage systems accounting for the remaining 20-60 percent. For mines that do not 

13 In the July 2004 edition of this report the specific emissions listed in the Profiled Mines Section (Section 6) for years 1997­

2001 were incorrect. However, the specific emissions reported in Table 13 were correct. This error has been corrected in 

the current report. 

Key 4-4 
_________________________________________________________________________________________ 

already have drainage systems in place, ventilation emissions are assumed to equal 100 percent of 

total methane liberation. 

The assumption that methane drainage accounts for 40 percent of total methane liberation is probably 

conservative for some mines, but optimistic for others. Therefore, drainage estimates of 20, 40, and 

60% were calculated for each mine profile. Accordingly, the drainage efficiency of 40 percent is 

merely an arbitrarily chosen value, and may not reflect actual conditions at any one mine. 

Drainage System Used: Seventeen of the mines profiled in this report use some type of drainage (or 

degasification) system to capture coal mine methane. Drainage systems used include vertical premine (drilled in advance of mining), vertical gob wells, long-hole horizontal pre-mine, and horizontal 

pre-mine. Summary Table 9 lists mines by drainage system used. 

Energy and Environmental Value of Emissions Reduction 

This section presents information on the environmental and energy benefits that may be achieved by 

developing a methane recovery project at a mine. 

CO2 Equivalent of CH4 Emissions Reductions (mmt/yr). This statistic shows the carbon dioxide (CO2) 

equivalent of the annual methane emissions reductions that may potentially be achieved at each 

mine. The CO2 equivalent of the potential methane emissions reductions is shown in order to 

facilitate the comparison of the environmental benefits of coal mine methane recovery projects to 

other greenhouse gas mitigation projects. The potential quantity of methane that may be recovered 

from a mine – which represents the emissions reductions that may be achieved – is converted to a 

CO2 equivalent as follows: 

CO2 equivalent 

(million tons/yr) = [CH4 liberated (mmcf/yr) x recovery efficiency (20%, 40% and 60%) x 19.2 g 

CH4/cf x 21 g CO2/ 1 g CH4 x 1 lb / 453.59 g x 1 ton / 2000 lbs] 

where: 21 is the global warming potential (GWP) of emitting 1 gram of methane 

compared to emitting 1 gram of carbon dioxide over a 100 year time period14 

19.2 g/cf is the density of methane at 60 degrees F and atmospheric pressure 

The CO2 equivalent is shown assuming a 20%, 40% and 60% recovery efficiencies (i.e., the portion of 

total methane emissions that are recovered and utilized). Summary Table 14 shows the CO2 

equivalent of the potential methane emissions reductions that may be achieved at each mine. 

CO2 Equivalent of CH4 Emissions Reductions/CO2 Emissions from Coal Combustion: This ratio 

shows the reduction in CO2 emissions from the combustion of methane instead of coal produced at 

the mine. The ratio is calculated by converting the methane recovered into a CO2 equivalent (as 

described above) and dividing by the annual CO2 emitted from the combustion of coal produced at the 

mine. In order to calculate the CO2 emissions from coal combustion, the annual coal production is 

multiplied by the Btu value of the coal (see general information section for Btu value). Next, this value 

14 For further information on the global warming potential of various greenhouse gases see Intergovernmental Panel on 

Climate Change (1997). 

Key 4-5 
_________________________________________________________________________________________ 

is multiplied by an emissions factor of from 203 to 210 lbs CO2 per million Btu.15 Finally, the value is 

multiplied by 99 percent to account for the fraction oxidized. The formula is as follows: 

[CO2 equivalent of potential annual CH4 emissions reductions (lbs)] / [annual coal production 

(tons) x Btus/ton x lbs CO2 emitted / Btu x 99% (fraction oxidized)]. 

The ratio is calculated assuming a 20%, 40% and 60% recovery efficiencies. 

Btu Value of Recovered Methane/Btu Value of Coal Produced: In order to calculate this ratio, the 

potential annual quantity of methane recovered is multiplied by a value of 1000 Btus/cf. Annual coal 

production is multiplied by the Btus/ton value for the mine. The ratio of the energy value of the 

methane recovered to the energy value of the coal produced is then calculated. The formula is as 

follows: 

[Recovered methane (cf/yr) x 1000 Btus/cf] / [coal production (tons) x Btus/ton] 

As with the other statistics in this section, the ratio is calculated assuming a 20%, 40% and 60% 

recovery efficiencies. In comparison with the first ratio (CO2 equivalent of methane/ CO2 emissions 

from coal combustion), the energy value of the methane emissions is a much smaller fraction of the 

energy value of the coal production. 

Power Generation Potential 

This section presents data relevant to the examination of whether the mine is a good candidate for an 

on-site electricity generation project. 

Utility Electricity Supplier: The utility that supplies electricity to the mine is listed here, based on the 

service areas reported in the North American Electric Power Atlas, 2001 Edition (Electric Power, 

2002). Summary Table 15 lists the utilities that sell power to the profiled mines. 

Parent of Utility: The parent company of the local electric utility is also shown. This information is 

also based on the North American Electric Power Atlas, (Electric Power, 2002). 

Total Electricity Demand (MW): The annual electricity demand – including the electricity demands of 

the mine plus the additional electricity load of the preparation plant – is calculated as follows: 

Mine Electricity Demand Assumptions: 

• Total annual electricity needs are estimated by assuming that 24 kWh are needed for each ton of 

coal mined. 

• Ventilation systems are run 24 hours a day, 365 days a year (8760 hours a year) and account for 

about 25% of total electricity needs. 

• Other mine operations run 16 hours a day for 220 days a year (3520 hours a year) and account 

for 75% of total electricity needs. 

15 The emissions factor used is based on average state values reported in Energy Information Administration (1992). For 

the states examined in this report, values range from about 203 to 210 lbs CO2/mm Btu. 

Key 4-6 
_________________________________________________________________________________________ 

Demand (kWh/yr): 24 kWh/ton x tons mined/yr = kWhs/yr 

Demand (kW): [(75% x kWhs/yr)/(3520 hours)] + [(25% x kWhs/yr)/8760 hours)] 

 (mine operations) + (mine ventilation) 

Prep Plant Electricity Demand Assumptions: 

Prep plants require 6 kWh/ton of coal processed 

Prep plants are operated 16 hours a day, 220 days a year (3520 hours) 

Demand (kWh/yr): 6 kWh/ton x tons/year 

Demand (kW): [kWh/yr / 3520 hours] 

Electricity Demand (GWh/year): The annual continuous electricity demand – including the electricity 

demands of the mine plus the additional electricity load of the preparation plant – is calculated as 

follows: 

Mine Electricity Demand Assumptions: 

Total annual electricity needs are estimated by assuming that 24 kWh are needed for each ton 

of coal mined. 

Demand (kWh/yr): 24 kWh/ton x tons mined/yr = kWhs/yr 

Demand (GWh/year): [Demand (kWh/yr)]/ 106 

Prep Plant Electricity Demand Assumptions: 

Prep plants require 6 kWh/ton of coal processed 

Demand (kWh/yr): 6 kWh/ton x tons/year 

Demand (GWh/year): [Demand (kWh/yr)]/ 106 

Potential Electric Generating Capacity (kW):

16 The potential electric generating capacity (i.e., the 

amount of electricity that could be generated from recovered coal mine methane) is estimated by 

assuming that there are 1000 Btus/cf of methane recovered and that the heat rate of a generator 

would be about 11,000 Btu/kWh, which is a conservative assumption for a heat rate given that a gas 

turbine would likely be used for such a project. (Other technologies such as internal combustion 

engines may also be used to generate electricity). The capacity is estimated based on 20%, 40% and 

60% recovery efficiencies (i.e. percentage of total emissions recovered). The formula is: 

Generating Capacity (kW): CH4 liberated in cf/day x 1 day/24 hours x 1000 Btus/cf x kWh/11,000 Btus. 

Summary Table 16 lists the mines according to their potential electric generating capacity in MW. 

16 In the July 2004 edition of this report the range provided for the potential electric generating capacity in Table 16 was 

incorrect. Table 16 stated an assumed recovery efficiency of 20% – 60%. However, the range provided actually 

corresponded to a recovery efficiency of 20% - 40%. This error has been corrected in the current report. 

Key 4-7 
_________________________________________________________________________________________ 

Pipeline Potential 

This section presents data that are useful in determining whether a mine is a good candidate for a 

pipeline sales project. 

Potential Annual Gas Sales: Potential annual gas sales are estimated by multiplying total daily 

methane liberated by 365 days per year and then multiplying that value by the assumed recovery 

efficiency. Potential annual gas sales are calculated for 20%, 40%, and a 60% assumed recovery 

efficiencies and are presented in billion cubic feet. The estimated amount of gas that could be 

produced for sale to a pipeline at each candidate mine is shown in Summary Table 17. 

Description of Surrounding Terrain: The terrain surrounding the mine is described, as this is an 

important factor in determining the costs of laying gathering lines for the project. While many mines in 

Appalachia are located in hilly or mountainous terrain, mines in the Illinois Basin tend to be located on 

relatively flat plains. 

Transmission Pipeline in County: A "yes" indicates that an existing commercial pipeline runs through 

the county. 

Owner of Nearest Pipeline: The corporate owner of the pipeline located closest to the mine is 

provided. If a mine is utilizing methane it is assumed that the owner of the nearest pipeline is the 

mine itself. The mine’s pipeline would connect the mine to a commercial pipeline. 

Distance to Pipeline: The estimated distance from the closest pipeline to the mine is provided. Some 

western coal mines may be more than 20 miles from the nearest pipeline. In contrast, most eastern 

coal mines are located within ten miles of a commercial pipeline. However, while a mine may be 

located within close proximity to an existing gas pipeline, there are no guarantees that the pipeline will 

have enough capacity to take the gas produced from a coal mine. In particular, the Appalachian 

region tends to have limited pipeline capacity. If a mine is using methane it is assumed that the 

distance to the nearest commercial pipeline is zero, since the mine would have to have a pipeline in 

place to transport the gas. 

Pipeline Diameter: The diameter (in inches) of the nearest pipeline is provided. 

Other Utilization Possibilities 

This section addresses the possibility of using methane in a nearby coal-fired power plant. 

Name of Nearby Coal Fired Power Plant: A few of the mines profiled here are located less than ten 

miles from a coal-fired power plant. For these mines, the name of the nearby power plant is listed. 

The source of this information, along with the estimated distance to the power plant and the plant 

capacity is taken from the North American Electric Power Atlas, (Electric Power, 2002). 

Distance to Plant: The profile shows the estimated distance between the mine and the nearby power 

plant. 

Comments: This section briefly describes any other important information about the mine that is not 

listed in any other section. 

Key 4-8 
_________________________________________________________________________________________ 

Ventilation Air Methane Emissions 

Table 18 in Chapter 5 summarizes certain characteristics of ventilation air methane (VAM) emissions 

that were derived for each mine from Mine Safety and Health Administration (MSHA) quarterly 

sampling data. For each shaft at gassy mines, MSHA samples methane concentration and ventilation 

airflow. The shaft-specific data were aggregated to derive weighted average methane emissions for 

each mine. The most current MSHA shaft emissions data available were used. 

Key 4-9 
5. Mine Summary Tables 

List of Summary Tables: 

Table 1: Mines Listed Alphabetically 

Table 2: Mines Listed by State and County 

Table 3: Mines Listed by Coal Basin 

Table 4: Mines Listed by Coalbed 

Table 5: Mines Listed by Company 

Table 6: Mines Listed by Mining Method 

Table 7: Mines Listed by Primary Coal Use 

Table 8: Mines Listed by 2003 Coal Production 

Table 9: Mines Employing Methane Drainage Systems 

Table 10: Mines Listed by Estimated Total Methane Liberated in 2003 

Table 11: Mines Listed by Daily Ventilation Emissions in 2003 

Table 12: Mines Listed by Daily Methane Drained in 2003 

Table 13: Mines Listed by Estimated Specific Emissions in 2003 

Table 14: Mines Listed by CO2 Equivalent of Potential CH4 Emissions Reductions 

Table 15: Mines Listed by Electric Utility Supplier 

Table 16: Mines Listed by Potential Electric Generating Capacity 

Table 17: Mines Listed by Potential Annual Gas Sales 

Table 18: Mine Shaft Emissions 
____________________________________________________________________________________________________ 

Table 1: Mines Listed Alphabetically 

Mine Name State Mine Name State 

Aberdeen UT Justice #1 WV 

American Eagle Mine WV Loveridge No. 22 WV 

Bailey Mine PA Mc Elroy Mine WV 

Baker KY Mine #1 KY 

Beckley Crystal WV No. 3 Mine KY 

Blacksville No. 2 WV North River Mine AL 

Blue Creek No. 4 AL Oak Grove Mine AL 

Blue Creek No. 5 AL Pinnacle No. 50 WV 

Blue Creek No. 7 AL Pollyanna No. 8 OK 

Buchanan Mine VA Pontiki No. 2 KY 

Cardinal KY Powhatan No. 6 Mine OH 

Clean Energy No. 1 KY RAG Cumberland Mine PA 

Dakota No. 2 WV RAG Emerald Mine PA 

Deep Mine #26 VA Robinson Run No. 95 WV 

Dugout Canyon Mine UT San Juan South NM 

E3RF KY Sentinel Mine WV 

Eagle Mine WV Shoal Creek AL 

Eighty-Four Mine PA Shoemaker Mine WV 

Elk Creek Mine CO Upper Big Branch - South WV 

Elkhart Mine IL Virginia Pocahontas No. 8 VA 

Enlow Fork Mine PA Wabash IL 

Federal No. 2 WV West Elk Mine CO 

Freedom Energy No.1 KY West Ridge Mine UT 

Galatia IL Whitetail Kittanning Mine WV 

Gibson IN Willow Lake Portal IL 

Mine Summary Tables Page 5-1 
____________________________________________________________________________________________________ 

Table 2: Mines Listed by State and County 

Mine Name State County Mine Name State County 

North River Mine AL Fayette Enlow Fork Mine PA Greene 

Oak Grove Mine AL Jefferson RAG Cumberland Mine PA Greene 

Shoal Creek AL Jefferson RAG Emerald Mine PA Greene 

Blue Creek No. 4 AL Tuscaloosa Eighty-Four Mine PA Washington 

Blue Creek No. 5 AL Tuscaloosa Aberdeen UT Carbon 

Blue Creek No. 7 AL Tuscaloosa Dugout Canyon Mine UT Carbon 

Elk Creek Mine CO Gunnison West Ridge Mine UT Carbon 

West Elk Mine CO Gunnison Buchanan Mine VA Buchanan 

Galatia IL Saline Virginia Pocahontas No. 8 VA Buchanan 

Willow Lake Portal IL Saline Deep Mine #26 VA Wise 

Elkhart Mine IL Sangamon Sentinel Mine WV Barbour 

Wabash IL Wabash Dakota No. 2 WV Boone 

Gibson IN Gibson Justice #1 WV Boone 

Cardinal KY Hopkins Robinson Run No. 95 WV Harrison 

E3RF KY Knott American Eagle Mine WV Kanawha 

Pontiki No. 2 KY Martin Eagle Mine WV Kanawha 

Clean Energy No. 1 KY Pike Loveridge No. 22 WV Marion 

Freedom Energy No.1 KY Pike Mc Elroy Mine WV Marshall 

Mine #1 KY Pike Blacksville No. 2 WV Monongalia 

No. 3 Mine KY Pike Federal No. 2 WV Monongalia 

Baker KY Webster Shoemaker Mine WV Ohio 

San Juan South NM San Juan Whitetail Kittanning Mine WV Preston 

Powhatan No. 6 Mine OH Belmont Beckley Crystal WV Raleigh 

Pollyanna No. 8 OK Le Flore Upper Big Branch - South WV Raleigh 

Bailey Mine PA Greene Pinnacle No. 50 WV Wyoming 

Mine Summary Tables Page 5-2 
____________________________________________________________________________________________________ 

Table 3: Mines Listed by Coal Basin 

Coal Basin/ Estimated Specific Coal Basin/ Estimated Specific 

Mine Name Emissions (cf/ton) Mine Name Emissions (cf/ton) 

Arkoma Gibson 355 

Pollyanna No. 8 929 Wabash 279 

Black Warrior Willow Lake Portal 138 

Northern Appalachian 

Blue Creek No. 4 1,856 

Blue Creek No. 5 3,791 Bailey Mine 223 

Blue Creek No. 7 3,942 Blacksville No. 2 571 

North River Mine 437 Eighty-Four Mine 467 

Oak Grove Mine 2,666 Enlow Fork Mine 382 

Shoal Creek 1,200 Federal No. 2 725 

Central Appalachian Justice #1 565 

Loveridge No. 22 6,402 

American Eagle Mine 435 

Mc Elroy Mine 88 

Beckley Crystal 1,809 

Powhatan No. 6 Mine 84 

Buchanan Mine 3,318 

RAG Cumberland Mine 1,418 

Cardinal 136 

RAG Emerald Mine 631 

Clean Energy No. 1 265 

Robinson Run No. 95 314 

Dakota No. 2 366 

Sentinel Mine 1,114 

Deep Mine #26 619 

Shoemaker Mine 206 

E3RF 149 

Whitetail Kittanning Mine 265 

Eagle Mine 240 

San Juan 

Freedom Energy No.1 211 

Mine #1 156 San Juan South 223 

No. 3 Mine 217 Uinta 

Pinnacle No. 50 2,064 Aberdeen 995 

Pontiki No. 2 132 Elk Creek Mine 91 

Upper Big Branch - South 347 West Elk Mine 1,528 

Virginia Pocahontas No. 8 8,992 West Ridge Mine 443 

Central Rockies 

Dugout Canyon Mine 267 

Illinois 

Baker 898

Elkhart Mine 152

Galatia 238

Mine Summary Tables Page 5-3 
____________________________________________________________________________________________________ 

Table 4: Mines Listed by Coalbed 

Mine Name Coalbed Mine Name Coalbed 

West Elk Mine B Seam Eighty-Four Mine Pittsburgh 

Blue Creek No. 7 Blue Creek Mc Elroy Mine Pittsburgh 

Oak Grove Mine Blue Creek Bailey Mine Pittsburgh 

Blue Creek No. 5 Blue Creek Loveridge No. 22 Pittsburgh 

Shoal Creek Blue Creek, Mary Lee Robinson Run No. 95 Pittsburgh 

Blue Creek No. 4 Blue Creek, Mary Lee Shoemaker Mine Pittsburgh 

Elk Creek Mine D-seam Federal No. 2 Pittsburgh 

Eagle Mine Eagle, Big Eagle Powhatan No. 6 Mine Pittsburgh No. 8 

American Eagle Mine Eagle, Big Eagle Blacksville No. 2 Pittsburgh No. 8 

Upper Big Branch - South Eagle, Powellton RAG Emerald Mine Pittsburgh No. 8 

Dugout Canyon Mine Gilson, Rock Canyon RAG Cumberland Mine Pittsburgh No. 8 

Pollyanna No. 8 Hartshorne Dakota No. 2 Pittsburgh No. 8 

Willow Lake Portal Illinois No. 5 & 6 Virginia Pocahontas No. 8 Pocahontas No. 3 

Whitetail Kittanning Mine Kittanning Buchanan Mine Pocahontas No. 3 

Sentinel Mine Kittanning Pinnacle No. 50 Pocahontas No. 3 

Cardinal KY No. 11 Freedom Energy No.1 Pond Creek 

Aberdeen L. Sunnyside, Gilson, Aber. Pontiki No. 2 Pond Creek 

West Ridge Mine Lower Sunnyside Clean Energy No. 1 Pond Creek 

No. 3 Mine NA Justice #1 Powellton, Buffalo Crk 

Beckley Crystal NA North River Mine Pratt 

Mine #1 NA Wabash Springfield No. 5 

E3RF NA Elkhart Mine Springfield No. 5 

San Juan South No 9, No. 8 Galatia Springfield No. 5 

Deep Mine #26 Norton, Upper Banner Gibson Springfield No. 5 

Enlow Fork Mine Pittsburgh Baker W. Kentucky No. 13 

Mine Summary Tables Page 5-4 
____________________________________________________________________________________________________ 

Table 5: Mines Listed by Company 

Parent Company Owner Mine Name 

ABC Coke Division - 

Drummond Co., Inc. Shoal Creek 

Alliance Resource Partners 

Warrior Coal, LLC Cardinal 

Alliance Resource Partners 

Excel Mining Pontiki No. 2 

Excel Mining LLC No. 3 Mine 

Alliance Resources Partners 

Gibson County Coal, LLC Gibson 

Alpha Natural Resources LLC 

Paramount Coal Corp. Deep Mine #26 

American Coal Company 

The American Coal Co. Galatia 

Andalex Resources, Inc. 

Andalex Resources, Inc. Aberdeen 

West Ridge Resources West Ridge Mine 

Anker Energy Corp. 

Anker West Virginia Mining Co. Sentinel Mine 

Arch Coal Co. 

Canyon Fuel Co., LLC Dugout Canyon Mine 

Mountain Coal Co. West Elk Mine 

BHP/Billitton 

San Juan Coal Co. San Juan South 

Bluegrass Coal Devel. Co. 

Turris Coal Company Elkhart Mine 

Chevron Texaco 

Pittsburg & Midway Coal Mining North River Mine 

Mine Summary Tables Page 5-5 
____________________________________________________________________________________________________ 

Table 5: Mines Listed by Company (cont.) 

Parent Company Owner Mine Name 

CONSOL Energy 

Consol Energy Inc. Bailey Mine 

Consol Energy Inc. Blacksville No. 2 

Consol Energy Inc. Buchanan Mine 

Consol Energy Inc. Enlow Fork Mine 

Consol Energy Inc. Loveridge No. 22 

Consol Energy Inc. Mc Elroy Mine 

Consol Energy Inc. Robinson Run No. 95 

Consol Energy Inc. Shoemaker Mine 

Consol Energy Inc. Virginia Pocahontas No. 8 

Consol of Kentucky, Inc. E3RF 

Eighty-Four Mining Co. Eighty-Four Mine 

El Paso Corporation 

Coastal Coal Co., LLC Whitetail Kittanning Mine 

James O. Bunn; Frank D. 

Newtown Energy, Inc. Eagle Mine 

Lodestar Energy, Inc. 

Lodestar Energy, Inc Baker 

Massey Energy Co. 

Freedom Energy Mining Co. Freedom Energy No.1 

Independence Coal Co., Inc. Justice #1 

Massey Energy Co. Clean Energy No. 1 

Performance Coal Co. Upper Big Branch - South 

Rockhouse Energy Mining Mine #1 

Murray Energy Corporation 

Ohio Valley Coal Co. Powhatan No. 6 Mine 

Oxbow Carbon & Materials 

Oxbow Mining, Inc. Elk Creek Mine 

Peabody Energy Corp. 

Big Ridge Inc Willow Lake Portal 

Peabody Energy/Federal Federal No. 2 

Mine Summary Tables Page 5-6 
____________________________________________________________________________________________________ 

Table 5: Mines Listed by Company (cont.) 

Parent Company Owner Mine Name 

RAG American Coal Co. 

RAG Cumberland Resources, LP RAG Cumberland Mine 

RAG Emerald Resources, LP RAG Emerald Mine 

Wabash Mine Holding Co. Wabash 

Rainbow Trout Coal LLC 

Dakota Mining, Inc. Dakota No. 2 

Robert L. Worley 

Baylor Mining, Inc. Beckley Crystal 

South Central Coal Company 

Sunrise Coal Co., LLC Pollyanna No. 8 

Timothy G. Elliott 

Speed Mining, Inc. American Eagle Mine 

USX Corp. 

U.S. Steel Mining Co., L.L.C. Oak Grove Mine 

U.S. Steel Mining Co., L.L.C. Pinnacle No. 50 

Walter Industries, Inc. 

Jim Walter Resources, Inc. Blue Creek No. 4 

Jim Walter Resources, Inc. Blue Creek No. 5 

Jim Walter Resources, Inc. Blue Creek No. 7 

Mine Summary Tables Page 5-7 
____________________________________________________________________________________________________ 

Table 6: Mines Listed by Mining Method 

Mine Name Method Mine Name Method 

American Eagle Mine Continuous Baker Longwall/Continuous 

Beckley Crystal Continuous Blacksville No. 2 Longwall/Continuous 

Cardinal Continuous Blue Creek No. 4 Longwall/Continuous 

Clean Energy No. 1 Continuous Blue Creek No. 5 Longwall/Continuous 

Dakota No. 2 Continuous Blue Creek No. 7 Longwall/Continuous 

Deep Mine #26 Continuous Buchanan Mine Longwall/Continuous 

E3RF Continuous Dugout Canyon Mine Longwall/Continuous 

Eagle Mine Continuous Eighty-Four Mine Longwall/Continuous 

Elkhart Mine Continuous Enlow Fork Mine Longwall/Continuous 

Freedom Energy No.1 Continuous Federal No. 2 Longwall/Continuous 

Gibson Continuous Justice #1 Longwall/Continuous 

Mine #1 Continuous Loveridge No. 22 Longwall/Continuous 

No. 3 Mine Continuous Mc Elroy Mine Longwall/Continuous 

Pollyanna No. 8 Continuous North River Mine Longwall/Continuous 

Pontiki No. 2 Continuous Oak Grove Mine Longwall/Continuous 

Sentinel Mine Continuous Pinnacle No. 50 Longwall/Continuous 

Wabash Continuous Powhatan No. 6 Mine Longwall/Continuous 

Whitetail Kittanning Mine Continuous RAG Cumberland Mine Longwall/Continuous 

Willow Lake Portal Continuous RAG Emerald Mine Longwall/Continuous 

Elk Creek Mine Longwall Robinson Run No. 95 Longwall/Continuous 

Galatia Longwall Shoal Creek Longwall/Continuous 

San Juan South Longwall Shoemaker Mine Longwall/Continuous 

West Ridge Mine Longwall Upper Big Branch - South Longwall/Continuous 

Aberdeen Longwall/Continuous Virginia Pocahontas No. 8 Longwall/Continuous 

Bailey Mine Longwall/Continuous West Elk Mine Longwall/Continuous 

Mine Summary Tables Page 5-8 
____________________________________________________________________________________________________ 

Table 7: Mines Listed by Primary Coal Use 

Mine Name Primary Use Mine Name Primary Use 

Blue Creek No. 4 Metallurgical Pontiki No. 2 Steam 

Pinnacle No. 50 Metallurgical Powhatan No. 6 Mine Steam 

Upper Big Branch - South Metallurgical RAG Cumberland Mine Steam 

Beckley Crystal NA Robinson Run No. 95 Steam 

E3RF NA San Juan South Steam 

Eagle Mine NA Shoal Creek Steam 

Elk Creek Mine NA Shoemaker Mine Steam 

No. 3 Mine NA Wabash Steam 

Willow Lake Portal NA West Elk Mine Steam 

Aberdeen Steam West Ridge Mine Steam 

Baker Steam Whitetail Kittanning Mine Steam 

Blacksville No. 2 Steam American Eagle Mine Steam, Metallurgical 

Cardinal Steam Bailey Mine Steam, Metallurgical 

Dakota No. 2 Steam Blue Creek No. 5 Steam, Metallurgical 

Dugout Canyon Mine Steam Buchanan Mine Steam, Metallurgical 

Elkhart Mine Steam Clean Energy No. 1 Steam, Metallurgical 

Enlow Fork Mine Steam Deep Mine #26 Steam, Metallurgical 

Federal No. 2 Steam Eighty-Four Mine Steam, Metallurgical 

Galatia Steam Freedom Energy No.1 Steam, Metallurgical 

Gibson Steam Justice #1 Steam, Metallurgical 

Loveridge No. 22 Steam Oak Grove Mine Steam, Metallurgical 

Mc Elroy Mine Steam RAG Emerald Mine Steam, Metallurgical 

Mine #1 Steam Sentinel Mine Steam, Metallurgical 

North River Mine Steam Virginia Pocahontas No. 8 Steam, Metallurgical 

Pollyanna No. 8 Steam Blue Creek No. 7 Steam, Metallurgical, Ind. 

Mine Summary Tables Page 5-9 
____________________________________________________________________________________________________ 

Table 8: Mines Listed by 2003 Coal Production 

Mine Name MM Tons Mine Name MM Tons 

Enlow Fork Mine 9.9 Gibson 2.4 

Bailey Mine 9.4 Cardinal 2.4 

Mc Elroy Mine 6.8 Whitetail Kittanning Mine 2.4 

RAG Emerald Mine 6.6 Elkhart Mine 2.1 

West Elk Mine 6.5 Pontiki No. 2 2.0 

RAG Cumberland Mine 6.2 Mine #1 1.9 

Galatia 6.0 E3RF 1.9 

San Juan South 5.9 Virginia Pocahontas No. 8 1.9 

Robinson Run No. 95 5.7 Blue Creek No. 7 1.9 

Blacksville No. 2 5.4 Justice #1 1.8 

Powhatan No. 6 Mine 4.9 Oak Grove Mine 1.7 

Buchanan Mine 4.7 Wabash 1.6 

Elk Creek Mine 4.6 No. 3 Mine 1.5 

Federal No. 2 4.4 Dakota No. 2 1.5 

American Eagle Mine 4.1 Eagle Mine 1.5 

Eighty-Four Mine 4.0 Blue Creek No. 5 1.4 

Shoemaker Mine 3.8 Freedom Energy No.1 1.4 

Shoal Creek 3.8 Deep Mine #26 1.1 

North River Mine 3.5 Clean Energy No. 1 1.0 

Upper Big Branch - South 3.3 Baker 0.6 

West Ridge Mine 3.0 Beckley Crystal 0.5 

Dugout Canyon Mine 2.9 Aberdeen 0.4 

Willow Lake Portal 2.9 Pollyanna No. 8 0.4 

Blue Creek No. 4 2.8 Loveridge No. 22 0.3 

Pinnacle No. 50 2.5 Sentinel Mine 0.3 

Mine Summary Tables Page 5-10 
____________________________________________________________________________________________________ 

Table 9: Mines Employing Methane Drainage Systems 

Estimated Current 

Mine Name Type of Drainage System Drainage Efficiency 

Blacksville No. 2 Vertical Gob, Horizontal Pre-Mine 45% 

Blue Creek No. 4 Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 39% 

Blue Creek No. 5 Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 46% 

Blue Creek No. 7 Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 51% 

Buchanan Mine Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 83% 

Federal No. 2 Vertical Gob, Horizontal Pre-Mine 13% 

Loveridge No. 22 Vertical Gob, Horizontal Pre-Mine 82% 

Oak Grove Mine Vertical Pre-Mine, Vertical Gob 33% 

Pinnacle No. 50 Directional Pre-Mine, Vertical Gob, Horizontal Pre-Mine 30% 

RAG Cumberland Mine Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 59% 

RAG Emerald Mine Vertical Gob, Horizontal Pre-Mine 35% 

Robinson Run No. 95 Vertical Gob, Horizontal Pre-Mine 20% 

San Juan South Vertical Gob, Horizontal Pre-mine 65% 

Shoal Creek Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 35% 

Shoemaker Mine Vertical Gob, Horizontal Pre-Mine 15% 

Virginia Pocahontas No. 8 Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 83% 

West Elk Mine Vertical Gob, Horizontal Pre-Mine 50% 

Mine Summary Tables Page 5-11 
____________________________________________________________________________________________________ 

Table 10: Mines Listed by Estimated Total Methane Liberated in 2003 

Mine Name MMCF/D Mine Name MMCF/D 

Virginia Pocahontas No. 8 46.3 Gibson 2.4 

Buchanan Mine 42.6 Beckley Crystal 2.3 

West Elk Mine 27.2 Shoemaker Mine 2.2 

RAG Cumberland Mine 24.3 Dugout Canyon Mine 2.2 

Blue Creek No. 7 20.1 Deep Mine #26 1.9 

Blue Creek No. 5 14.4 Whitetail Kittanning Mine 1.7 

Blue Creek No. 4 14.2 Mc Elroy Mine 1.6 

Pinnacle No. 50 14.0 Baker 1.5 

Oak Grove Mine 12.6 Dakota No. 2 1.5 

Shoal Creek 12.6 Aberdeen 1.2 

RAG Emerald Mine 11.5 Wabash 1.2 

Enlow Fork Mine 10.3 Elk Creek Mine 1.1 

Federal No. 2 8.7 Powhatan No. 6 Mine 1.1 

Blacksville No. 2 8.5 Willow Lake Portal 1.1 

Bailey Mine 5.7 Pollyanna No. 8 1.0 

Loveridge No. 22 5.3 Eagle Mine 1.0 

Eighty-Four Mine 5.1 No. 3 Mine 0.9 

Robinson Run No. 95 4.9 Sentinel Mine 0.9 

American Eagle Mine 4.9 Elkhart Mine 0.9 

North River Mine 4.2 Cardinal 0.9 

Galatia 3.9 Mine #1 0.8 

West Ridge Mine 3.6 Freedom Energy No.1 0.8 

San Juan South 3.6 E3RF 0.8 

Upper Big Branch - South 3.1 Clean Energy No. 1 0.8 

Justice #1 2.8 Pontiki No. 2 0.7 

Mine Summary Tables Page 5-12 
____________________________________________________________________________________________________ 

Table 11: Mines Listed by Daily Ventilation Emissions in 2003 

Mine Name MMCF/D Mine Name MMCF/D 

West Elk Mine 13.6 Dugout Canyon Mine 2.2 

Enlow Fork Mine 10.3 Deep Mine #26 1.9 

RAG Cumberland Mine 9.9 Shoemaker Mine 1.8 

Pinnacle No. 50 9.8 Whitetail Kittanning Mine 1.7 

Blue Creek No. 7 9.8 Mc Elroy Mine 1.6 

Blue Creek No. 4 8.7 Baker 1.5 

Oak Grove Mine 8.5 Dakota No. 2 1.5 

Shoal Creek 8.2 San Juan South 1.3 

Virginia Pocahontas No. 8 7.9 Aberdeen 1.2 

Blue Creek No. 5 7.8 Wabash 1.2 

Federal No. 2 7.6 Elk Creek Mine 1.1 

RAG Emerald Mine 7.4 Powhatan No. 6 Mine 1.1 

Buchanan Mine 7.3 Willow Lake Portal 1.1 

Bailey Mine 5.7 Pollyanna No. 8 1.0 

Eighty-Four Mine 5.1 Eagle Mine 1.0 

American Eagle Mine 4.9 Loveridge No. 22 0.9 

Blacksville No. 2 4.7 No. 3 Mine 0.9 

North River Mine 4.2 Sentinel Mine 0.9 

Robinson Run No. 95 4.0 Elkhart Mine 0.9 

Galatia 3.9 Cardinal 0.9 

West Ridge Mine 3.6 Mine #1 0.8 

Upper Big Branch - South 3.1 Freedom Energy No.1 0.8 

Justice #1 2.8 E3RF 0.8 

Gibson 2.4 Clean Energy No. 1 0.8 

Beckley Crystal 2.3 Pontiki No. 2 0.7 

Mine Summary Tables Page 5-13 
____________________________________________________________________________________________________ 

Table 12: Mines Listed by Estimated Daily Methane Drained in 2003

 Mine Name MMCF/D Mine Name MMCF/D 

Virginia Pocahontas No. 8 38.4 Deep Mine #26 0.0 

Buchanan Mine 35.3 Dugout Canyon Mine 0.0 

RAG Cumberland Mine 14.4 E3RF 0.0 

West Elk Mine 13.6 Eagle Mine 0.0 

Blue Creek No. 7 10.3 Eighty-Four Mine 0.0 

Blue Creek No. 5 6.6 Elk Creek Mine 0.0 

Blue Creek No. 4 5.6 Elkhart Mine 0.0 

Shoal Creek 4.4 Enlow Fork Mine 0.0 

Loveridge No. 22 4.4 Freedom Energy No.1 0.0 

Pinnacle No. 50 4.2 Galatia 0.0 

Oak Grove Mine 4.1 Gibson 0.0 

RAG Emerald Mine 4.0 Justice #1 0.0 

Blacksville No. 2 3.8 Mc Elroy Mine 0.0 

San Juan South 2.3 Mine #1 0.0 

Federal No. 2 1.1 No. 3 Mine 0.0 

Robinson Run No. 95 1.0 North River Mine 0.0 

Shoemaker Mine 0.3 Pollyanna No. 8 0.0 

Aberdeen 0.0 Pontiki No. 2 0.0 

American Eagle Mine 0.0 Powhatan No. 6 Mine 0.0 

Bailey Mine 0.0 Sentinel Mine 0.0 

Baker 0.0 Upper Big Branch - South 0.0 

Beckley Crystal 0.0 Wabash 0.0 

Cardinal 0.0 West Ridge Mine 0.0 

Clean Energy No. 1 0.0 Whitetail Kittanning Mine 0.0 

Dakota No. 2 0.0 Willow Lake Portal 0.0 

Mine Summary Tables Page 5-14 
____________________________________________________________________________________________________ 

Table 13: Mines Listed by Estimated Specific Emissions in 2003 

Mine Name CF/Ton Mine Name CF/Ton 

Virginia Pocahontas No. 8 8,992 Enlow Fork Mine 382 

Loveridge No. 22 6,402 Dakota No. 2 366 

Blue Creek No. 7 3,942 Gibson 355 

Blue Creek No. 5 3,791 Upper Big Branch - South 347 

Buchanan Mine 3,318 Robinson Run No. 95 314 

Oak Grove Mine 2,666 Wabash 279 

Pinnacle No. 50 2,064 Dugout Canyon Mine 267 

Blue Creek No. 4 1,856 Whitetail Kittanning Mine 265 

Beckley Crystal 1,809 Clean Energy No. 1 265 

West Elk Mine 1,528 Eagle Mine 240 

RAG Cumberland Mine 1,418 Galatia 238 

Shoal Creek 1,200 Bailey Mine 223 

Sentinel Mine 1,114 San Juan South 223 

Aberdeen 995 No. 3 Mine 217 

Pollyanna No. 8 929 Freedom Energy No.1 211 

Baker 898 Shoemaker Mine 206 

Federal No. 2 725 Mine #1 156 

RAG Emerald Mine 631 Elkhart Mine 152 

Deep Mine #26 619 E3RF 149 

Blacksville No. 2 571 Willow Lake Portal 138 

Justice #1 565 Cardinal 136 

Eighty-Four Mine 467 Pontiki No. 2 132 

West Ridge Mine 443 Elk Creek Mine 91 

North River Mine 437 Mc Elroy Mine 88 

American Eagle Mine 435 Powhatan No. 6 Mine 84 

Mine Summary Tables Page 5-15 
____________________________________________________________________________________________________ 

Table 14: Mines Listed by CO2 Equivalent of 

Potential Annual CH4 Emissions Reductions 

(Assuming 20% - 60% Recovery Efficiency) 

Mine Name MM Tons CO2/Yr Mine Name MM Tons CO2/Yr 

Virginia Pocahontas No. 8 1.50 - 4.51 Gibson 0.08 - 0.23 

Buchanan Mine 1.38 - 4.15 Beckley Crystal 0.08 - 0.23 

West Elk Mine 0.88 - 2.65 Shoemaker Mine 0.07 - 0.21 

RAG Cumberland Mine 0.79 - 2.36 Dugout Canyon Mine 0.07 - 0.21 

Blue Creek No. 7 0.65 - 1.96 Deep Mine #26 0.06 - 0.19 

Blue Creek No. 5 0.47 - 1.40 Whitetail Kittanning Mine 0.06 - 0.17 

Blue Creek No. 4 0.46 - 1.38 Mc Elroy Mine 0.05 - 0.16 

Pinnacle No. 50 0.45 - 1.36 Baker 0.05 - 0.15 

Oak Grove Mine 0.41 - 1.23 Dakota No. 2 0.05 - 0.14 

Shoal Creek 0.41 - 1.23 Aberdeen 0.04 - 0.12 

RAG Emerald Mine 0.37 - 1.11 Wabash 0.04 - 0.12 

Enlow Fork Mine 0.34 - 1.01 Elk Creek Mine 0.04 - 0.11 

Federal No. 2 0.28 - 0.85 Powhatan No. 6 Mine 0.04 - 0.11 

Blacksville No. 2 0.28 - 0.83 Willow Lake Portal 0.04 - 0.11 

Bailey Mine 0.19 - 0.56 Pollyanna No. 8 0.03 - 0.10 

Loveridge No. 22 0.17 - 0.52 Eagle Mine 0.03 - 0.09 

Eighty-Four Mine 0.16 - 0.49 No. 3 Mine 0.03 - 0.09 

Robinson Run No. 95 0.16 - 0.48 Sentinel Mine 0.03 - 0.09 

American Eagle Mine 0.16 - 0.48 Elkhart Mine 0.03 - 0.09 

North River Mine 0.14 - 0.41 Cardinal 0.03 - 0.09 

Galatia 0.13 - 0.38 Mine #1 0.03 - 0.08 

West Ridge Mine 0.12 - 0.35 Freedom Energy No.1 0.03 - 0.08 

San Juan South 0.12 - 0.35 E3RF 0.02 - 0.07 

Upper Big Branch - South 0.10 - 0.30 Clean Energy No. 1 0.02 - 0.07 

Justice #1 0.09 - 0.27 Pontiki No. 2 0.02 - 0.07 

Mine Summary Tables Page 5-16 
____________________________________________________________________________________________________ 

Table 15: Mines Listed by Electric Utility Supplier 

Utility Parent Company 

Mine Name Utility Company 

Eagle Mine NA 

E3RF NA 

American Eagle Mine NA 

Dakota No. 2 NA 

Deep Mine #26 NA 

Elk Creek Mine NA 

Willow Lake Portal NA 

Elkhart Mine NA 

No. 3 Mine NA 

Mine #1 NA 

Beckley Crystal NA 

Allegheny Power Systems, Inc. 

Whitetail Kittanning Mine Monongahela Power Co. 

Blacksville No. 2 Monongahela Power Co. 

Loveridge No. 22 Monongahela Power Co. 

Robinson Run No. 95 Monongahela Power Co. 

Federal No. 2 Monongahela Power Co. 

Eighty-Four Mine West Penn Power Co. 

Enlow Fork Mine West Penn Power Co. 

RAG Emerald Mine West Penn Power Co. 

Bailey Mine West Penn Power Co. 

RAG Cumberland Mine West Penn Power Co. 

American Electric Power Co., Inc. 

Buchanan Mine Appalachian Power Co. 

Virginia Pocahontas No. 8 Appalachian Power Co. 

Pinnacle No. 50 Appalachian Power Co. 

Justice #1 Appalachian Power Co. 

Upper Big Branch - South Appalachian Power Co. 

Pontiki No. 2 Kentucky Power Co. 

Shoemaker Mine Wheeling Power Co. 

Mc Elroy Mine Wheeling Power Co. 

Mine Summary Tables Page 5-17 
____________________________________________________________________________________________________ 

Table 15: Mines Listed by Electric Utility Supplier (cont.) 

Utility Parent Company 

Mine Name Utility Company 

Cinergy 

Gibson PSI 

CIPSCO, Inc. 

Galatia Central Illinois Public Service 

DPL Inc. 

Powhatan No. 6 Mine The Dayton Power & Light Co. 

KU Energy 

Freedom Energy No.1 Kentucky Utilities Co.

Baker Kentucky Utilities Co.

Clean Energy No. 1 Kentucky Utilities Co.

Municipal Owned 

Sentinel Mine Philippi Municipal Electric 

OGE Energy Corp. 

Pollyanna No. 8 OGE Energy Corp 

Pacificorp 

Dugout Canyon Mine Pacificorp

West Ridge Mine Pacificorp

Aberdeen Price City Utilities, Utah Power & Light

Public Service of New Mexico 

San Juan South Public Service of New Mexico 

The Southern Co. 

Shoal Creek Alabama Power Co.

Oak Grove Mine Alabama Power Co.

Blue Creek No. 5 Alabama Power Co.

North River Mine Alabama Power Co.

Blue Creek No. 4 Alabama Power Co.

Blue Creek No. 7 Alabama Power Co.

Touchstone Energy Cooperatives 

West Elk Mine Delta Montrose Elec. Assoc./Gunnison County Elec. 

Cardinal Kenergy Corp

Wabash Wayne White Counties Elec. Coop./Norris Elec. 

Mine Summary Tables Page 5-18 
____________________________________________________________________________________________________ 

Table 16: Mines Listed by Potential Electric Generating Capacity

(Assuming 20% - 60% Recovery Efficiency) 

Mine Name Megawatts Mine Name Megawatts 

Virginia Pocahontas No. 8 35.1 - 105.2 Gibson 1.8 - 5.4 

Buchanan Mine 32.3 - 96.8 Beckley Crystal 1.8 - 5.3 

West Elk Mine 20.6 - 61.8 Shoemaker Mine 1.6 - 4.9 

RAG Cumberland Mine 18.4 - 55.1 Dugout Canyon Mine 1.6 - 4.9 

Blue Creek No. 7 15.2 - 45.7 Deep Mine #26 1.4 - 4.3 

Blue Creek No. 5 10.9 - 32.7 Whitetail Kittanning Mine 1.3 - 3.9 

Blue Creek No. 4 10.8 - 32.3 Mc Elroy Mine 1.2 - 3.7 

Pinnacle No. 50 10.6 - 31.7 Baker 1.1 - 3.4 

Oak Grove Mine 9.6 - 28.7 Dakota No. 2 1.1 - 3.4 

Shoal Creek 9.6 - 28.7 Aberdeen 0.9 - 2.8 

RAG Emerald Mine 8.7 - 26.0 Wabash 0.9 - 2.7 

Enlow Fork Mine 7.8 - 23.5 Elk Creek Mine 0.9 - 2.6 

Federal No. 2 6.6 - 19.9 Powhatan No. 6 Mine 0.9 - 2.6 

Blacksville No. 2 6.5 - 19.4 Willow Lake Portal 0.8 - 2.5 

Bailey Mine 4.3 - 13.0 Pollyanna No. 8 0.8 - 2.3 

Loveridge No. 22 4.0 - 12.1 Eagle Mine 0.7 - 2.2 

Eighty-Four Mine 3.8 - 11.5 No. 3 Mine 0.7 - 2.1 

Robinson Run No. 95 3.7 - 11.2 Sentinel Mine 0.7 - 2.0 

American Eagle Mine 3.7 - 11.2 Elkhart Mine 0.7 - 2.0 

North River Mine 3.2 - 9.6 Cardinal 0.7 - 2.0 

Galatia 3.0 - 8.9 Mine #1 0.6 - 1.9 

West Ridge Mine 2.7 - 8.2 Freedom Energy No.1 0.6 - 1.8 

San Juan South 2.7 - 8.2 E3RF 0.6 - 1.7 

Upper Big Branch - South 2.4 - 7.1 Clean Energy No. 1 0.6 - 1.7 

Justice #1 2.1 - 6.4 Pontiki No. 2 0.5 - 1.6 

Mine Summary Tables Page 5-19 
____________________________________________________________________________________________________ 

Table 17: Mines Listed by Potential Annual Gas Sales* 

(Assuming 20% - 60% Recovery Efficiency) 

Mine Name BCF/Yr Mine Name BCF/Yr 

Virginia Pocahontas No. 8 3.4 -10.1 Gibson 0.2 - 0.5 

Buchanan Mine 3.1 - 9.3 Beckley Crystal 0.2 - 0.5 

West Elk Mine 2.0 - 6.0 Shoemaker Mine 0.2 - 0.5 

RAG Cumberland Mine 1.8 - 5.3 Dugout Canyon Mine 0.2 - 0.5 

Blue Creek No. 7 1.5 - 4.4 Deep Mine #26 0.1 - 0.4 

Blue Creek No. 5 1.1 - 3.2 Whitetail Kittanning Mine 0.1 - 0.4 

Blue Creek No. 4 1.0 - 3.1 Mc Elroy Mine 0.1 - 0.4 

Pinnacle No. 50 1.0 - 3.1 Baker 0.1 - 0.3 

Oak Grove Mine 0.9 - 2.8 Dakota No. 2 0.1 - 0.3 

Shoal Creek 0.9 - 2.8 Aberdeen 0.1 - 0.3 

RAG Emerald Mine 0.8 - 2.5 Wabash 0.1 - 0.3 

Enlow Fork Mine 0.8 - 2.3 Elk Creek Mine 0.1 - 0.2 

Federal No. 2 0.6 - 1.9 Powhatan No. 6 Mine 0.1 - 0.2 

Blacksville No. 2 0.6 - 1.9 Willow Lake Portal 0.1 - 0.2 

Bailey Mine 0.4 - 1.3 Pollyanna No. 8 0.1 - 0.2 

Loveridge No. 22 0.4 - 1.2 Eagle Mine 0.1 - 0.2 

Eighty-Four Mine 0.4 - 1.1 No. 3 Mine 0.1 - 0.2 

Robinson Run No. 95 0.4 - 1.1 Sentinel Mine 0.1 - 0.2 

American Eagle Mine 0.4 - 1.1 Elkhart Mine 0.1 - 0.2 

North River Mine 0.3 - 0.9 Cardinal 0.1 - 0.2 

Galatia 0.3 - 0.9 Mine #1 0.1 - 0.2 

West Ridge Mine 0.3 - 0.8 Freedom Energy No.1 0.1 - 0.2 

San Juan South 0.3 - 0.8 E3RF 0.1 - 0.2 

Upper Big Branch - South 0.2 - 0.7 Clean Energy No. 1 0.1 - 0.2 

Justice #1 0.2 - 0.6 Pontiki No. 2 0.1 - 0.2 

* Mine's actual gas sales may differ from the potential 

Mine Summary Tables Page 5-20 
____________________________________________________________________________________________________ 

Table 18: Mine Shaft Emissions (2001) 

Shaft Weighted Shaft Vent Shaft Methane Mine Mine Name Shaft Name Air Flow Methane Flow Methane CFM Conc. % CFM Conc. % 

Aberdeen Aberdeen 517,249 2,608 0.50 0.50 

Bailey Bleeder 12A 193,738 577 0.30 

Bailey Bleeder 1E 219,398 2,230 1.02 0.61 

Bailey Bleeder 7B 150,385 634 0.42 

Baker Baker 738,685 1,718 0.23 0.23 

Blacksville #2 3,001,534 4,930 0.16 0.16 

Blue Creek No. 4 #4, North fan 2,023,813 6,915 0.34 0.34 

Blue Creek No. 5 #5, 5-7 fan 1,656,540 7,766 0.47 0.47 

Blue Creek No. 7 #7, South fan 1,563,218 6,165 0.39 

0.34 

Blue Creek No. 7 #7, South fan 1,904,878 5,678 0.30 

Bowie No. 2 No.2 423,768 85 0.02 0.02 

Buchanan #1 3,101,292 8,278 0.27 0.27 

Cadiz Portal 245,339 932 0.38 0.38 

Camp #11 #11 500,176 844 0.17 0.17 

Cardinal No. 2 #2 162,322 410 0.25 0.25 

Clean Energy No. 1 #1 473,924 1,264 0.27 0.27 

Cumberland #1 308,439 1,344 0.44 

Cumberland #6 540,459 2,130 0.39 

Cumberland Bleeder #1 167,909 2,614 1.56 0.64

Cumberland Bleeder #2 104,608 1,306 1.25 

Cumberland Bleeder #3 197,806 1,071 0.54 

Dugout Canyon 395,517 119 0.03 0.03 

Eighty-Four Mine Lang 130,365 917 0.70 

Eighty-Four Mine Smith 157,370 1,389 0.88 0.38

Eighty-Four Mine Zediker 538,793 853 0.16 

Emerald Bleeder #4 206,017 1,806 0.88 

0.35 

Emerald Emerald #7 684,012 1,318 0.19 

Enlow Fork A11 bleeder 270,518 2,178 0.80 

Enlow Fork B6 bleeder 255,353 1,735 0.68 0.79

Enlow Fork E1 bleeder 238,607 2,126 0.89 

Federal No. 2 #2 2,018,301 6,259 0.31 0.31 

Galatia Galatia 1,788,102 5,802 0.32 0.32 

Gibson Gibson 208,240 469 0.23 0.23 

Harris No. 1 #1 444,809 618 0.14 0.14 

Mine Summary Tables Page 5-21 
____________________________________________________________________________________________________ 

Table 18: Mine Shaft Emissions (cont.) 

Shaft Weighted Shaft Vent Shaft Methane Mine Mine Name Shaft Name Air Flow Methane Flow Methane CFM Conc. % CFM Conc. % 

Justice #1 Licks bleeder 222,761 546 0.24 

0.41 

Justice #1 Whites Br bleeder 206,935 1,226 0.59 

Leeco No. 68 387,748 318 0.08 0.08 

Loveridge No. 22 22 1,405,850 3,576 0.25 0.25 

McElroy McElroy 1,425,538 4,610 0.32 0.32 

Mine #1 #1 605,988 685 0.11 0.11 

Monterey No. 1 #1 764,901 673 0.09 0.09 

North River Cedar Cr 422,891 1,118 0.26 

0.36 

North River Tyro Cr 509,182 2,249 0.44 

Oak Grove #1 680,844 683 0.10 

Oak Grove #4 610,557 2,552 0.42 0.24 

Oak Grove #5 463,871 1,030 0.22 

Pattiki Pattiki 361,495 1,681 0.47 0.47 

Pinnacle Pinnacle 199,051 434 0.22 0.22 

Pollyanna No. 8 No.8 185,939 182 0.10 0.10 

Pontiki No. 2 #2 294,519 215 0.07 0.07 

Powhatan No. 6 #6 871,079 784 0.09 0.09 

Rend Lake 1,620,913 1,572 0.10 0.10 

Robinson Run Robinson Run 1,347,678 2,808 0.21 0.21 

San Juan South South 90,807 6 0.01 0.01 

Sanborn Creek Sanborn Creek 636,551 3,683 0.58 0.58 

Sentinel Sentinel 867,540 1,211 0.14 0.14 

Shoal Creek #2 514,181 1,538 0.30 

0.27 

Shoal Creek #4 470,259 1,081 0.23 

Shoemaker 1,672,768 3,178 0.19 0.19 

Tiller No. 1 #1 19,070 0 0.00 0.00 

U.S. Steel No. 50 8A 353,691 2,477 0.70 

U.S. Steel No. 50 Dale 396,627 2,496 0.63 0.50

U.S. Steel No. 50 South Fork 649,707 1,967 0.30 

Upper Big Branch Upper Big Branch 275,127 777 0.28 0.28 

VP No. 8 #8 2,693,001 5,852 0.22 0.22 

Wabash 1,063,658 1,106 0.10 0.10 

West Elk West Elk 1,519,703 7,231 0.48 0.48 

West Ridge 190,696 19 0.01 0.01 

Whitetail Kittanning 381,391 381 0.10 0.10 

Mine Summary Tables Page 5-22 
________________________________________________________________________________________________ 

6. Profiled Mines (continued) 

States with Candidate and Utilizing Mines: 

Alabama 

Colorado 

Illinois 

Indiana 

Kentucky 

New Mexico 

Ohio 

Oklahoma 

Pennsylvania 

Utah 

Virginia 

West Virginia 
___________________________________________________________________________________________________ 

6. Profiled Mines 

Data Summary 

Below is a state-by-state summary of data pertaining to coal mine methane at the mines profiled in 

this report. Chapter 4 explains how these data were derived. Following this data summary section are 

individual mine profiles, in alphabetical order by state. 

Alabama 

Of the twelve profiled U.S. mines that already recover and use methane, five are located in Alabama. 

Three of these mines are owned by Jim Walter Resources (JWR), one mine is owned by U.S. Steel, 

and one mine is owned by Drummond Coal. All five mines sell methane to pipelines. Based on 

information obtained from MSHA (2004), these five mines recovered and sold an average of 28 

mmcf/d in 2003. This recovery was drained from areas that are currently or will eventually be mined. 

In addition to these mines, Alabama has one other large gassy mine that appears to be a good 

candidate for a methane recovery project. North River has been in operation since 1974 and uses the 

longwall mining method. Table 6-1 shows that the implementation of a methane recovery and use 

project at the North River Mine could reduce annual methane emissions by 0.3 – 0.9 Bcf/yr. 

Table 6-1: Alabama Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation, Drainage and Use Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Estimated 

Methane 

Used 

(mmcf/d) 

Mines Using Methane (mines at which recovery and use projects have already been developed): 

Blue Creek No. 4 Jim Walter Res. 2.8 8.7 5.6 14.2 1,856 5.5 

Blue Creek No. 5 Jim Walter Res. 1.4 7.8 6.6 14.4 3,791 6.6 

Blue Creek No. 7 Jim Walter Res. 1.9 9.8 10.3 20.1 3,942 10.3 

Oak Grove U.S. Steel 1.7 8.5 4.1 12.6 2,666 4.1 

Shoal Creek Drummond 3.8 8.2 4.4 12.6 1,200 1.0 

Total for All Mines Using Methane 11.6 43.0 31.0 74.0 - 27.6 

Operating But Not Using Methane: 

North River Pitts. & Midway 3.5 4.2 0.0 4.2 437 0.0

 TOTAL:2 15.1 47.2 31.0 78.2 - 27.6 

Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent 

From Operating Mines Not Currently Using Methane (North River): 

2003 Estimated Total Emissions 

Estimated Annual Avoided Emissions if Recovery Project is Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

1.5 

0.3 - 0.9 

0.7 

0.1 – 0.4 

1

 Chapter 4 explains how these were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

Mine Summary Tables Page 6-1 
___________________________________________________________________________________________________ 

Colorado 

Colorado has a number of underground mines with relatively low methane emissions, but there are 

also several deep and gassy mines with high emissions; these mines present potential opportunities 

for those interested in developing a methane recovery project in the West. 

Of the two Colorado mines profiled in this report, West Elk began recovering methane in 2003 for use 

onsite (heaters). Table 6-2 shows coal production, methane ventilation, and drainage data. In 2003, 

West Elk liberated an estimated 27.2 mmcf/d (9.9 Bcf/yr), while recovering 0.1 mmcf/d (0.04 Bcf/yr). 

Colorado has three additional mines that are potential candidates for methane recovery: Elk Creek, 

Bowie No. 2, and Sanborn Creek. Among the three mines, only Elk Creek is profiled in this report17. 

Elk Creek had methane emissions totaling 1.1 mmcf/d in 2003. Table 6-2 shows that the 

implementation of methane recovery and use project at Elk Creek could reduce annual methane 

emissions by 0.1 – 0.2 Bcf/yr. 

Table 6-2: Colorado Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation, Drainage and Use Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Estimated 

Methane 

Used 

(mmcf/d) 

Mines Using Methane (mines at which recovery and use projects have already been developed): 

West Elk Mountain Coal 6.5 13.6 13.6 27.2 1,528 0.1 

Operating But Not Using Methane: 

Elk Creek Oxbow Mining 4.6 1.1 0.0 1.1 91 0.0

 TOTAL:2 11.1 14.7 13.6 28.3 - 0.1 

Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent 

From Operating Mines Not Currently Using Methane (Elk Creek): 

2003 Estimated Total Emissions 

Estimated Annual Avoided Emissions if Recovery Project is Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

0.4 

0.1 – 0.2 

0.2 

0.0 – 0.1 

1

 Chapter 4 explains how these were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

Illinois 

In general, Illinois mines tend to be less gassy than mines in other regions of the country. These 

mines tend to have lower specific emissions, but many have high total methane emissions depending 

on their yearly coal production. Accordingly, emissions reductions may be achieved at several of 

these mines. Coal production and methane ventilation and drainage data on these mines are shown 

in Table 6-3. 

Four operating Illinois mines are considered to be potential candidates for methane recovery projects. 

None of the featured Illinois mines have a degasification system in place. Table 6-3 shows that 

methane emissions from the four Illinois mines totaled an estimated 2.6 Bcf in 2003. Table 6-3 shows 

that the implementation of methane recovery and use projects at the four profiled mines that are 

17 Bowie No. 2 Mine is not profiled in this report because it did not emit large volumes of methane to the atmosphere in 2003. 

 Sanborn Creek Mine was closed in 2003. Both of these mines are examples of potential recovery projects in addition to the 

one highlighted in Table 6-2. 

Mine Summary Tables Page 6-2 
___________________________________________________________________________________________________ 

operating but not currently using methane could reduce annual methane emissions by 0.5 – 1.6 

Bcf/yr. 

Table 6-3: Illinois Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation and Drainage Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Operating But Not Using Methane: 

Elkhart Turris Coal 2.1 0.9 0.0 0.9 152 

Galatia American Coal Co. 6.0 3.9 0.0 3.9 238 

Wabash Wabash Mne. Hld. 1.6 1.2 0.0 1.2 279 

Willow Lake Portal Big Ridge Inc. 2.9 1.1 0.0 1.1 138 

TOTAL2: 12.6 7.1 0.0 7.1 -

Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent 

From Operating Mines Not Currently Using Methane (four mines): 

2003 Estimated Total Emissions 

 Estimated Annual Avoided Emissions if Recovery Projects are Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

2.6 

0.5 – 1.6 

1.2 

0.2 – 0.7 

1

 Chapter 4 explains how these data were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

Indiana 

A single Indiana mine, the Gibson Mine, is profiled in this report. This room-and-pillar operation, 

which opened in 2000, is currently considered the gassiest underground mine in Indiana. The mine 

produced 2.4 million tons of coal in 2003. Gibson Mine reported total methane emissions of 

approximately 0.88 billion cubic feet in 2003, and is not equipped with a degasification system. Based 

on these emissions, a methane use project may remain viable at the Gibson Mine. 

Kentucky 

Kentucky has eight operating mines that are good candidates for the development of methane 

recovery projects. The Baker Mine, which is located in the western Kentucky portion of the Illinois 

Coal Basin, is the gassiest in the state and the only one with methane emissions greater than 1 

mmcf/d. The other seven mines are located in the in eastern Kentucky, in the Central Appalachian 

Basin. 

Table 6-4 shows that methane emissions from the eight Kentucky mines totaled an estimated 2.6 Bcf 

in 2003. Implementation of methane recovery and use projects at these eight mines could reduce 

annual methane emissions by an estimated 0.5 - 1.6 Bcf/yr. 

Mine Summary Tables Page 6-3 
___________________________________________________________________________________________________ 

Table 6-4: Kentucky Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation and Drainage Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Operating But Not Using Methane: 

Baker Lodestar Energy 0.6 1.5 0.0 1.5 898 

Cardinal Warrior Coal 2.4 0.9 0.0 0.9 136 

Clean Energy No. 1 Massey Energy 1.0 0.8 0.0 0.8 265 

E3RF2 CONSOL of KY 1.9 0.8 0.0 0.8 149 

 Freedom Energy No. 1 Frdm. Engy. 

Mng. 

1.4 0.8 0.0 0.8 211 

Mine #1 Rockhouse 1.9 0.8 0.0 0.8 156 

No. 3 Mine Excel Mining 1.5 0.9 0.0 0.9 217 

Pontiki No. 2 Excel Mining 2.0 0.7 0.0 0.7 132 

TOTAL:3 12.7 7.2 0.0 7.2 -

Estimated Emissions and Avoided Emissions of Methane and CO2 

Equivalent From Operating Mines Not Currently Using Methane (8 mines): 

2003 Estimated Total Emissions 

Estimated Annual Avoided Emissions if Recovery Projects are Implemented4 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

2.6 

0.5 – 1.6 

1.2 

0.2 – 0.7 

1

 Chapter 4 explains how these data were estimated. 

2 Mine listed as permanently abandoned by EIA. However, according to the MSHA Data Retrieval System 

mine is currently active and never stopped producing coal. Mine listed as “No. 10 mine” operated by 

Ember Contracting. 

3

 Values shown here do not always sum to totals due to rounding. 

4 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

New Mexico 

The San Juan Mine, which is owned by the BHP Billiton, is the only New Mexico mine profiled in this 

report. This longwall mine opened in 2002 and methane recovery began in 2003. San Juan 

produced ventilation emissions of 1.3 mmcf/d in 2003, and total methane liberated was 3.6 mmcf/d 

(1.3 Bcf/yr) in 2003. The mine employs a degasification system which uses both vertical gob vent 

boreholes and in-mine, horizontal, pre-drainage boreholes. The mine recovered 40 mmcf/yr in 2003. 

Ohio 

As with the Illinois mines, Ohio mines tend to be less gassy than mines in other regions of the country. 

One operating Ohio mine is profiled in this report, the Powhatan No. 6 Mine. The mine produced 4.9 

million tons in 2003 and had ventilation emissions of 1.1 mmcf/d. As of 2003, Powhatan No. 6 had no 

drainage system in place. The implementation of a methane recovery and use project at this Ohio 

mine could reduce annual methane emissions by 0.1 - 0.2 Bcf/yr. 

Oklahoma 

A single Oklahoma mine, the Pollyanna No. 8 Mine, is profiled in this report. This room-and-pillar 

operation, which opened in 1996, is currently considered the gassiest underground mine in 

Oklahoma. In 2003, the mine produced 0.4 million tons annually and reported total methane 

emissions of approximately 0.37 billion cubic feet in 2003. Based on these emissions, and a history 

Mine Summary Tables Page 6-4 
___________________________________________________________________________________________________ 

of gassy mines in the Arkoma Basin, a coalmine methane project may be viable at the Pollyanna No. 

8 Mine. 

Pennsylvania 

Five operating Pennsylvania mines are good candidates for methane recovery and use and are 

profiled in this report. Several of the mines profiled in the previous edition of this report have recently 

closed. These mines may also be candidates for methane projects. Coal production, ventilation, and 

drainage data on these mines are shown in Table 6-5. 

In 2003, the five mines shown in Table 6-5 liberated about 56.9 mmcf/d (20.8 Bcf/yr) of methane. 

Several of these mines are located in Greene County, Pennsylvania. In fact, Greene County is the 

location of the two largest underground mines in the United States, CONSOL's Bailey and Enlow Fork 

mines. These mines are adjacent to one another and are often referred to as the Bailey-Enlow Fork 

complex. 

Two other large and gassy mines are also located in Greene County, RAG America’s Emerald and 

Cumberland mines. As with Bailey and Enlow Fork, Emerald and Cumberland are located in close 

proximity to each other. Both mines already have drainage systems in place, although the methane is 

not being used at present. 

Table 6-5 shows that the implementation of recovery and use projects at the five profiled 

Pennsylvania mines that are currently operating could reduce annual methane emissions by 4.2 – 

12.5 Bcf/yr. 

Table 6-5: Pennsylvania Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation and Drainage Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Operating But Not Using Methane: 

Bailey CONSOL 9.4 5.7 0.0 5.7 223 

Eighty-Four 84 Mining 4.0 5.1 0.0 5.1 467 

Enlow Fork CONSOL 9.9 10.3 0.0 10.3 382 

RAG Cumberland RAG Resources 6.2 9.9 14.4 24.3 1,418 

RAG Emerald RAG Resources 6.6 7.4 4.0 11.5 631 

TOTAL:2 36.1 38.4 18.4 56.9 -

Estimated Emissions and Avoided Emissions of Methane and CO2 

Equivalent From Operating Mines Not Currently Using Methane (five mines): 

2003 Estimated Total Emissions 

Estimated Annual Avoided Emissions if Recovery Projects are Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

20.8 

4.2 – 12.5 

9.2 

1.8 – 5.5 

1

 Chapter 4 explains how these data were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

Mine Summary Tables Page 6-5 
___________________________________________________________________________________________________ 

Utah 

Utah has a number of underground mines with relatively low methane emissions along the Wasatch 

Plateau, but it also has several deep and gassy mines with high methane emissions located nearby in 

the Uinta Basin. As with Colorado, these mines present potential opportunities for those interested in 

developing a methane recovery project in the West. Three operating Utah mines are good candidates 

for methane recovery and use and are profiled in this report18. 

The Aberdeen Mine is currently the gassiest in the state with 2003 estimated specific emissions of 

995 cf/ton. However, West Ridge and Dugout Canyon liberated a total of 3.6 mmcf/d and 2.2 mmcf/d 

in 2003, respectively. These Utah mines tend to have high specific emissions, and have produced 

high total methane emissions depending on their yearly coal production. Table 6-6 shows that the 

implementation of methane recovery and use projects at these three operating Utah mines could 

reduce annual methane emissions by 0.5 – 1.5 Bcf/yr. 

Table 6-6: Utah Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation and Drainage Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(est.) 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Operating But Not Using Methane: 

Aberdeen Andalex Resources 0.4 1.2 0.0 1.2 995 

Dugout Canyon Canyon Fuel Co. 2.9 2.2 0.0 2.2 267 

West Ridge Andalex Resources 3.0 3.6 0.0 3.6 443 

TOTAL:2 6.4 7.0 0.0 7.0 -

Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent 

From Operating Mines Not Currently Using Methane (three mines): 

2003 Estimated Total Emissions 

 Estimated Annual Avoided Emissions if Recovery Projects are Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

2.5 

0.5 – 1.5 

1.1 

0.2 – 0.7 

1

 Chapter 4 explains how these data were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

Virginia 

As Table 6-7 demonstrates, two of the mines at which successful methane recovery and use projects 

have already been developed are located in Virginia. The Buchanan and the VP No. 8 mines are both 

longwall operations, and are owned by subsidiaries of CONSOL. The total methane drained at the two 

CONSOL Virginia mine properties equaled 76 mmcf/d in 2003. This number significantly exceeds 

ventilation emissions of 15 mmcf/d, which indicates that recovery efficiencies (greater that 80% at VP 

No.8) are higher than standard EPA assumptions. Table 6-7 shows that CONSOL operates the 

largest active methane recovery project in the United States. 

Pinnacle mine, which closed in the Fall of 2003 as a consequence of ventilation problems, may also be potential 

candidate for a methane use and recovery project. 

Mine Summary Tables Page 6-6 

18 
___________________________________________________________________________________________________ 

Table 6-7: Virginia Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation, Drainage and Use Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Estimated 

Methane 

Used 

(mmcf/d) 

Mines Using Methane (mines at which recovery and use projects have already been developed): 

Buchanan CONSOL 4.7 7.3 35.3 42.6 3,318 36.4 

VP No. 8 CONSOL 1.9 7.9 38.4 46.3 8,992 39.5 

Total for All Mines Using Methane 6.6 15.2 73.7 88.9 - 75.9 

Operating But Not Using Methane: 

Deep Mine #26 Paramount Coal 1.1 1.9 0.0 1.9 619 0.0

 TOTAL:2 7.7 17.1 73.7 90.8 - 75.9 

Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent 

From Operating Mines Not Currently Using Methane (Deep Mine #26): 

2003 Estimated Total Emissions 

Estimated Annual Avoided Emissions if Recovery Project is Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

0.7 

0.1 – 0.4 

0.3 

0.1 – 0.2 

1

 Chapter 4 explains how these were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

West Virginia 

Of the 50 mines profiled in this report, 15 are located in West Virginia. Of these mines, three are 

currently recovering methane for sale. Coal production, methane ventilation, and drainage data on 

these mines are shown in Table 6-8. 

The three profiled mines that are recovering methane for sale are the Blacksville No. 2, Federal No. 2, 

and Pinnacle No. 50 mines. (The methane recovery project involving the Blacksville No. 2, Humphrey 

No. 7, and Loveridge No. 22 mines is often considered a Pennsylvania project, for reasons explained 

in Chapter 3). In 2003, these mines liberated an estimated 31.2 mmcf/d (11.4 Bcf/yr), while 

recovering 5.6 mmcf/d (2.0 Bcf/yr). Federal No. 2 recovered and sold about 0.3 Bcf of methane in 

2003, while Pinnacle No. 50 sold about 0.5 Bcf of methane to a gas marketing company, and the 

project at Blacksville No. 2 sold about 1.2 Bcf in 2003. 

Nine of the West Virginia mines profiled in this report are located in the Northern Appalachian Basin; 

five of these are owned by subsidiaries of CONSOL. The remaining six operating mines that are 

profiled are located in the Central Appalachian Basin. Table 6-8 shows that the implementation of 

methane recovery and use projects at the twelve operating mines that do not already use methane 

could reduce annual methane emissions by 2.4 – 7.1 Bcf/yr. 

Mine Summary Tables Page 6-7 
___________________________________________________________________________________________________ 

Table 6-8: West Virginia Mines 

Mine Company 

2003 Coal 

Production 

(mm tons) 

2003 Ventilation, Drainage and Use Data1 

Ventilation 

Emissions 

(mmcf/d) 

Estimated 

Methane 

Drained 

(mmcf/d) 

Estimated 

Total 

Methane 

Liberated 

(mmcf/d) 

Estimated 

Specific 

Emissions 

(cf/ton) 

Estimated 

Methane 

Used 

(mmcf/d) 

Mines Using Methane (mines at which recovery and use projects have already been developed): 

Blacksville No. 2 CONSOL 5.4 4.7 3.8 8.5 571 3.3 

Federal No. 2 Peabody Energy 4.4 7.6 1.1 8.7 725 0.8 

Pinnacle No. 50 U.S. Steel 2.5 9.8 4.2 14.0 2,064 1.5 

Total for All Mines Using Methane 12.3 22.1 9.1 31.2 - 5.6 

Operating But Not Using Methane: 

American Eagle Speed Mining 4.1 4.9 0.0 4.9 435 0.0 

Beckley Crystal Baylor Mining 0.5 2.4 0.0 2.3 1,809 0.0 

Dakota No. 2 Dakota Mining 1.5 1.5 0.0 1.5 366 0.0 

Eagle Newtown Energy 1.5 1.0 0.0 1.0 240 0.0 

Justice #1 Independence 1.8 2.8 0.0 2.8 565 0.0 

Loveridge No. 22 CONSOL 0.3 0.9 4.4 5.3 6,402 0.0 

Mc Elroy CONSOL 6.8 1.6 0.0 1.6 88 0.0 

Robinson Run No. 95 CONSOL 5.7 4.0 1.0 4.9 314 0.0 

Sentinel Anker WV Mining 0.3 0.9 0.0 0.9 1,114 0.0 

Shoemaker CONSOL 3.8 1.8 0.3 2.2 206 0.0 

Upper Big Branch So. Performance 3.3 3.1 0.0 3.1 347 0.0 

Whitetail-Kittanning Coastal Coal 2.4 1.7 0.0 1.7 265 0.0

 TOTAL:2 44.3 48.8 14.8 63.6 - 5.6 

Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent From 

Operating Mines Not Currently Using Methane (12 Mines): 

2003 Estimated Total Emissions 

Estimated Annual Avoided Emissions if Recovery Project is Implemented3 

Methane 

(Bcf/yr) 

CO2 

(mmt/yr)

11.8 

2.4 – 7.1 

5.2 

1.0 – 3.1 

1

 Chapter 4 explains how these were estimated. 

2 Values shown here do not always sum to totals due to rounding. 

3

 Range calculated assuming 20% - 60% of total liberated methane could be recovered. 

Mine Summary Tables Page 6-8 
6. Profiled Mines (continued) 

Alabama Mines 

Blue Creek No. 4 

North River 

Oak Grove 

Shoal Creek 

Blue Creek No. 5 

Blue Creek No. 7 
Updated: 08/01/2005 Status: Active

Blue Creek No. 4

GEOGRAPHIC DATA

Basin: Black Warrior State: AL

Coalbed: Blue Creek, Mary Lee County: Tuscaloosa

CORPORATE INFORMATION 

Current Owner: Jim Walter Resources, Inc. 

Parent Company: Walter Industries, Inc. Parent Company Web Site: www.jimwalterresources.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: No. 4 Mine 

MINE ADDRESS 

Contact Name: Keith Shalvey, Mine Mgr. Phone Number: (205) 554-6450 

Mailing Address: 14730 Lock 17 Rd. 

City: Brookwood State: AL ZIP: 35444 

GENERAL INFORMATION 

Number of Employees at Mine: 394 Mining Method: Longwall/Continuous 

Year of Initial Production: 1975 Primary Coal Use: Metallurgical 

Life Expectancy: 2020 Sulfur Content of Coal Produced: 0.75% - 0.95% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 14,200 

Depth to Seam (ft): 2,000 Seam Thickness (ft): 6.5 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 2.0 2.4 2.5 2.8 2.8 

Estimated Total Methane Liberated (million cf/day): 19.6 21.4 15.9 23.8 14.2 

Emission from Ventilation Systems: 12.0 11.0 8.0 11.7 8.7 

Estimated Methane Drained: 7.6 10.3 8.0 12.1 5.6 

Estimated Specific Emissions (cf/ton): 3526 3295 2290 3077 1856

Methane Recovered (million cf/day): 7.8 10.3 7.9 8.4 5.5

Estimated Current Drainage Efficiency: 39%

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Blue Creek No. 4 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.5 0.9 1.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 5.7% 11.3% 17.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.3% 2.6% 3.9% 

Power Generation Potential 

Utility Electric Supplier: Alabama Power Co. 

Parent Corporation of Utility: The Southern Co. 

MW GWh/year 

Total Electricity Demand (2003 data): 22.2 83.9 

Mine Electricity Demand: 17.4 67.1 

Prep Plant Electricity Demand: 4.8 16.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 10.8 94.4 

Assuming 40% Recovery Efficiency: 21.6 188.9

Assuming 60% Recovery Efficiency: 32.3 283.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 1.0

Assuming 40% Recovery (Bcf): 2.1

Assuming 60% Recovery (Bcf): 3.1

Description of Surrounding Terrain: Open Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Mine owns pipeline that connects to trans. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): 8.3 Pipeline Diameter (inches): 24.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Blue Creek No. 5

GEOGRAPHIC DATA

Basin: Black Warrior State: AL

Coalbed: Blue Creek County: Tuscaloosa

CORPORATE INFORMATION 

Current Owner: Jim Walter Resources, Inc. 

Parent Company: Walter Industries, Inc. Parent Company Web Site: www.jimwalterresources.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: No. 5 Mine 

MINE ADDRESS 

Contact Name: Trent Thrasher, Mine Mgr. Phone Number: (205) 554-6550 

Mailing Address: 12972 Lock 17 Rd. 

City: Brookwood State: AL ZIP: 35444 

GENERAL INFORMATION 

Number of Employees at Mine: 389 Mining Method: Longwall/Continuous 

Year of Initial Production: 1978 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: 2006 Sulfur Content of Coal Produced: 0.72% - 0.8% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,300 

Depth to Seam (ft): 2,140 Seam Thickness (ft): 8.3 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.7 2.0 1.5 0.7 1.4 

Estimated Total Methane Liberated (million cf/day): 22.7 23.9 23.6 12.0 14.4 

Emission from Ventilation Systems: 14.3 14.0 13.2 6.3 7.8 

Estimated Methane Drained: 8.4 10.0 10.4 5.8 6.6 

Estimated Specific Emissions (cf/ton): 4772 4410 5865 6451 3791

Methane Recovered (million cf/day): 8.3 9.9 9.4 5.8 6.6

Estimated Current Drainage Efficiency: 46%

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Blue Creek No. 5 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.5 0.9 1.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 12.3% 24.7% 37.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 2.9% 5.7% 8.6% 

Power Generation Potential 

Utility Electric Supplier: Alabama Power Co. 

Parent Corporation of Utility: The Southern Co. 

MW GWh/year 

Total Electricity Demand (2003 data): 11.0 41.6 

Mine Electricity Demand: 8.6 33.3 

Prep Plant Electricity Demand: 2.4 8.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 10.9 95.6 

Assuming 40% Recovery Efficiency: 21.8 191.1

Assuming 60% Recovery Efficiency: 32.7 286.7

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 1.1

Assuming 40% Recovery (Bcf): 2.1

Assuming 60% Recovery (Bcf): 3.2

Description of Surrounding Terrain: Open Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Mine owns pipeline that connects to trans. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): 10.0 Pipeline Diameter (inches): 24.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Blue Creek No. 7

GEOGRAPHIC DATA

Basin: Black Warrior State: AL

Coalbed: Blue Creek County: Tuscaloosa

CORPORATE INFORMATION 

Current Owner: Jim Walter Resources, Inc. 

Parent Company: Walter Industries, Inc. Parent Company Web Site: www.jimwalterresources.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: No. 7 Mine 

MINE ADDRESS 

Contact Name: Leon Robertson, Mine Mgr. Phone Number: (205) 554-6750 

Mailing Address: 18069 Hannah Creek 

City: Brookwood State: AL ZIP: 35444 

GENERAL INFORMATION 

Number of Employees at Mine: 407 Mining Method: Longwall/Continuous 

Year of Initial Production: 1975 Primary Coal Use: Steam, Metallurgical, Ind. 

Life Expectancy: 2039 Sulfur Content of Coal Produced: 0.58% -0.75% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 14,500 

Depth to Seam (ft): 1790 Seam Thickness (ft): 5.1 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 2.1 2.4 1.8 2.0 1.9 

Estimated Total Methane Liberated (million cf/day): 25.2 26.1 24.5 22.9 20.1 

Emission from Ventilation Systems: 16.9 16.9 14.7 11.0 9.8 

Estimated Methane Drained: 8.3 9.2 9.8 11.9 10.3 

Estimated Specific Emissions (cf/ton): 4467 3905 4881 4218 3942

Methane Recovered (million cf/day): 8.4 9.3 9.9 11.9 10.3

Estimated Current Drainage Efficiency: 51%

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Blue Creek No. 7 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.7 1.3 2.0 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 11.8% 23.5% 35.3% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 2.7% 5.4% 8.2% 

Power Generation Potential 

Utility Electric Supplier: Alabama Power Co. 

Parent Corporation of Utility: The Southern Co. 

MW GWh/year 

Total Electricity Demand (2003 data): 14.8 55.8 

Mine Electricity Demand: 11.6 44.7 

Prep Plant Electricity Demand: 3.2 11.2 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 15.2 133.4 

Assuming 40% Recovery Efficiency: 30.5 266.8

Assuming 60% Recovery Efficiency: 45.7 400.2

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 1.5

Assuming 40% Recovery (Bcf): 2.9

Assuming 60% Recovery (Bcf): 4.4

Description of Surrounding Terrain: Open Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Mine owns pipeline that connects to trans. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): 13.3 Pipeline Diameter (inches): 24.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

North River Mine

GEOGRAPHIC DATA

Basin: Black Warrior State: AL

Coalbed: Pratt County: Fayette

CORPORATE INFORMATION 

Current Owner: Pittsburg & Midway Coal Mining 

Parent Company: Chevron Texaco Parent Company Web Site: www.chevron.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: North River No. 1 

MINE ADDRESS 

Contact Name: Mark Premo, Gen. Mine Mgr. Phone Number: (205) 333-5000 

Mailing Address: 12398 New Lexington 

City: Berry State: AL ZIP: 35546 

GENERAL INFORMATION 

Number of Employees at Mine: 353 Mining Method: Longwall/Continuous 

Year of Initial Production: 1974 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.5% - 1.85% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 12,000 

Depth to Seam (ft): 516 Seam Thickness (ft): 4.7 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 2.3 2.6 3.2 3.4 3.5 

Estimated Total Methane Liberated (million cf/day): 5.2 3.8 5.6 5.1 4.2 

Emission from Ventilation Systems: 5.2 3.8 5.6 5.1 4.2 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 819 528 629 547 437 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
North River Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.3 0.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.6% 3.1% 4.7% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.7% 1.1% 

Power Generation Potential 

Utility Electric Supplier: Alabama Power Co. 

Parent Corporation of Utility: The Southern Co. 

MW GWh/year 

Total Electricity Demand (2003 data): 27.9 105.5 

Mine Electricity Demand: 21.9 84.4 

Prep Plant Electricity Demand: 6.0 21.1 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 3.2 27.9 

Assuming 40% Recovery Efficiency: 6.4 55.9

Assuming 60% Recovery Efficiency: 9.6 83.8

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.3

Assuming 40% Recovery (Bcf): 0.6

Assuming 60% Recovery (Bcf): 0.9

Description of Surrounding Terrain: Open Hills/Open High Hills 

Transmission Pipeline in County? No 

Owner of Nearest Pipeline: City Of Berry 

Distance to Pipeline (miles): 0.4 Pipeline Diameter (inches): 2.0 

Owner of Next Nearest Pipeline: SNG Intrastate Pipeline 

Distance to Next Nearest Pipeline (miles): 14.2 Pipeline Diameter (inches): 24.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Oak Grove Mine

GEOGRAPHIC DATA

Basin: Black Warrior State: AL

Coalbed: Blue Creek County: Jefferson

CORPORATE INFORMATION 

Current Owner: U.S. Steel Mining Co., L.L.C. 

Parent Company: USX Corp. Parent Company Web Site: www.uss.com/ussteel/Index.html 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: John Hedrick Phone Number: (205) 497-3602 

Mailing Address: 8800 Oak Grove Mine 

City: Adger State: AL ZIP: 35006 

GENERAL INFORMATION 

Number of Employees at Mine: 450 Mining Method: Longwall/Continuous 

Year of Initial Production: 1974 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: 2023 Sulfur Content of Coal Produced: 0.5% - 0.55% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 14,000 

Depth to Seam (ft): 1,100 Seam Thickness (ft): 5.8 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 2.1 2.1 1.8 1.9 1.7 

Estimated Total Methane Liberated (million cf/day): 12.6 10.4 8.8 12.7 12.6 

Emission from Ventilation Systems: 9.6 6.7 6.3 5.1 8.5 

Estimated Methane Drained: 3.0 3.7 2.5 7.6 4.1 

Estimated Specific Emissions (cf/ton): 2135 1803 1751 2385 2666 

Methane Recovered (million cf/day): 2.9 3.0 2.5 9.7 4.1 

Estimated Current Drainage Efficiency: 33% 

Drainage System Used: Vertical Pre-Mine, Vertical Gob 
Oak Grove Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.4 0.8 1.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 8.2% 16.5% 24.7% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.9% 3.8% 5.7% 

Power Generation Potential 

Utility Electric Supplier: Alabama Power Co. 

Parent Corporation of Utility: The Southern Co. 

MW GWh/year 

Total Electricity Demand (2003 data): 13.7 51.9 

Mine Electricity Demand: 10.8 41.5 

Prep Plant Electricity Demand: 2.9 10.4 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 9.6 83.9 

Assuming 40% Recovery Efficiency: 19.2 167.8

Assuming 60% Recovery Efficiency: 28.7 251.7

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.9

Assuming 40% Recovery (Bcf): 1.8

Assuming 60% Recovery (Bcf): 2.8

Description of Surrounding Terrain: Open Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Mine owns pipeline that connects to trans. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: SNG Intrastate Pipeline 

Distance to Next Nearest Pipeline (miles): 3.8 Pipeline Diameter (inches): 12.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Shoal Creek

GEOGRAPHIC DATA

Basin: Black Warrior State: AL

Coalbed: Blue Creek, Mary Lee County: Jefferson

CORPORATE INFORMATION 

Current Owner: Drummond Co., Inc. 

Parent Company: ABC Coke Division - Drummond Parent Company Web Site: www.drummondco.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Jay Vilseck Phone Number: (205) 491-6200 

Mailing Address: P.O. Box 1549 

City: Jasper State: AL ZIP: 35501 

GENERAL INFORMATION 

Number of Employees at Mine: 830 Mining Method: Longwall/Continuous 

Year of Initial Production: 1994 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.63% - 1.1% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 12,464 

Depth to Seam (ft): 1,180 Seam Thickness (ft): 7.5, 2.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.1 4.2 4.1 4.0 3.8 

Estimated Total Methane Liberated (million cf/day): 6.8 6.0 6.9 7.4 12.6 

Emission from Ventilation Systems: 6.6 5.7 6.6 6.7 8.2 

Estimated Methane Drained: 0.2 0.3 0.3 0.7 4.4 

Estimated Specific Emissions (cf/ton): 604 520 615 681 1200

Methane Recovered (million cf/day): 0.2 0.3 0.5 0.7 1.0

Estimated Current Drainage Efficiency: 35%

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Shoal Creek (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.4 0.8 1.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 4.2% 8.3% 12.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.0% 1.9% 2.9% 

Power Generation Potential 

Utility Electric Supplier: Alabama Power Co. 

Parent Corporation of Utility: The Southern Co. 

MW GWh/year 

Total Electricity Demand (2003 data): 30.4 115.2 

Mine Electricity Demand: 23.9 92.2 

Prep Plant Electricity Demand: 6.5 23.0 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 9.6 83.8 

Assuming 40% Recovery Efficiency: 19.1 167.5

Assuming 60% Recovery Efficiency: 28.7 251.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.9

Assuming 40% Recovery (Bcf): 1.8

Assuming 60% Recovery (Bcf): 2.8

Description of Surrounding Terrain: Open Hills/High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: SNG Intrastate Pipeline 

Distance to Pipeline (miles): NA Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
6. Profiled Mines (continued) 

Colorado Mines 

Elk Creek 

West Elk 
Updated: 08/01/2005 Status: Active

Elk Creek Mine

GEOGRAPHIC DATA

Basin: Uinta State: CO

Coalbed: D-seam County: Gunnison

CORPORATE INFORMATION 

Current Owner: Oxbow Mining, Inc. 

Parent Company: Oxbow Carbon & Materials Inc. Parent Company Web Site: www.oxbow.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: James Cooper Phone Number: (970) 929-5122 

Mailing Address: P.O. Box 535 

City: Somerset State: CO ZIP: 81434 

GENERAL INFORMATION 

Number of Employees at Mine: 258 Mining Method: Longwall 

Year of Initial Production: 2001 Primary Coal Use: NA 

Life Expectancy: 2011 Sulfur Content of Coal Produced: 0.5% - 0.8% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 11,750 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.0 0.0 0.6 4.6 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.0 0.1 1.1 

Emission from Ventilation Systems: 0.0 0.0 0.0 0.1 1.1 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - - - 31 91 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Elk Creek Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.3% 0.7% 1.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2% 0.2% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 36.4 137.9 

Mine Electricity Demand: 28.6 110.3 

Prep Plant Electricity Demand: 7.8 27.6 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.9 7.6 

Assuming 40% Recovery Efficiency: 1.7 15.1

Assuming 60% Recovery Efficiency: 2.6 22.7

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

West Elk Mine

GEOGRAPHIC DATA

Basin: Uinta State: CO

Coalbed: B Seam County: Gunnison

CORPORATE INFORMATION 

Current Owner: Mountain Coal Co. 

Parent Company: Arch Coal, Inc. Parent Company Web Site: www.archcoal.com 

Previous Owner(s): Atlantic Richfield/ITOCHU Corp. Previous or Alternate Name of Mine: Mt. Gunnison 

MINE ADDRESS 

Contact Name: Gene DiClaudio, Pres. & G.M. Phone Number: (970) 929-5015 

Mailing Address: P.O. Box 591 

City: Somerset State: CO ZIP: 81434 

GENERAL INFORMATION 

Number of Employees at Mine: 341 Mining Method: Longwall/Continuous 

Year of Initial Production: 1982 Primary Coal Use: Steam 

Life Expectancy: 2020 Sulfur Content of Coal Produced: 0.36% - 0.78% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 11,700 

Depth to Seam (ft): 1,000 - 2,000 Seam Thickness (ft): 12 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 7.1 3.4 5.0 6.6 6.5 

Estimated Total Methane Liberated (million cf/day): 11.8 15.7 16.1 19.8 27.2 

Emission from Ventilation Systems: 11.8 11.8 12.1 9.9 13.6 

Estimated Methane Drained: 0.0 3.9 4.0 9.9 13.6 

Estimated Specific Emissions (cf/ton): 607 1711 1169 1100 1528 

Methane Recovered (million cf/day): - - - - 0.1 

Estimated Current Drainage Efficiency: 50% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
West Elk Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.9 1.8 2.6 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 5.6% 11.3% 16.9% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.3% 2.6% 3.9% 

Power Generation Potential 

Utility Electric Supplier: Delta Montrose Elec. Assoc./Gunnison County 

Elec. Assoc. 

Parent Corporation of Utility: Touchstone Energy Cooperatives 

MW GWh/year 

Total Electricity Demand (2003 data): 51.5 194.7 

Mine Electricity Demand: 40.4 155.8 

Prep Plant Electricity Demand: 11.1 38.9 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 20.6 180.4 

Assuming 40% Recovery Efficiency: 41.2 360.8

Assuming 60% Recovery Efficiency: 61.8 541.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 2.0

Assuming 40% Recovery (Bcf): 4.0

Assuming 60% Recovery (Bcf): 6.0

Description of Surrounding Terrain: Hilly/Mountainous 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Rocky Mountain Natural Gas 

Distance to Pipeline (miles): < 25.0 Pipeline Diameter (inches): 8.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Hospital and other institutional facilities. 
6. Profiled Mines (continued)

 Illinois Mines 

Elkhart 

Galatia 

Wabash 

Willow Lake Portal 
Updated: 08/01/2005 Status: Active

Elkhart Mine

GEOGRAPHIC DATA

Basin: Illinois State: IL

Coalbed: Springfield No. 5 County: Sangamon

CORPORATE INFORMATION 

Current Owner: Turris Coal Company 

Parent Company: Bluegrass Coal Devel. Co. Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: C. Lane Phone Number: (606) 923-2934 

Mailing Address: 8100 E. Main 

City: Williamsville State: IL ZIP: 62693 

GENERAL INFORMATION 

Number of Employees at Mine: 219 Mining Method: Continuous 

Year of Initial Production: 1982 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 3.0% - 3.2% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 10,454 

Depth to Seam (ft): 290 Seam Thickness (ft): 5.7 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 2.3 2.0 2.1 1.8 2.1 

Estimated Total Methane Liberated (million cf/day): 0.5 0.5 0.5 0.6 0.9 

Emission from Ventilation Systems: 0.5 0.5 0.5 0.6 0.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 79 101 93 122 152 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Elkhart Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.6% 1.3% 1.9% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.3% 0.4% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 16.9 64.0 

Mine Electricity Demand: 13.3 51.2 

Prep Plant Electricity Demand: 3.6 12.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.7 5.9 

Assuming 40% Recovery Efficiency: 1.3 11.8

Assuming 60% Recovery Efficiency: 2.0 17.7

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active 

Galatia 

GEOGRAPHIC DATA 

Basin: Illinois State: IL 

Coalbed: Springfield No. 5 County: Saline 

CORPORATE INFORMATION 

Current Owner: The American Coal Co. 

Parent Company: American Coal Company Parent Company Web Site: NA 

Previous Owner(s): Kerr-McGee Coal Corp. Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Maynard St. John, Mine Mgr. Phone Number: (618) 268-6311 

Mailing Address: P.O. Box 727 

City: Harrisburg State: IL ZIP: 62946 

GENERAL INFORMATION 

Number of Employees at Mine: 585 Mining Method: Longwall 

Year of Initial Production: 1983 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.2% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 12,000 

Depth to Seam (ft): 400 Seam Thickness (ft): 7.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 6.5 7.3 7.0 6.3 6.0 

Estimated Total Methane Liberated (million cf/day): 8.6 10.3 8.4 6.1 3.9 

Emission from Ventilation Systems: 8.6 10.3 8.4 6.1 3.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 483 509 436 354 238 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Galatia (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.3 0.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.9% 1.7% 2.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.4% 0.6% 

Power Generation Potential 

Utility Electric Supplier: Central Illinois Public Service 

Parent Corporation of Utility: CIPSCO, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 47.7 180.3 

Mine Electricity Demand: 37.4 144.3 

Prep Plant Electricity Demand: 10.2 36.1 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 3.0 26.0 

Assuming 40% Recovery Efficiency: 5.9 52.0

Assuming 60% Recovery Efficiency: 8.9 78.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.3

Assuming 40% Recovery (Bcf): 0.6

Assuming 60% Recovery (Bcf): 0.9

Description of Surrounding Terrain: Open Hills/Irregular Plains 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Texas Eastern Transmission Co. 

Distance to Pipeline (miles): 0.8 Pipeline Diameter (inches): 24.0 

Owner of Next Nearest Pipeline: Trunkline 

Distance to Next Nearest Pipeline (miles): 8.0 Pipeline Diameter (inches): 26" 

miles 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Apparel, fertilizers, trusses, and mine equipment manufacturing. 
Updated: 08/01/2005 Status: Active

Wabash

GEOGRAPHIC DATA

Basin: Illinois State: IL

Coalbed: Springfield No. 5 County: Wabash

CORPORATE INFORMATION 

Current Owner: Wabash Mine Holding Co. 

Parent Company: RAG American Coal Co. Parent Company Web Site: http://www.rag-american.com/ 

Previous Owner(s): Amax Coal Co. Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: William Kelly, Gen. Mine Mgr. Phone Number: (618) 298-2394 

Mailing Address: P.O. Box 144, 1000 

City: Keensburg State: IL ZIP: 62852 

GENERAL INFORMATION 

Number of Employees at Mine: 234 Mining Method: Continuous 

Year of Initial Production: 1973 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.5% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 11,000 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.3 1.5 1.5 1.5 1.6 

Estimated Total Methane Liberated (million cf/day): 0.8 1.2 1.5 0.8 1.2 

Emission from Ventilation Systems: 0.8 1.2 1.5 0.8 1.2 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 220 298 382 189 279 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Wabash (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.1% 2.2% 3.3% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.5% 0.8% 

Power Generation Potential 

Utility Electric Supplier: Wayne White Counties Elec. Coop./Norris Elec. 

Coop. 

Parent Corporation of Utility: Touchstone Energy Cooperatives 

MW GWh/year 

Total Electricity Demand (2003 data): 12.4 47.0 

Mine Electricity Demand: 9.8 37.6 

Prep Plant Electricity Demand: 2.7 9.4 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.9 8.0 

Assuming 40% Recovery Efficiency: 1.8 15.9

Assuming 60% Recovery Efficiency: 2.7 23.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.3

Description of Surrounding Terrain: Irregular Plains 

Transmission Pipeline in County? No 

Owner of Nearest Pipeline: Texas Eastern Transmission Co. 

Distance to Pipeline (miles): 4.2 Pipeline Diameter (inches): 24.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Willow Lake Portal

GEOGRAPHIC DATA

Basin: Illinois State: IL

Coalbed: Illinois No. 5 & 6 County: Saline

CORPORATE INFORMATION 

Current Owner: Big Ridge Inc 

Parent Company: Peabody Energy Parent Company Web Site: NA 

Previous Owner(s): Arclar Co., LLC Previous or Alternate Name of Mine: Willow Lake Mine 

MINE ADDRESS 

Contact Name: Mike Fourney Phone Number: (314) 342-7699 

Mailing Address: 420 Long Lane Rd 

City: Equality State: IL ZIP: 62934 

GENERAL INFORMATION 

Number of Employees at Mine: 307 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: NA 

Life Expectancy: NA Sulfur Content of Coal Produced: 2% - 5% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,200 

Depth to Seam (ft): NA Seam Thickness (ft): 4.5 - 5 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.0 0.0 2.1 2.9 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.0 0.5 1.1 

Emission from Ventilation Systems: 0.0 0.0 0.0 0.5 1.1 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - - - 86 138 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Willow Lake Portal (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.5% 1.0% 1.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2% 0.3% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 22.6 85.6 

Mine Electricity Demand: 17.8 68.5 

Prep Plant Electricity Demand: 4.9 17.1 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.8 7.2 

Assuming 40% Recovery Efficiency: 1.6 14.3

Assuming 60% Recovery Efficiency: 2.5 21.5

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
6. Profiled Mines (continued) 

Indiana Mines 

Gibson 
Updated: 08/01/2005 Status: Active

Gibson

GEOGRAPHIC DATA

Basin: Illinois State: IN

Coalbed: Springfield No. 5 County: Gibson

CORPORATE INFORMATION 

Current Owner: Gibson County Coal, LLC 

Parent Company: Alliance Resources Partners Parent Company Web Site: www.arlp.com 

Previous Owner(s): Alliance Resources Holdings Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: NA Phone Number: (812) 385-1816 

Mailing Address: P.O.Box 1269 

City: Princeton State: IN ZIP: 47670 

GENERAL INFORMATION 

Number of Employees at Mine: 153 Mining Method: Continuous 

Year of Initial Production: 2000 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.6% - 7.2% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 12,800 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.0 1.7 1.9 2.4 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 1.3 2.2 2.4 

Emission from Ventilation Systems: 0.0 0.0 1.3 2.2 2.4 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - 0 291 406 355 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Gibson (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.2 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.2% 2.4% 3.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.6% 0.8% 

Power Generation Potential 

Utility Electric Supplier: PSI 

Parent Corporation of Utility: Cinergy 

MW GWh/year 

Total Electricity Demand (2003 data): 19.4 73.4 

Mine Electricity Demand: 15.2 58.7 

Prep Plant Electricity Demand: 4.2 14.7 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.8 15.8 

Assuming 40% Recovery Efficiency: 3.6 31.6

Assuming 60% Recovery Efficiency: 5.4 47.4

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.2

Assuming 40% Recovery (Bcf): 0.3

Assuming 60% Recovery (Bcf): 0.5

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Texas Gas Transmission Co. 

Distance to Pipeline (miles): < 5.0 Pipeline Diameter (inches): 4.0 

Owner of Next Nearest Pipeline: Texas Eastern Transmission Co. 

Distance to Next Nearest Pipeline (miles): < 10.0 Pipeline Diameter (inches): 20"

 miles 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
6. Profiled Mines (continued)

 Kentucky Mines 

Baker 

Cardinal 

Clean Energy No. 1 

E3RF 

Freedom Energy No. 1 

Mine #1 

No. 3 Mine 

Pontiki No. 2 
Updated: 08/01/2005 Status: Active

Baker

GEOGRAPHIC DATA

Basin: Illinois State: KY

Coalbed: W. Kentucky No. 13 County: Webster

CORPORATE INFORMATION 

Current Owner: Lodestar Energy, Inc 

Parent Company: Lodestar Energy, Inc. Parent Company Web Site: www.lodestarenergy.com 

Previous Owner(s): The Renco Group Previous or Alternate Name of Mine: Pyro/Baker 

MINE ADDRESS 

Contact Name: David Wineberger, Mine Mgr. Phone Number: (270) 667-7025 

Mailing Address: P.O. Box 448 

City: Clay State: KY ZIP: 42404 

GENERAL INFORMATION 

Number of Employees at Mine: 390 Mining Method: Longwall/Continuous 

Year of Initial Production: NA Primary Coal Use: Steam 

Life Expectancy: 2005 Sulfur Content of Coal Produced: 1.9% - 3.0% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 9,400 

Depth to Seam (ft): 850 Seam Thickness (ft): 6.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.5 4.3 3.4 2.9 0.6 

Estimated Total Methane Liberated (million cf/day): 2.2 2.2 3.4 2.3 1.5 

Emission from Ventilation Systems: 2.0 2.2 3.4 2.3 1.5 

Estimated Methane Drained: 0.2 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 179 187 366 289 898 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Baker (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 4.2% 8.4% 12.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.0% 1.9% 2.9% 

Power Generation Potential 

Utility Electric Supplier: Kentucky Utilities Co. 

Parent Corporation of Utility: KU Energy 

MW GWh/year 

Total Electricity Demand (2003 data): 4.9 18.4 

Mine Electricity Demand: 3.8 14.7 

Prep Plant Electricity Demand: 1.0 3.7 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.1 10.0 

Assuming 40% Recovery Efficiency: 2.3 20.0

Assuming 60% Recovery Efficiency: 3.4 30.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.3

Description of Surrounding Terrain: Open Hills 

Transmission Pipeline in County? No 

Owner of Nearest Pipeline: Texas Gas Transmission 

Distance to Pipeline (miles): 8.3 Pipeline Diameter (inches): 26.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Cardinal

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: KY No. 11 County: Hopkins

CORPORATE INFORMATION 

Current Owner: Warrior Coal, LLC 

Parent Company: Alliance Resource Partners Parent Company Web Site: www.alrp.com 

Previous Owner(s): Roberts Brothers Coal Co., Inc. Previous or Alternate Name of Mine: Cardinal No. 2 

MINE ADDRESS 

Contact Name: Brian Kelley, Manager of Phone Number: (270) 249-3100 

Mailing Address: 57 J.E. Ellis 

City: Madisonville State: KY ZIP: 42431 

GENERAL INFORMATION 

Number of Employees at Mine: 220 Mining Method: Continuous 

Year of Initial Production: 1993 Primary Coal Use: Steam 

Life Expectancy: 2012 Sulfur Content of Coal Produced: 3.29% - 4.27% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 11,440 

Depth to Seam (ft): 600 Seam Thickness (ft): 6.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.5 1.6 1.8 1.6 2.4 

Estimated Total Methane Liberated (million cf/day): 0.4 0.8 0.7 0.6 0.9 

Emission from Ventilation Systems: 0.4 0.8 0.7 0.6 0.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 112 177 140 148 136 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Cardinal (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.5% 1.0% 1.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2% 0.4% 

Power Generation Potential 

Utility Electric Supplier: Kenergy Corp 

Parent Corporation of Utility: Touchstone Energy Cooperatives 

MW GWh/year 

Total Electricity Demand (2003 data): 18.8 71.1 

Mine Electricity Demand: 14.7 56.9 

Prep Plant Electricity Demand: 4.0 14.2 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.7 5.8 

Assuming 40% Recovery Efficiency: 1.3 11.7

Assuming 60% Recovery Efficiency: 2.0 17.5

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: ANR Pipeline Company 

Distance to Pipeline (miles): < 3.0 Pipeline Diameter (inches): 30.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

Clean Energy No. 1

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: Pond Creek County: Pike

CORPORATE INFORMATION 

Current Owner: Massey Energy Co. 

Parent Company: Massey Energy Co. Parent Company Web Site: www.masseyenergyco.com 

Previous Owner(s): Sidney Coal Co., Clean Energy Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Barry Dotson Phone Number: (804) 788-1800 

Mailing Address: 29501 Mayo Trail 

City: Cattlesburg State: KY ZIP: 41129 

GENERAL INFORMATION 

Number of Employees at Mine: 92 Mining Method: Continuous 

Year of Initial Production: 1994 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: NA 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,200 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.2 1.1 1.3 1.1 1.0 

Estimated Total Methane Liberated (million cf/day): 1.2 1.0 0.9 0.9 0.8 

Emission from Ventilation Systems: 1.2 1.0 0.9 0.9 0.8 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 377 332 231 277 265 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Clean Energy No. 1 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.0 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.9% 1.7% 2.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.4% 0.6% 

Power Generation Potential 

Utility Electric Supplier: Kentucky Utilities Co. 

Parent Corporation of Utility: KU Energy 

MW GWh/year 

Total Electricity Demand (2003 data): 8.3 31.4 

Mine Electricity Demand: 6.5 25.1 

Prep Plant Electricity Demand: 1.8 6.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.6 5.0 

Assuming 40% Recovery Efficiency: 1.2 10.1

Assuming 60% Recovery Efficiency: 1.7 15.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas of Kentucky, Inc. 

Distance to Pipeline (miles): < 2.0 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

E3RF

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: NA County: Knott

CORPORATE INFORMATION 

Current Owner: Consol of Kentucky, Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Richard Liberatore Phone Number: (412) 831-4212 

Mailing Address: PO Box 1500 

City: Pikesville State: KY ZIP: 41502 

GENERAL INFORMATION 

Number of Employees at Mine: 175 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: NA 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.5% - 5.2% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,500 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.3 1.1 2.7 2.1 1.9 

Estimated Total Methane Liberated (million cf/day): 0.0 0.2 0.5 0.6 0.8 

Emission from Ventilation Systems: 0.0 0.2 0.5 0.6 0.8 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 0 52 64 105 149 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
E3RF (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.0 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.5% 1.0% 1.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2% 0.4% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 14.9 56.5 

Mine Electricity Demand: 11.7 45.2 

Prep Plant Electricity Demand: 3.2 11.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.6 5.1 

Assuming 40% Recovery Efficiency: 1.2 10.2

Assuming 60% Recovery Efficiency: 1.7 15.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

Freedom Energy No.1

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: Pond Creek County: Pike

CORPORATE INFORMATION 

Current Owner: Freedom Energy Mining Co. 

Parent Company: Massey Energy Co. Parent Company Web Site: www.masseyenergyco.com 

Previous Owner(s): Aero Energy Co., Inc. Previous or Alternate Name of Mine: Mine #1 

MINE ADDRESS 

Contact Name: Nick Pope Phone Number: (304) 235-4290 

Mailing Address: P.O. Box 299 

City: Sydney State: KY ZIP: 41564 

GENERAL INFORMATION 

Number of Employees at Mine: 123 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.67% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,822 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.5 1.5 1.9 1.9 1.4 

Estimated Total Methane Liberated (million cf/day): 1.1 1.1 1.0 0.8 0.8 

Emission from Ventilation Systems: 1.1 1.1 1.0 0.8 0.8 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 257 281 202 151 211 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Freedom Energy No.1 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.7% 1.4% 2.1% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.3% 0.5% 

Power Generation Potential 

Utility Electric Supplier: Kentucky Utilities Co. 

Parent Corporation of Utility: KU Energy 

MW GWh/year 

Total Electricity Demand (2003 data): 10.7 40.5 

Mine Electricity Demand: 8.4 32.4 

Prep Plant Electricity Demand: 2.3 8.1 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.6 5.2 

Assuming 40% Recovery Efficiency: 1.2 10.4

Assuming 60% Recovery Efficiency: 1.8 15.5

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas of Kentucky, Inc. 

Distance to Pipeline (miles): < 2.0 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Mine #1

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: NA County: Pike

CORPORATE INFORMATION 

Current Owner: Rockhouse Energy Mining 

Parent Company: Massey Energy Company Parent Company Web Site: www.masseyenergyco.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Nick Pope Phone Number: (304) 235-4290 

Mailing Address: P.O. Box 299 

City: Sidney State: KY ZIP: 41564 

GENERAL INFORMATION 

Number of Employees at Mine: 129 Mining Method: Continuous 

Year of Initial Production: 1995 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.8% - 1.4% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,440 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.6 1.0 0.7 1.8 1.9 

Estimated Total Methane Liberated (million cf/day): 0.4 0.3 0.3 0.4 0.8 

Emission from Ventilation Systems: 0.4 0.3 0.3 0.4 0.8 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 243 129 167 86 156 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Mine #1 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.5% 1.0% 1.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2% 0.3% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 15.2 57.6 

Mine Electricity Demand: 11.9 46.1 

Prep Plant Electricity Demand: 3.3 11.5 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.6 5.4 

Assuming 40% Recovery Efficiency: 1.2 10.9

Assuming 60% Recovery Efficiency: 1.9 16.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

No. 3 Mine

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: NA County: Pike

CORPORATE INFORMATION 

Current Owner: Excel Mining LLC 

Parent Company: Alliance Resource Partners LP Parent Company Web Site: www.arlp.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Judy Magee Phone Number: (918) 295-7635 

Mailing Address: 4126 St. Hwy. 194 W. 

City: Pikeville State: KY ZIP: 41501 

GENERAL INFORMATION 

Number of Employees at Mine: 193 Mining Method: Continuous 

Year of Initial Production: 1977 Primary Coal Use: NA 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.8% - 1.4% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,440 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.9 0.8 1.2 1.3 1.5 

Estimated Total Methane Liberated (million cf/day): 0.9 0.5 0.4 0.8 0.9 

Emission from Ventilation Systems: 0.9 0.5 0.4 0.8 0.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 364 237 139 227 217 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
No. 3 Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.7% 1.4% 2.1% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.3% 0.5% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 12.3 46.4 

Mine Electricity Demand: 9.6 37.1 

Prep Plant Electricity Demand: 2.6 9.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.7 6.1 

Assuming 40% Recovery Efficiency: 1.4 12.2

Assuming 60% Recovery Efficiency: 2.1 18.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

Pontiki No. 2

GEOGRAPHIC DATA

Basin: Central Appalachian State: KY

Coalbed: Pond Creek County: Martin

CORPORATE INFORMATION 

Current Owner: Excel Mining 

Parent Company: Alliance Resource Partners LP Parent Company Web Site: www.arlp.com 

Previous Owner(s): Pontiki Coal Co. Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: John Small Phone Number: (606) 395-5352 

Mailing Address: P.O. Box 802 

City: Lovely State: KY ZIP: 41231 

GENERAL INFORMATION 

Number of Employees at Mine: 220 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.6% - 0.73% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,900 

Depth to Seam (ft): 425 Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.8 0.6 1.2 1.8 2.0 

Estimated Total Methane Liberated (million cf/day): 0.6 0.5 0.6 0.4 0.7 

Emission from Ventilation Systems: 0.6 0.5 0.6 0.4 0.7 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 283 335 182 83 132 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Pontiki No. 2 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.0 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.4% 0.9% 1.3% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2% 0.3% 

Power Generation Potential 

Utility Electric Supplier: Kentucky Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 15.8 59.6 

Mine Electricity Demand: 12.4 47.7 

Prep Plant Electricity Demand: 3.4 11.9 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.5 4.8 

Assuming 40% Recovery Efficiency: 1.1 9.6

Assuming 60% Recovery Efficiency: 1.6 14.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: High Hills/Low Mountains 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): 2.0 Pipeline Diameter (inches): 6.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
6. Profiled Mines (continued)

 New Mexico Mines 

San Juan South 
Updated: 08/01/2005 Status: Active 

San Juan South 

GEOGRAPHIC DATA 

Basin: San Juan State: NM 

Coalbed: No 9, No. 8 County: San Juan 

CORPORATE INFORMATION 

Current Owner: San Juan Coal Co. 

Parent Company: BHP/Billiton Parent Company Web Site: www.bhpbilliton.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Scott Langley Phone Number: (505) 598-2000 

Mailing Address: P.O. Box 561 

City: Waterflow State: NM ZIP: 87421 

GENERAL INFORMATION 

Number of Employees at Mine: 280 Mining Method: Longwall 

Year of Initial Production: 1997 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.8% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 9,500 

Depth to Seam (ft): 300 - 1,000 Seam Thickness (ft): 4.2 - 14.6 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.1 0.0 0.7 1.8 5.9 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.3 2.0 3.6 

Emission from Ventilation Systems: 0.0 0.0 0.3 1.5 1.3 

Estimated Methane Drained: 0.0 0.0 0.0 0.5 2.3 

Estimated Specific Emissions (cf/ton): 0 0 166 425 223 

Methane Recovered (million cf/day): - - - - 0.1 

Estimated Current Drainage Efficiency: 65% 

Drainage System Used: Vertical Gob, Horizontal Pre-mine 
San Juan South (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.2 0.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.0% 2.0% 3.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.5% 0.7% 

Power Generation Potential 

Utility Electric Supplier: Public Service of New Mexico 

Parent Corporation of Utility: Public Service of New Mexico 

MW GWh/year 

Total Electricity Demand (2003 data): 46.7 176.7 

Mine Electricity Demand: 36.7 141.4 

Prep Plant Electricity Demand: 10.0 35.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 2.7 23.9 

Assuming 40% Recovery Efficiency: 5.5 47.8

Assuming 60% Recovery Efficiency: 8.2 71.7

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.3

Assuming 40% Recovery (Bcf): 0.5

Assuming 60% Recovery (Bcf): 0.8

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Western/Chuska 

Distance to Pipeline (miles): < 10.0 Pipeline Diameter (inches): 16.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
6. Profiled Mines (continued) 

Ohio Mines 

Powhatan No. 6 
Updated: 08/01/2005 Status: Active

Powhatan No. 6 Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: OH

Coalbed: Pittsburgh No. 8 County: Belmont

CORPORATE INFORMATION 

Current Owner: Ohio Valley Coal Co. 

Parent Company: Murray Energy Corporation Parent Company Web Site: www.ohiovalleycoal.com 

Previous Owner(s): None in last ten years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Roy A. Heidelbach, Mine Supt. Phone Number: (740) 926-1351 

Mailing Address: 56854 Pleasant Ridge 

City: Alledonia State: OH ZIP: 43902 

GENERAL INFORMATION 

Number of Employees at Mine: 415 Mining Method: Longwall/Continuous 

Year of Initial Production: 1972 Primary Coal Use: Steam 

Life Expectancy: 2018 Sulfur Content of Coal Produced: 3.8% - 4.5% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 12,600 

Depth to Seam (ft): 270 Seam Thickness (ft): 5.3 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.4 4.6 4.6 3.9 4.9 

Estimated Total Methane Liberated (million cf/day): 1.0 1.1 1.4 1.2 1.1 

Emission from Ventilation Systems: 1.0 1.1 1.4 1.2 1.1 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 84 89 114 116 84 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Powhatan No. 6 Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.3% 0.6% 0.9% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.1% 0.2% 

Power Generation Potential 

Utility Electric Supplier: The Dayton Power & Light Co. 

Parent Corporation of Utility: DPL Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 38.7 146.6 

Mine Electricity Demand: 30.4 117.3 

Prep Plant Electricity Demand: 8.3 29.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.9 7.5 

Assuming 40% Recovery Efficiency: 1.7 15.0

Assuming 60% Recovery Efficiency: 2.6 22.5

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: Hills/High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): 0.1 Pipeline Diameter (inches): 4.0 

Owner of Next Nearest Pipeline: Texas Eastern Transmission 

Distance to Next Nearest Pipeline (miles): 1.4 Pipeline Diameter (inches): 30.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
6. Profiled Mines (continued) 

Oklahoma Mines 

Pollyanna No. 8 
Updated: 08/01/2005 Status: Active 

Pollyanna No. 8 

GEOGRAPHIC DATA 

Basin: Arkoma State: OK 

Coalbed: Hartshorne County: Le Flore 

CORPORATE INFORMATION 

Current Owner: Sunrise Coal Co., LLC 

Parent Company: South Central Coal Company Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: Sunrise Coal 

MINE ADDRESS 

Contact Name: Paul Matlock Phone Number: (918) 962-9402 

Mailing Address: P. O. Box 100 

City: Spiro State: OK ZIP: 74959 

GENERAL INFORMATION 

Number of Employees at Mine: 36 Mining Method: Continuous 

Year of Initial Production: 1995 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.0% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 14,190 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.2 0.2 0.4 0.5 0.4 

Estimated Total Methane Liberated (million cf/day): 0.0 0.5 0.9 1.2 1.0 

Emission from Ventilation Systems: 0.0 0.5 0.9 1.2 1.0 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 0 787 827 945 929 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Pollyanna No. 8 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 2.8% 5.7% 8.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.7% 1.3% 2.0% 

Power Generation Potential 

Utility Electric Supplier: OGE Energy Corp 

Parent Corporation of Utility: OGE Energy Corp. 

MW GWh/year 

Total Electricity Demand (2003 data): 3.1 11.8 

Mine Electricity Demand: 2.4 9.4 

Prep Plant Electricity Demand: 0.7 2.4 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.8 6.6 

Assuming 40% Recovery Efficiency: 1.5 13.3

Assuming 60% Recovery Efficiency: 2.3 19.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Arkansas Oklahoma Gas Co. 

Distance to Pipeline (miles): 2.0 Pipeline Diameter (inches): 6.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
6. Profiled Mines (continued) 

Pennsylvania Mines 

Bailey 

Eighty-Four Mine 

Enlow Fork 

RAG Cumberland 

RAG Emerald 
Updated: 08/01/2005 Status: Active

Bailey Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: PA

Coalbed: Pittsburgh County: Greene

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Roy Pride Phone Number: (724) 663-4781 

Mailing Address: 192 Crabapple 

City: Wind Ridge State: PA ZIP: 15377 

GENERAL INFORMATION 

Number of Employees at Mine: 540 Mining Method: Longwall/Continuous 

Year of Initial Production: 1984 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.03% -2.41% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,200 

Depth to Seam (ft): 800 Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 8.5 9.9 10.3 9.7 9.4 

Estimated Total Methane Liberated (million cf/day): 8.6 7.6 6.8 7.1 5.7 

Emission from Ventilation Systems: 6.9 7.6 6.7 7.1 5.7 

Estimated Methane Drained: 1.7 0.1 0.1 0.1 0.0 

Estimated Specific Emissions (cf/ton): 371 282 241 270 223 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Bailey Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.2 0.4 0.6 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.7% 1.5% 2.2% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.3% 0.5% 

Power Generation Potential 

Utility Electric Supplier: West Penn Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 74.5 281.7 

Mine Electricity Demand: 58.4 225.4 

Prep Plant Electricity Demand: 16.0 56.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 4.3 38.1 

Assuming 40% Recovery Efficiency: 8.7 76.2

Assuming 60% Recovery Efficiency: 13.0 114.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.4

Assuming 40% Recovery (Bcf): 0.8

Assuming 60% Recovery (Bcf): 1.3

Description of Surrounding Terrain: High Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Carnegie Natural Gas 

Distance to Pipeline (miles): 6.0 Pipeline Diameter (inches): 20.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Television components, apparel, and metal manufacturing; hospitals, schools and other municipal 

buildings. 
Updated: 08/01/2005 Status: Active

Eighty-Four Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: PA

Coalbed: Pittsburgh County: Washington

CORPORATE INFORMATION 

Current Owner: Eighty-Four Mining Co. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): Beth Energy Mines Previous or Alternate Name of Mine: Ellsworth or Livingston 

MINE ADDRESS 

Contact Name: Eric Schubel Phone Number: (724) 250-1577 

Mailing Address: P.O. Box 284 

City: Eighty Four State: PA ZIP: 15330 

GENERAL INFORMATION 

Number of Employees at Mine: 499 Mining Method: Longwall/Continuous 

Year of Initial Production: NA Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.33% - 1.71% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,307 

Depth to Seam (ft): 625 Seam Thickness (ft): 7.5 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 5.8 4.2 1.6 4.0 4.0 

Estimated Total Methane Liberated (million cf/day): 6.0 6.1 4.6 4.9 5.1 

Emission from Ventilation Systems: 6.0 6.1 4.6 4.9 5.1 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 379 531 1022 445 467 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Eighty-Four Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.2 0.3 0.5 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.5% 3.0% 4.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.7% 1.1% 

Power Generation Potential 

Utility Electric Supplier: West Penn Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 31.4 118.9 

Mine Electricity Demand: 24.7 95.1 

Prep Plant Electricity Demand: 6.8 23.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 3.8 33.6 

Assuming 40% Recovery Efficiency: 7.7 67.3

Assuming 60% Recovery Efficiency: 11.5 100.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.4

Assuming 40% Recovery (Bcf): 0.7

Assuming 60% Recovery (Bcf): 1.1

Description of Surrounding Terrain: Open High Hills/High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas of Pennsylvania, Inc. 

Distance to Pipeline (miles): 6.0 Pipeline Diameter (inches): 20.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Steel, plastics, apparel, glass, fertilizers, and other types of manufacturing; municipal buildings. 
Updated: 08/01/2005 Status: Active 

Enlow Fork Mine 

GEOGRAPHIC DATA 

Basin: Northern Appalachian State: PA 

Coalbed: Pittsburgh County: Greene 

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Dave Hudson Phone Number: (724) 663-3101 

Mailing Address: Rte. 231 

City: East Finley State: PA ZIP: 15377 

GENERAL INFORMATION 

Number of Employees at Mine: 504 Mining Method: Longwall/Continuous 

Year of Initial Production: 1990 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.00% -2.41% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,000 

Depth to Seam (ft): 800 Seam Thickness (ft): 5.7 - 6.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 9.8 9.5 10.3 9.6 9.9 

Estimated Total Methane Liberated (million cf/day): 13.9 11.1 9.8 9.1 10.3 

Emission from Ventilation Systems: 11.1 11.0 9.7 9.0 10.3 

Estimated Methane Drained: 2.8 0.1 0.1 0.1 0.0 

Estimated Specific Emissions (cf/ton): 514 426 346 346 382 

Methane Recovered (million cf/day): - - - - -

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Enlow Fork Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.3 0.7 1.0 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.3% 2.5% 3.8% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.6% 0.9% 

Power Generation Potential 

Utility Electric Supplier: West Penn Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 78.4 296.7 

Mine Electricity Demand: 61.5 237.3 

Prep Plant Electricity Demand: 16.9 59.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 7.8 68.6 

Assuming 40% Recovery Efficiency: 15.7 137.2

Assuming 60% Recovery Efficiency: 23.5 205.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.8

Assuming 40% Recovery (Bcf): 1.5

Assuming 60% Recovery (Bcf): 2.3

Description of Surrounding Terrain: Open Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): 6.0 Pipeline Diameter (inches): 20.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA 

Comments: Television components, apparel, and metal manufacturing; hospitals, schools and other municipal 

buildings. 
Updated: 08/01/2005 Status: Active 

RAG Cumberland Mine 

GEOGRAPHIC DATA 

Basin: Northern Appalachian State: PA 

Coalbed: Pittsburgh No. 8 County: Greene 

CORPORATE INFORMATION 

Current Owner: RAG Cumberland Resources, LP 

Parent Company: RAG American Coal Co. Parent Company Web Site: http://www.rag-american.com/ 

Previous Owner(s): Cyprus Amax, U. S. Steel Previous or Alternate Name of Mine: Cumberland 

MINE ADDRESS 

Contact Name: Mike Misha, Pres. Phone Number: (724) 852-7781 

Mailing Address: P.O. Box 1020 

City: Waynesburg State: PA ZIP: 15370 

GENERAL INFORMATION 

Number of Employees at Mine: 574 Mining Method: Longwall/Continuous 

Year of Initial Production: 1972 Primary Coal Use: Steam 

Life Expectancy: 2023 Sulfur Content of Coal Produced: 2.4% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,000 

Depth to Seam (ft): 900 Seam Thickness (ft): 6.5 - 7.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 

Estimated Total Methane Liberated (million cf/day): 

Emission from Ventilation System

Estimated Methane Drained: 

Estimated Specific Emissions (cf/ton): 

Methane Recovered (million cf/day): 

s: 

6.6 

10.7 

9.1 

1.6 

594 

-

6.5 

17.4 

12.9 

4.5 

975 

-

6.7 

16.2 

11.7 

4.5 

888 

-

6.6 

11.1 

9.6 

1.5 

609 

-

6.2 

24.3 

9.9 

14.4 

1418 

-

Estimated Current Drainage Efficiency: 59% 

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 
RAG Cumberland Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.8 1.6 2.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 4.7% 9.4% 14.1% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.1% 2.2% 3.3% 

Power Generation Potential 

Utility Electric Supplier: West Penn Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 49.5 187.4 

Mine Electricity Demand: 38.9 149.9 

Prep Plant Electricity Demand: 10.6 37.5 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 18.4 161.0 

Assuming 40% Recovery Efficiency: 36.8 322.0

Assuming 60% Recovery Efficiency: 55.1 483.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 1.8

Assuming 40% Recovery (Bcf): 3.5

Assuming 60% Recovery (Bcf): 5.3

Description of Surrounding Terrain: High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Texas Eastern Transmission Co. 

Distance to Pipeline (miles): 0.2 Pipeline Diameter (inches): 24.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA 

Comments: Television components, apparel, and metal manufacturing; hospitals, schools and other municipal 

buildings. 
Updated: 08/01/2005 Status: Active

RAG Emerald Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: PA

Coalbed: Pittsburgh No. 8 County: Greene

CORPORATE INFORMATION 

Current Owner: RAG Emerald Resources, LP 

Parent Company: RAG American Coal Co. Parent Company Web Site: http://www.rag-american.com/ 

Previous Owner(s): Cyprus Amax Previous or Alternate Name of Mine: Emerald No. 1 

MINE ADDRESS 

Contact Name: Mike Misha, Pres. Phone Number: (724) 852-1200 

Mailing Address: 212 Mine Rd., Rte. 218 

City: Waynesburg State: PA ZIP: 15370 

GENERAL INFORMATION 

Number of Employees at Mine: 549 Mining Method: Longwall/Continuous 

Year of Initial Production: 1977 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: 2013 Sulfur Content of Coal Produced: 2.4% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,000 

Depth to Seam (ft): 650 Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.3 6.4 6.7 6.6 6.6 

Estimated Total Methane Liberated (million cf/day): 8.3 7.5 7.6 9.1 11.5 

Emission from Ventilation Systems: 5.0 5.8 5.9 6.6 7.4 

Estimated Methane Drained: 3.3 1.6 1.7 2.5 4.0 

Estimated Specific Emissions (cf/ton): 696 425 410 508 631 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 35% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
RAG Emerald Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.4 0.7 1.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 2.1% 4.2% 6.3% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.5% 1.0% 1.5% 

Power Generation Potential 

Utility Electric Supplier: West Penn Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 52.5 198.6 

Mine Electricity Demand: 41.2 158.9 

Prep Plant Electricity Demand: 11.3 39.7 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 8.7 76.0 

Assuming 40% Recovery Efficiency: 17.3 152.0

Assuming 60% Recovery Efficiency: 26.0 228.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.8

Assuming 40% Recovery (Bcf): 1.7

Assuming 60% Recovery (Bcf): 2.5

Description of Surrounding Terrain: High Hills/Open High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Texas Eastern Transmission Co. 

Distance to Pipeline (miles): 0.2 Pipeline Diameter (inches): 24.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Television components, apparel, and metal manufacturing; hospitals, schools and other municipal 

buildings. 
6. Profiled Mines (continued) 

Utah Mines 

Aberdeen 

Dugout Canyon 

West Ridge 
Updated: 08/01/2005 Status: Active 

Aberdeen 

GEOGRAPHIC DATA 

Basin: Uinta State: UT 

Coalbed: L. Sunnyside, Gilson, Aber. County: Carbon 

CORPORATE INFORMATION 

Current Owner: Andalex Resources, Inc. 

Parent Company: Andalex Resources, Inc. Parent Company Web Site: www.andalex.com 

Previous Owner(s): None Previous or Alternate Name of Mine: Tower Division 

MINE ADDRESS 

Contact Name: Garth Neilsen Phone Number: (435) 637-5385 

Mailing Address: P.O. Box 902 

City: Price State: UT ZIP: 84501 

GENERAL INFORMATION 

Number of Employees at Mine: 31 Mining Method: Longwall/Continuous 

Year of Initial Production: 1980 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: NA 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 11,991 

Depth to Seam (ft): NA Seam Thickness (ft): 6.0 - 8.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.5 1.6 0.5 0.0 0.4 

Estimated Total Methane Liberated (million cf/day): 4.4 4.4 1.2 0.8 1.2 

Emission from Ventilation Systems: 4.4 4.4 1.2 0.8 1.2 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 1037 1020 848 8484 995 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Aberdeen (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 3.6% 7.2% 10.8% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.8% 1.7% 2.5% 

Power Generation Potential 

Utility Electric Supplier: Price City Utilities, Utah Power & Light 

Parent Corporation of Utility: Pacificorp 

MW GWh/year 

Total Electricity Demand (2003 data): 3.5 13.3 

Mine Electricity Demand: 2.8 10.7 

Prep Plant Electricity Demand: 0.8 2.7 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.9 8.0 

Assuming 40% Recovery Efficiency: 1.8 16.1

Assuming 60% Recovery Efficiency: 2.8 24.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.3

Description of Surrounding Terrain: Tablelands; Open High/Low Mountains 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Questar Pipeline Company 

Distance to Pipeline (miles): ~5.0 Pipeline Diameter (inches): 20.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Carbon Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Dugout Canyon Mine

GEOGRAPHIC DATA

Basin: Central Rockies State: UT

Coalbed: Gilson, Rock Canyon County: Carbon

CORPORATE INFORMATION 

Current Owner: Canyon Fuel Co., LLC 

Parent Company: Arch Coal Co. Parent Company Web Site: www.archcoal.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: R.W. Olsen, Mine Mgr. Phone Number: (435) 636-2860 

Mailing Address: P.O. Box 1029 

City: Wellington State: UT ZIP: 84542 

GENERAL INFORMATION 

Number of Employees at Mine: 175 Mining Method: Longwall/Continuous 

Year of Initial Production: 1998 Primary Coal Use: Steam 

Life Expectancy: 2115 Sulfur Content of Coal Produced: 0.4% - 0.75% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 11,700 

Depth to Seam (ft): 1400 Seam Thickness (ft): 7.5 - 8.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.8 0.5 2.0 2.1 2.9 

Estimated Total Methane Liberated (million cf/day): 0.1 0.1 0.6 1.1 2.2 

Emission from Ventilation Systems: 0.1 0.1 0.6 1.1 2.2 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 62 103 103 195 267 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Dugout Canyon Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.1 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.0% 2.0% 3.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.5% 0.7% 

Power Generation Potential 

Utility Electric Supplier: Pacificorp 

Parent Corporation of Utility: Pacificorp 

MW GWh/year 

Total Electricity Demand (2003 data): 23.3 88.2 

Mine Electricity Demand: 18.3 70.6 

Prep Plant Electricity Demand: 5.0 17.6 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.6 14.3 

Assuming 40% Recovery Efficiency: 3.3 28.5

Assuming 60% Recovery Efficiency: 4.9 42.8

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.2

Assuming 40% Recovery (Bcf): 0.3

Assuming 60% Recovery (Bcf): 0.5

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Questar Pipeline Company 

Distance to Pipeline (miles): < 5.0 Pipeline Diameter (inches): 20.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

West Ridge Mine

GEOGRAPHIC DATA

Basin: Uinta State: UT

Coalbed: Lower Sunnyside County: Carbon

CORPORATE INFORMATION 

Current Owner: West Ridge Resources 

Parent Company: Andalex Resources, Inc. Parent Company Web Site: www.andalex.com/westridge.html 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Gary Gray Phone Number: (435) 564-4015 

Mailing Address: P.O. Box 1077 

City: Price State: UT ZIP: 84501 

GENERAL INFORMATION 

Number of Employees at Mine: 76 Mining Method: Longwall 

Year of Initial Production: 2001 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.09% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,648 

Depth to Seam (ft): 1200 Seam Thickness (ft): 8-14 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.5 2.3 2.8 3.0 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.8 2.5 3.6 

Emission from Ventilation Systems: 0.0 0.0 0.8 2.5 3.6 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - 0 120 316 443 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
West Ridge Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.2 0.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2 

 Emissions from Coal Combustion: 1.5% 3.1% 4.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.7% 1.1% 

Power Generation Potential 

Utility Electric Supplier: Pacificorp 

Parent Corporation of Utility: Pacificorp 

MW GWh/year 

Total Electricity Demand (2003 data): 23.6 89.2 

Mine Electricity Demand: 18.5 71.4 

Prep Plant Electricity Demand: 5.1 17.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 2.7 24.0 

Assuming 40% Recovery Efficiency: 5.5 47.9

Assuming 60% Recovery Efficiency: 8.2 71.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.3

Assuming 40% Recovery (Bcf): 0.5

Assuming 60% Recovery (Bcf): 0.8

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Questar Pipeline Co. 

Distance to Pipeline (miles): < 10.0 Pipeline Diameter (inches): 20.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
6. Profiled Mines (continued) 

Virginia Mines 

Buchanan 

Deep Mine #26 

Virginia Pocahontas No. 8 
Updated: 08/01/2005 Status: Active 

Buchanan Mine 

GEOGRAPHIC DATA 

Basin: Central Appalachian State: VA 

Coalbed: Pocahontas No. 3 County: Buchanan 

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: Buchanan No. 1 

MINE ADDRESS 

Contact Name: Terry Suder Phone Number: (276) 498-6900 

Mailing Address: Rte. 680 

City: Keen Mountain State: VA ZIP: 24624 

GENERAL INFORMATION 

Number of Employees at Mine: 392 Mining Method: Longwall/Continuous 

Year of Initial Production: 1983 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.73% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,831 

Depth to Seam (ft): NA Seam Thickness (ft): 5.4 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.7 4.5 4.5 4.1 4.7 

Estimated Total Methane Liberated (million cf/day): 19.5 21.6 17.9 48.2 42.6 

Emission from Ventilation Systems: 12.3 11.8 10.3 9.5 7.3 

Estimated Methane Drained: 7.2 9.8 7.5 38.7 35.3 

Estimated Specific Emissions (cf/ton): 1520 1766 1463 4330 3318

Methane Recovered (million cf/day): 7.0 9.8 7.5 38.8 36.4

Estimated Current Drainage Efficiency: 83%

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Buchanan Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 1.4 2.8 4.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 10.3% 20.7% 31.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 2.4% 4.8% 7.2% 

Power Generation Potential 

Utility Electric Supplier: Appalachian Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 37.2 140.6 

Mine Electricity Demand: 29.2 112.5 

Prep Plant Electricity Demand: 8.0 28.1 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 32.3 282.7 

Assuming 40% Recovery Efficiency: 64.5 565.4

Assuming 60% Recovery Efficiency: 96.8 848.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 3.1

Assuming 40% Recovery (Bcf): 6.2

Assuming 60% Recovery (Bcf): 9.3

Description of Surrounding Terrain: Open Low Mountains/Low Mountains 

Transmission Pipeline in County? No 

Owner of Nearest Pipeline: Mine owns pipeline that connects to dist. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG) 

Distance to Next Nearest Pipeline (miles): 1.0 Pipeline Diameter (inches): 8.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Deep Mine #26

GEOGRAPHIC DATA

Basin: Central Appalachian State: VA

Coalbed: Norton, Upper Banner County: Wise

CORPORATE INFORMATION 

Current Owner: Paramount Coal Corp. 

Parent Company: Alpha Natural Resources LLC Parent Company Web Site: www.alphanr.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: Virginia Commonwealth 5 

MINE ADDRESS 

Contact Name: Robert Hutton Phone Number: (276) 619-4476 

Mailing Address: 179 E. Jackson St. 

City: Gate City State: VA ZIP: 24251 

GENERAL INFORMATION 

Number of Employees at Mine: 133 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.75% - 0.87% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,620 

Depth to Seam (ft): NA Seam Thickness (ft): 4-7 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.0 0.0 0.3 1.1 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.0 0.5 1.9 

Emission from Ventilation Systems: 0.0 0.0 0.0 0.5 1.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - - - 629 619 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Deep Mine #26 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.1 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 2.0% 3.9% 5.9% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.5% 0.9% 1.4% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 8.9 33.8 

Mine Electricity Demand: 7.0 27.0 

Prep Plant Electricity Demand: 1.9 6.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.4 12.7 

Assuming 40% Recovery Efficiency: 2.9 25.4

Assuming 60% Recovery Efficiency: 4.3 38.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.3

Assuming 60% Recovery (Bcf): 0.4

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active 

Virginia Pocahontas No. 8 

GEOGRAPHIC DATA 

Basin: Central Appalachian State: VA 

Coalbed: Pocahontas No. 3 County: Buchanan 

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 5 years Previous or Alternate Name of Mine: VP No. 8 

MINE ADDRESS 

Contact Name: Neil Made Phone Number: (276) 498-7800 

Mailing Address: Rte. 624 

City: Rowe State: VA ZIP: 24646 

GENERAL INFORMATION 

Number of Employees at Mine: NA Mining Method: Longwall/Continuous 

Year of Initial Production: 1994 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.75% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 14,013 

Depth to Seam (ft): 2050 Seam Thickness (ft): 5.0 -5.1 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 

Estimated Total Methane Liberated (million cf/day): 

Emission from Ventilation System

Estimated Methane Drained: 

Estimated Specific Emissions (cf/ton): 

Methane Recovered (million cf/day): 

s: 

1.4 

53.7 

6.2 

47.5 

14489 

46.3 

2.3 

59.8 

7.9 

51.8 

9651 

51.5 

2.3 

70.6 

7.3 

63.3 

11063 

63.0 

2.2 

43.0 

8.5 

34.6 

7225 

34.5 

1.9 

46.3 

7.9 

38.4 

8992 

39.5 

Estimated Current Drainage Efficiency: 83% 

Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine 
Virginia Pocahontas No. 8 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 1.5 3.0 4.5 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 27.7% 55.3% 83.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 6.4% 12.8% 19.2% 

Power Generation Potential 

Utility Electric Supplier: Appalachian Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 14.9 56.4 

Mine Electricity Demand: 11.7 45.1 

Prep Plant Electricity Demand: 3.2 11.3 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 35.1 307.3 

Assuming 40% Recovery Efficiency: 70.2 614.7

Assuming 60% Recovery Efficiency: 105.2 922.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 3.4

Assuming 40% Recovery (Bcf): 6.8

Assuming 60% Recovery (Bcf): 10.1

Description of Surrounding Terrain: Open Low Mountains/Low Mountains 

Transmission Pipeline in County? No 

Owner of Nearest Pipeline: Mine owns pipeline that connects to dist. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG) 

Distance to Next Nearest Pipeline (miles): 1.0 Pipeline Diameter (inches): 6.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
6. Profiled Mines (continued) 

West Virginia Mines 

American Eagle 

Beckley Crystal 

Blacksville No. 2 

Eagle 

Justice #1 

McElroy 

Sentinel 

Shoemaker 

Upper Big Branch - South 

Whitetail Kittanning 

Dakota No. 2 

Federal No. 2 

Loveridge No. 22 

Pinnacle No. 50 

Robinson Run No. 95 
Updated: 08/01/2005 Status: Active 

American Eagle Mine 

GEOGRAPHIC DATA 

Basin: Central Appalachian State: WV 

Coalbed: Eagle, Big Eagle County: Kanawha 

CORPORATE INFORMATION 

Current Owner: Speed Mining, Inc. 

Parent Company: Timothy G. Elliott Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Scott Pettry Phone Number: (304) 461-3050 

Mailing Address: 325 Harper Park Dr. 

City: Beckley State: WV ZIP: 25801 

GENERAL INFORMATION 

Number of Employees at Mine: 132 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: <1.5% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,500 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.2 0.0 0.9 3.3 4.1 

Estimated Total Methane Liberated (million cf/day): 0.3 0.0 0.5 2.5 4.9 

Emission from Ventilation Systems: 0.3 0.0 0.5 2.5 4.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 534 - 199 282 435 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
American Eagle Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.2 0.3 0.5 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.4% 2.8% 4.1% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.6% 1.0% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 32.7 123.8 

Mine Electricity Demand: 25.7 99.1 

Prep Plant Electricity Demand: 7.0 24.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 3.7 32.7 

Assuming 40% Recovery Efficiency: 7.5 65.3

Assuming 60% Recovery Efficiency: 11.2 98.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.4

Assuming 40% Recovery (Bcf): 0.7

Assuming 60% Recovery (Bcf): 1.1

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active 

Beckley Crystal 

GEOGRAPHIC DATA 

Basin: Central Appalachian State: WV 

Coalbed: NA County: Raleigh 

CORPORATE INFORMATION 

Current Owner: Baylor Mining, Inc. 

Parent Company: Robert L. Worley Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Sam Hatcher Phone Number: (304) 732-6422 

Mailing Address: P.O. Box 577 

City: Mabscott State: WV ZIP: 25871 

GENERAL INFORMATION 

Number of Employees at Mine: 55 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: NA 

Life Expectancy: NA Sulfur Content of Coal Produced: <1.5% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,000 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.0 0.2 0.6 0.5 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.7 1.0 2.3 

Emission from Ventilation Systems: 0.0 0.0 0.7 1.0 2.3 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - - 1169 646 1809 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Beckley Crystal (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.2 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 6.5% 12.9% 19.4% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.5% 3.0% 4.5% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 3.8 14.2 

Mine Electricity Demand: 3.0 11.4 

Prep Plant Electricity Demand: 0.8 2.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.8 15.6 

Assuming 40% Recovery Efficiency: 3.6 31.2

Assuming 60% Recovery Efficiency: 5.3 46.8

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.2

Assuming 40% Recovery (Bcf): 0.3

Assuming 60% Recovery (Bcf): 0.5

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active 

Blacksville No. 2 

GEOGRAPHIC DATA 

Basin: Northern Appalachian State: WV 

Coalbed: Pittsburgh No. 8 County: Monongalia 

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Byron Payne Phone Number: (304) 662-6128 

Mailing Address: P.O. Box 24 

City: Wana State: WV ZIP: 26590 

GENERAL INFORMATION 

Number of Employees at Mine: 479 Mining Method: Longwall/Continuous 

Year of Initial Production: 1971 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.97% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,419 

Depth to Seam (ft): 1375 Seam Thickness (ft): 6.5 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.6 5.2 5.0 4.8 5.4 

Estimated Total Methane Liberated (million cf/day): 11.1 11.9 9.1 8.2 8.5 

Emission from Ventilation Systems: 6.7 7.1 6.7 5.7 4.7 

Estimated Methane Drained: 4.4 4.8 2.4 2.4 3.8 

Estimated Specific Emissions (cf/ton): 873 843 658 619 571 

Methane Recovered (million cf/day): 3.4 1.1 2.1 3.3 3.3 

Estimated Current Drainage Efficiency: 45% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
Blacksville No. 2 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.3 0.6 0.8 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.8% 3.6% 5.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.9% 1.3% 

Power Generation Potential 

Utility Electric Supplier: Monongahela Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 43.2 163.5 

Mine Electricity Demand: 33.9 130.8 

Prep Plant Electricity Demand: 9.3 32.7 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 6.5 56.5 

Assuming 40% Recovery Efficiency: 12.9 113.1

Assuming 60% Recovery Efficiency: 19.4 169.6

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.6

Assuming 40% Recovery (Bcf): 1.2

Assuming 60% Recovery (Bcf): 1.9

Description of Surrounding Terrain: Open Low Mountains/High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG) 

Distance to Pipeline (miles): 0.4 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Pharmaceuticals, chemicals, apparel, and glass manufacturing; hospitals, university, and other 

municipal buildings. 
Updated: 08/01/2005 Status: Active 

Dakota No. 2 

GEOGRAPHIC DATA 

Basin: Central Appalachian State: WV 

Coalbed: Pittsburgh No. 8 County: Boone 

CORPORATE INFORMATION 

Current Owner: Dakota Mining, Inc. 

Parent Company: Rainbow Trout Coal LLC Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Amanda Lawson Phone Number: (304) 461-3049 

Mailing Address: 430 Harper Park, Ste. A 

City: Beckley State: WV ZIP: 25801 

GENERAL INFORMATION 

Number of Employees at Mine: 165 Mining Method: Continuous 

Year of Initial Production: 1996 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: <1.5% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,500 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.6 1.6 1.2 1.5 1.5 

Estimated Total Methane Liberated (million cf/day): 0.5 0.5 0.4 1.0 1.5 

Emission from Ventilation Systems: 0.5 0.5 0.4 1.0 1.5 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 119 107 129 235 366 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Dakota No. 2 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.2% 2.3% 3.5% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.5% 0.8% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 11.7 44.2 

Mine Electricity Demand: 9.2 35.4 

Prep Plant Electricity Demand: 2.5 8.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.1 9.8 

Assuming 40% Recovery Efficiency: 2.2 19.6

Assuming 60% Recovery Efficiency: 3.4 29.5

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.3

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active 

Eagle Mine 

GEOGRAPHIC DATA 

Basin: Central Appalachian State: WV 

Coalbed: Eagle, Big Eagle County: Kanawha 

CORPORATE INFORMATION 

Current Owner: Newtown Energy, Inc. 

Parent Company: James O. Bunn; Frank D. Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: John Dunlap Phone Number: (304) 837-8587 

Mailing Address: 13905 McCorkle Ave, 

City: Chesapeake State: WV ZIP: 25315 

GENERAL INFORMATION 

Number of Employees at Mine: 143 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: NA 

Life Expectancy: NA Sulfur Content of Coal Produced: <1.5% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,500 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.5 1.5 1.2 1.5 

Estimated Total Methane Liberated (million cf/day): 0.0 0.0 0.4 0.8 1.0 

Emission from Ventilation Systems: 0.0 0.0 0.4 0.8 1.0 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - 0 96 263 240 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Eagle Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.8% 1.5% 2.3% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.4% 0.5% 

Power Generation Potential 

Utility Electric Supplier: 

Parent Corporation of Utility: 

MW GWh/year 

Total Electricity Demand (2003 data): 11.7 44.2 

Mine Electricity Demand: 9.2 35.4 

Prep Plant Electricity Demand: 2.5 8.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.7 6.4 

Assuming 40% Recovery Efficiency: 1.5 12.9

Assuming 60% Recovery Efficiency: 2.2 19.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: 

Transmission Pipeline in County? 

Owner of Nearest Pipeline: 

Distance to Pipeline (miles): Pipeline Diameter (inches): 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

Federal No. 2

GEOGRAPHIC DATA

Basin: Northern Appalachian State: WV

Coalbed: Pittsburgh County: Monongalia

CORPORATE INFORMATION 

Current Owner: Peabody Energy/Federal 

Parent Company: Peabody Energy Corp. Parent Company Web Site: www.peabodyenergy.com 

Previous Owner(s): Eastern Associated Coal Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: John Kucish, Mine Mgr. Phone Number: (304) 449-1911 

Mailing Address: 1044 Miracle Run Rd. 

City: Fairview State: WV ZIP: 26570 

GENERAL INFORMATION 

Number of Employees at Mine: 425 Mining Method: Longwall/Continuous 

Year of Initial Production: 1968 Primary Coal Use: Steam 

Life Expectancy: 2011 Sulfur Content of Coal Produced: 2.0% - 3.2% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,330 

Depth to Seam (ft): 800 - 1250 Seam Thickness (ft): 7.0 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.6 4.3 4.9 5.0 4.4 

Estimated Total Methane Liberated (million cf/day): 15.3 12.8 17.9 12.0 8.7 

Emission from Ventilation Systems: 9.1 7.7 10.7 10.6 7.6 

Estimated Methane Drained: 6.1 5.1 7.1 1.4 1.1 

Estimated Specific Emissions (cf/ton): 1198 1096 1336 876 725 

Methane Recovered (million cf/day): 0.2 1.0 1.0 0.4 0.8 

Estimated Current Drainage Efficiency: 13% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
Federal No. 2 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.3 0.6 0.9 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 2.3% 4.7% 7.0% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.5% 1.1% 1.6% 

Power Generation Potential 

Utility Electric Supplier: Monongahela Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 34.9 131.9 

Mine Electricity Demand: 27.4 105.5 

Prep Plant Electricity Demand: 7.5 26.4 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 6.6 58.0 

Assuming 40% Recovery Efficiency: 13.2 116.0

Assuming 60% Recovery Efficiency: 19.9 174.0

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.6

Assuming 40% Recovery (Bcf): 1.3

Assuming 60% Recovery (Bcf): 1.9

Description of Surrounding Terrain: Open Low Mountains/High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG) 

Distance to Pipeline (miles): 0.9 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Pharmaceuticals, chemicals, apparel, and glass manufacturing; hospitals, university, and other 

municipal buildings. 
Updated: 08/01/2005 Status: Active

Justice #1

GEOGRAPHIC DATA

Basin: Northern Appalachian State: WV

Coalbed: Powellton, Buffalo Crk County: Boone

CORPORATE INFORMATION 

Current Owner: Independence Coal Co., Inc. 

Parent Company: Massey Energy Co. Parent Company Web Site: www.masseyenergyco.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Dwayne Francisco, Pres. Phone Number: (304) 369-7103 

Mailing Address: HC 78, Box 1800 

City: Madison State: WV ZIP: 25130 

GENERAL INFORMATION 

Number of Employees at Mine: 117 Mining Method: Longwall/Continuous 

Year of Initial Production: NA Primary Coal Use: Steam, Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: <1.5% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,500 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.8 3.0 3.4 2.6 1.8 

Estimated Total Methane Liberated (million cf/day): 1.4 2.0 2.5 3.3 2.8 

Emission from Ventilation Systems: 1.4 2.0 2.5 3.3 2.8 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 283 245 275 460 565 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Justice #1 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.2 0.3 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.8% 3.6% 5.4% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.8% 1.3% 

Power Generation Potential 

Utility Electric Supplier: Appalachian Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 14.4 54.6 

Mine Electricity Demand: 11.3 43.7 

Prep Plant Electricity Demand: 3.1 10.9 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 2.1 18.7 

Assuming 40% Recovery Efficiency: 4.3 37.4

Assuming 60% Recovery Efficiency: 6.4 56.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.2

Assuming 40% Recovery (Bcf): 0.4

Assuming 60% Recovery (Bcf): 0.6

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): < 1.0 Pipeline Diameter (inches): 8.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active 

Loveridge No. 22 

GEOGRAPHIC DATA 

Basin: Northern Appalachian State: WV 

Coalbed: Pittsburgh County: Marion 

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: John Higgins Phone Number: (304) 285-2223 

Mailing Address: P.O. Box 40 

City: Fairview State: WV ZIP: 26570 

GENERAL INFORMATION 

Number of Employees at Mine: 184 Mining Method: Longwall/Continuous 

Year of Initial Production: 1953 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 2.69% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,175 

Depth to Seam (ft): 1250 Seam Thickness (ft): 7.8 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 1.1 0.0 1.1 0.0 0.3 

Estimated Total Methane Liberated (million cf/day): 0.0 2.7 5.8 3.3 5.3 

Emission from Ventilation Systems: 0.0 2.7 3.5 2.0 0.9 

Estimated Methane Drained: 0.0 0.1 2.3 1.3 4.4 

Estimated Specific Emissions (cf/ton): 0 - 1835 - 6402 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 82% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
Loveridge No. 22 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.2 0.3 0.5 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 20.9% 41.7% 62.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 4.9% 9.7% 14.6% 

Power Generation Potential 

Utility Electric Supplier: Monongahela Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 2.4 9.1 

Mine Electricity Demand: 1.9 7.3 

Prep Plant Electricity Demand: 0.5 1.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 4.0 35.4 

Assuming 40% Recovery Efficiency: 8.1 70.9

Assuming 60% Recovery Efficiency: 12.1 106.3

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.4

Assuming 40% Recovery (Bcf): 0.8

Assuming 60% Recovery (Bcf): 1.2

Description of Surrounding Terrain: Open Low Mountains/High Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG) 

Distance to Pipeline (miles): 0.9 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: Kentucky West Virginia Gas Company 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): 6" 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Lighting products, temperature control equipment, hospital and other municipal buildings. 
Updated: 08/01/2005 Status: Active

Mc Elroy Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: WV

Coalbed: Pittsburgh County: Marshall

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): Consolidation Coal Co. Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Dave Eraskovich, Supt. Phone Number: (304) 843-3700 

Mailing Address: Rd. 1 

City: Glen Easton State: WV ZIP: 26039 

GENERAL INFORMATION 

Number of Employees at Mine: 568 Mining Method: Longwall/Continuous 

Year of Initial Production: 1968 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 3.98% -4.42% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 12,300 

Depth to Seam (ft): 600 - 1200 Seam Thickness (ft): 5.0 - 5.4 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 7.0 6.8 6.6 4.8 6.8 

Estimated Total Methane Liberated (million cf/day): 8.0 6.4 6.9 7.4 1.6 

Emission from Ventilation Systems: 6.8 6.4 6.9 7.4 1.6 

Estimated Methane Drained: 1.2 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 417 345 382 565 88 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Mc Elroy Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.1 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.3% 0.6% 0.9% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.1% 0.2% 

Power Generation Potential 

Utility Electric Supplier: Wheeling Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 53.8 203.8 

Mine Electricity Demand: 42.3 163.0 

Prep Plant Electricity Demand: 11.6 40.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.2 10.9 

Assuming 40% Recovery Efficiency: 2.5 21.8 

Assuming 60% Recovery Efficiency: 3.7 32.7 

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.2

Assuming 60% Recovery (Bcf): 0.4

Description of Surrounding Terrain: High Hills/Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Ohio Power Kammer Plant Distance to Plant (miles): 10.0 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Pinnacle No. 50

GEOGRAPHIC DATA

Basin: Central Appalachian State: WV

Coalbed: Pocahontas No. 3 County: Wyoming

CORPORATE INFORMATION 

Current Owner: U.S. Steel Mining Co., L.L.C. 

Parent Company: USX Corp. Parent Company Web Site: www.uss.com/ussteel/index.html 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: Gary No. 50, U.S. Steel No. 

MINE ADDRESS 

Contact Name: Jack Shroder, GM Pinnacle Phone Number: (304) 732-5200 

Mailing Address: C/O U.S. Steel Mining, 

City: Pineville State: WV ZIP: 24824 

GENERAL INFORMATION 

Number of Employees at Mine: 540 Mining Method: Longwall/Continuous 

Year of Initial Production: 1969 Primary Coal Use: Metallurgical 

Life Expectancy: NA Sulfur Content of Coal Produced: 0.75% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 14,900 

Depth to Seam (ft): NA Seam Thickness (ft): 4.2 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 3.9 3.7 3.1 3.5 2.5 

Estimated Total Methane Liberated (million cf/day): 18.4 16.0 14.8 15.8 14.0 

Emission from Ventilation Systems: 14.8 11.0 7.7 8.0 9.8 

Estimated Methane Drained: 3.7 5.0 7.1 7.8 4.2 

Estimated Specific Emissions (cf/ton): 1735 1594 1721 1636 2064

Methane Recovered (million cf/day): 2.3 3.5 5.6 5.6 1.5

Estimated Current Drainage Efficiency: 30%

Drainage System Used: Directional Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Pinnacle No. 50 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.5 0.9 1.4 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 5.9% 11.9% 17.8% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.4% 2.8% 4.2% 

Power Generation Potential 

Utility Electric Supplier: Appalachian Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 19.6 74.1 

Mine Electricity Demand: 15.4 59.3 

Prep Plant Electricity Demand: 4.2 14.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 10.6 92.7 

Assuming 40% Recovery Efficiency: 21.2 185.4

Assuming 60% Recovery Efficiency: 31.7 278.1

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 1.0

Assuming 40% Recovery (Bcf): 2.0

Assuming 60% Recovery (Bcf): 3.1

Description of Surrounding Terrain: Low Mountains 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Mine owns pipeline that connects to trans. line 

Distance to Pipeline (miles): 0.0 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: Cabot 

Distance to Next Nearest Pipeline (miles): 0.5 Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Mining equipment manufacturing, quarries, municipal buildings. 
Updated: 08/01/2005 Status: Active

Robinson Run No. 95

GEOGRAPHIC DATA

Basin: Northern Appalachian State: WV

Coalbed: Pittsburgh County: Harrison

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: No. 95 

MINE ADDRESS 

Contact Name: Jimmy Brock Phone Number: (304) 795-4421 

Mailing Address: Rte. 2, P.O. Box 152 

City: Mannington State: WV ZIP: 26582 

GENERAL INFORMATION 

Number of Employees at Mine: NA Mining Method: Longwall/Continuous 

Year of Initial Production: 1968 Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 2.95% - 3.14% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,100 

Depth to Seam (ft): 700 Seam Thickness (ft): 6.5 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 5.3 6.0 4.9 5.0 5.7 

Estimated Total Methane Liberated (million cf/day): 6.9 5.1 5.0 5.6 4.9 

Emission from Ventilation Systems: 4.1 4.1 4.0 4.5 4.0 

Estimated Methane Drained: 2.8 1.0 1.0 1.1 1.0 

Estimated Specific Emissions (cf/ton): 474 308 375 410 314 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 20% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
Robinson Run No. 95 (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.2 0.3 0.5 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.0% 2.1% 3.1% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.5% 0.7% 

Power Generation Potential 

Utility Electric Supplier: Monongahela Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 45.5 172.2 

Mine Electricity Demand: 35.7 137.7 

Prep Plant Electricity Demand: 9.8 34.4 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 3.7 32.8 

Assuming 40% Recovery Efficiency: 7.5 65.6

Assuming 60% Recovery Efficiency: 11.2 98.4

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.4

Assuming 40% Recovery (Bcf): 0.7

Assuming 60% Recovery (Bcf): 1.1

Description of Surrounding Terrain: Open Low Mountains 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Equitable Gas 

Distance to Pipeline (miles): 0.2 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: Consolidated Gas Supply 

Distance to Next Nearest Pipeline (miles): 3.0 Pipeline Diameter (inches): 12.0 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Harrison Distance to Plant (miles): 3.0 

Comments: Aircraft, glass, and casket manufacturing; FBI facility, shopping malls, and municipal buildings. 
Updated: 08/01/2005 Status: Active

Sentinel Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: WV

Coalbed: Kittanning County: Barbour

CORPORATE INFORMATION 

Current Owner: Anker West Virginia Mining Co. 

Parent Company: Anker Energy Corp. Parent Company Web Site: NA 

Previous Owner(s): NA Previous or Alternate Name of Mine: Ryanstone #1 

MINE ADDRESS 

Contact Name: Robby Mundy Phone Number: (304) 457-1895 

Mailing Address: Rte. 3, Box 146 

City: Philippi State: WV ZIP: 26416 

GENERAL INFORMATION 

Number of Employees at Mine: 182 Mining Method: Continuous 

Year of Initial Production: 1974 Primary Coal Use: Steam, Metallurgical 

Life Expectancy: 2013 Sulfur Content of Coal Produced: 0.96% - 1.34% 

Prep Plant Located on Site? Yes BTUs/lb of Coal Produced: 13,234 

Depth to Seam (ft): 425 Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.9 0.5 0.4 0.3 0.3 

Estimated Total Methane Liberated (million cf/day): 1.7 1.6 1.4 0.9 0.9 

Emission from Ventilation Systems: 1.7 1.6 1.4 0.9 0.9 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 689 1177 1208 1087 1114 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Sentinel Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.0 0.1 0.1 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 3.6% 7.2% 10.8% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.8% 1.7% 2.5% 

Power Generation Potential 

Utility Electric Supplier: Philippi Municipal Electric 

Parent Corporation of Utility: Municipal Owned 

MW GWh/year 

Total Electricity Demand (2003 data): 2.3 8.8 

Mine Electricity Demand: 1.8 7.1 

Prep Plant Electricity Demand: 0.5 1.8 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 0.7 6.0 

Assuming 40% Recovery Efficiency: 1.4 11.9

Assuming 60% Recovery Efficiency: 2.0 17.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.1

Assuming 60% Recovery (Bcf): 0.2

Description of Surrounding Terrain: Open Low Mountains 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Hope Gas 

Distance to Pipeline (miles): 0.5 Pipeline Diameter (inches): NA 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active 

Shoemaker Mine 

GEOGRAPHIC DATA 

Basin: Northern Appalachian State: WV 

Coalbed: Pittsburgh County: Ohio 

CORPORATE INFORMATION 

Current Owner: Consol Energy Inc. 

Parent Company: CONSOL Energy Parent Company Web Site: www.consolenergy.com 

Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Rock Harris Phone Number: (304) 238-1500 

Mailing Address: Rd. 1 Box 62 A 

City: Dallas State: WV ZIP: 26036 

GENERAL INFORMATION 

Number of Employees at Mine: 376 Mining Method: Longwall/Continuous 

Year of Initial Production: NA Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 3.3% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,172 

Depth to Seam (ft): 650 Seam Thickness (ft): 5.0 - 5.5 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 4.4 3.6 4.1 3.4 3.8 

Estimated Total Methane Liberated (million cf/day): 5.2 4.3 4.2 3.4 2.2 

Emission from Ventilation Systems: 4.4 3.6 3.5 2.9 1.8 

Estimated Methane Drained: 0.8 0.6 0.6 0.5 0.3 

Estimated Specific Emissions (cf/ton): 428 435 372 371 206 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 15% 

Drainage System Used: Vertical Gob, Horizontal Pre-Mine 
Shoemaker Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.1 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.7% 1.5% 2.2% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.3% 0.5% 

Power Generation Potential 

Utility Electric Supplier: Wheeling Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 30.5 115.3 

Mine Electricity Demand: 23.9 92.2 

Prep Plant Electricity Demand: 6.6 23.1 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.6 14.4 

Assuming 40% Recovery Efficiency: 3.3 28.8

Assuming 60% Recovery Efficiency: 4.9 43.2

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.2

Assuming 40% Recovery (Bcf): 0.3

Assuming 60% Recovery (Bcf): 0.5

Description of Surrounding Terrain: High Hills/Hills 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): 0.2 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: NA 

Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter (inches): NA 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA 

Comments: Not yet researched. 
Updated: 08/01/2005 Status: Active

Upper Big Branch - South

GEOGRAPHIC DATA

Basin: Central Appalachian State: WV

Coalbed: Eagle, Powellton County: Raleigh

CORPORATE INFORMATION 

Current Owner: Performance Coal Co. 

Parent Company: Massey Energy Co. Parent Company Web Site: www.masseyenergyco.com 

Previous Owner(s): NA Previous or Alternate Name of Mine: None 

MINE ADDRESS 

Contact Name: Homer Wallace Phone Number: (304) 854-1761 

Mailing Address: P.O. Box 

City: Naoma State: WV ZIP: 25140 

GENERAL INFORMATION 

Number of Employees at Mine: 216 Mining Method: Longwall/Continuous 

Year of Initial Production: NA Primary Coal Use: Metallurgical 

Life Expectancy: 2018 Sulfur Content of Coal Produced: <1.5% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 12,000 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 5.1 4.0 2.9 3.4 3.3 

Estimated Total Methane Liberated (million cf/day): 1.0 1.2 1.0 1.5 3.1 

Emission from Ventilation Systems: 1.0 1.2 1.0 1.5 3.1 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): 70 108 125 164 347 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Upper Big Branch - South (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.2 0.3 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 1.2% 2.5% 3.7% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.6% 0.9% 

Power Generation Potential 

Utility Electric Supplier: Appalachian Power Co. 

Parent Corporation of Utility: American Electric Power Co., Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 25.9 98.1 

Mine Electricity Demand: 20.4 78.5 

Prep Plant Electricity Demand: 5.6 19.6 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 2.4 20.6 

Assuming 40% Recovery Efficiency: 4.7 41.3

Assuming 60% Recovery Efficiency: 7.1 61.9

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.2

Assuming 40% Recovery (Bcf): 0.5

Assuming 60% Recovery (Bcf): 0.7

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): < 3.0 Pipeline Diameter (inches): 8.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
Updated: 08/01/2005 Status: Active

Whitetail Kittanning Mine

GEOGRAPHIC DATA

Basin: Northern Appalachian State: WV

Coalbed: Kittanning County: Preston

CORPORATE INFORMATION 

Current Owner: Coastal Coal Co., LLC 

Parent Company: El Paso Corporation Parent Company Web Site: www.elpaso.com 

Previous Owner(s): Kingwood Coal Co. Previous or Alternate Name of Mine: NA 

MINE ADDRESS 

Contact Name: Richard L. Craig Phone Number: (304) 568-2460 

Mailing Address: Rte. 1, Box 249C 

City: Newburg State: WV ZIP: 26410 

GENERAL INFORMATION 

Number of Employees at Mine: 209 Mining Method: Continuous 

Year of Initial Production: NA Primary Coal Use: Steam 

Life Expectancy: NA Sulfur Content of Coal Produced: 1.5% - 1.7% 

Prep Plant Located on Site? No BTUs/lb of Coal Produced: 13,150 

Depth to Seam (ft): NA Seam Thickness (ft): NA 

PRODUCTION, VENTILATION AND DRAINAGE DATA 

1999 2000 2001 2002 2003 

Coal Production (million short tons/year): 0.0 0.3 2.4 2.4 2.4 

Estimated Total Methane Liberated (million cf/day): 0.0 0.1 0.9 1.7 1.7 

Emission from Ventilation Systems: 0.0 0.1 0.9 1.7 1.7 

Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0 

Estimated Specific Emissions (cf/ton): - 158 142 256 265 

Methane Recovered (million cf/day): - - - - ­

Estimated Current Drainage Efficiency: 0% 

Drainage System Used: None 
Whitetail Kittanning Mine (continued) 

ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS 

Assumed Potential Recovery Efficiency 

(Based on 2003 Data) 20% 40% 60% 

CO2 Equivalent of CH4 Emissions Reductions (mm tons): 0.1 0.1 0.2 

CO2 Equivalent of CH4 Emissions Reductions/CO2

 Emissions from Coal Combustion: 0.9% 1.7% 2.6% 

BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.4% 0.6% 

Power Generation Potential 

Utility Electric Supplier: Monongahela Power Co. 

Parent Corporation of Utility: Allegheny Power Systems, Inc. 

MW GWh/year 

Total Electricity Demand (2003 data): 18.8 71.1 

Mine Electricity Demand: 14.7 56.8 

Prep Plant Electricity Demand: 4.0 14.2 

Potential Generating Capacity (2003 data) 

Assuming 20% Recovery Efficiency: 1.3 11.4 

Assuming 40% Recovery Efficiency: 2.6 22.8

Assuming 60% Recovery Efficiency: 3.9 34.2

Pipeline Sales Potential 

Potential Annual Gas Sales (2003 data) Bcf

Assuming 20% Recovery (Bcf): 0.1

Assuming 40% Recovery (Bcf): 0.3

Assuming 60% Recovery (Bcf): 0.4

Description of Surrounding Terrain: 

Transmission Pipeline in County? Yes 

Owner of Nearest Pipeline: Columbia Gas Transmission Co. 

Distance to Pipeline (miles): ~10.0 Pipeline Diameter (inches): 10.0 

Owner of Next Nearest Pipeline: 

Distance to Next Nearest Pipeline (miles): Pipeline Diameter (inches): 

Other Utilization Possibilities 

Name of Nearby Coal Fired Power Plant: Distance to Plant (miles): 

Comments: 
7. References 

CONSOL. 1997. Notes taken by L.B. Pollard of ICF during field trip to CONSOL's VP and Buchanan Mines, 

as part of the U.S. Mine Ventilation Symposium , May 16-18, 1997. 

Electric Power, 2002. North American Electric Power Atlas, 2001 Edition, Platts, a Division of the McGraw-Hill 

Companies. 2002. 

EIA (Energy Information Administration) 1992. Analysis of the Relationship Between the Heat and Carbon 

Content of U.S. Coals. Final Task Report. September 1992. 

EIA (Energy Information Administration) 2003. Coal Production Data Files (2003) 

http://www.eia.doe.gov/cneaf/coal/page/database.html 

ICF Resources. 1990a. Opportunities for Power Generation from Methane Recovered During Coal Mining. 

Revised Draft Report Prepared by ICF Resources Incorporated for U.S. Environmental Protection 

Agency, Office of Air and Radiation. 

ICF Resources. 1990b. The Potential for Recovery of Methane from Coal Mining for Use in the U.S. Natural 

Gas System. Prepared by ICF Resources Incorporated for U.S. Environmental Protection Agency, 

Office of Air and Radiation. 

IPCC (Intergovernmental Panel on Climate Change) 1997. Revised 1996 IPCC Guidelines for National 

Greenhouse Gas Inventories. Japan. 1997 

Keystone. 1997-2004. Keystone Coal Industry Manual. Years 1997, 1998, 1999, 2000, 2001, and 2004. 

Chicago, Illinois: MacLean Hunter Publishing Co. 

Kim, J., and Mutmansky, J.M. 1990. Comparative Analysis of Ventilation Systems for a Large-Scale 

Longwall Mining Operation in Coal Seams with High Methane Content. Min. Res. Eng., 1990, v. 3, no. 

2, p. 99-117. 

Lewin, J.L., 1995. Energy and environmental policy options to promote coalbed methane. Proceedings of the 

International Unconventional Gas Symposium, Tuscaloosa, Alabama, May 995, p. 497-507. 

Lewin, J.L., 1997. Memorandum from Jeff L. Lewin to Roger Fernandez on July 14, 1997. 

Northwest Fuel. 1997. Oral communication between Peet Soot and Carol J. Bibler of Raven Ridge 

Resources, Incorporated, July 1997. 

MSHA. 2004. Mine Safety and Health Administration listing of ventilation emissions from coal mines for 

1997 - 2003, provided to the U.S. EPA via Raven Ridge Resources, Incorporated. 

USBM (U.S. Bureau of Mines). 1992. Personal Communication between Chrissy Mikes, ICF and Pat 

Diamond, U.S. Bureau of Mines Pittsburgh Research Center. 

USDOE (U.S. Department of Energy), 2000, http://www.netl.doe.gov/ Fossil Energy Techline, September 14, 

2000 

USEPA (U.S. Environmental Protection Agency). 1990. Methane Emissions From Coal Mining: Issues and 

Opportunities for Reduction. Office of Air and Radiation (9ANR-445). Washington, DC EPA/400/9­

90/008. 
USEPA (U.S. Environmental Protection Agency). 1991. Assessment of the Potential for Economic 

Development and Utilization of Coalbed Methane in Poland. Office of Air and Radiation (9ANR-445). 

Washington, DC EPA/400/1-91/032. 

USEPA (U.S. Environmental Protection Agency). 1993. Opportunities to Reduce Anthropogenic Methane 

Emissions in the United States. Report to Congress. Office of Air and Radiation (6202J). EPA 430­

R-93-012. October 1993. 

USEPA (U.S. Environmental Protection Agency). 1994. The Environmental and Economic Benefits of 

Coalbed Methane Development in the Appalachian Region. Office of Air and Radiation. (6202J). 

EPA/430/R-94/007. April 1994. 

USEPA (U.S. Environmental Protection Agency) 1998. Gas Storage at the Abandoned Leyden Coal Mine 

Near Denver Colorado. Office of Air and Radiation, (6206J). November 1998. 

USEPA (U.S. Environmental Protection Agency). 1999. Conceptual Design for a Coal Mine Gob Well Flare, 

Office of Air and Radiation, (6206J). EPA/430/R-99/012. August 1999. 

USEPA (U.S. Environmental Protection Agency). 2000. Technical and Economic Assessment: Mitigation of 

Methane Emissions from Coal Mine Ventilation Air, U.S. Environmental Protection Agency, EPA-430­

R-001, February 2000. 

USEPA (U.S. Environmental Protection Agency). 2001. Non-CO2 Greenhouse Gas Emissions from 

Developed Countries: 1990-2010; Office of Air and Radiation, (6206J), EPA 430-R-01-007. 

December 2001. 

USEPA (U.S. Environmental Protection Agency). 2003. Assessment of the Worldwide Market Potential for 

Oxidizing Coal Mine Ventilation Air Methane, EPA/430/R-03/002. July 2003. 

USEPA (U.S. Environmental Protection Agency). 2005. Inventory of U.S. Greenhouse Gas Emissions and 

Sinks 1990-2003, Office of Atmospheric Programs, EPA/430/R-03/004. April 2005. 
References and Calculations Used in the Mine Profiles 

Data Item Sources Calculations 

Geographic Data (State, 

County, Basin, 

Coalbed) 

Keystone (2004) 

Corporate Information: 

Current Owner Past versions of Keystone Coal 

Manual and recent coal industry 

publications 

Previous Owner Past versions of Keystone Coal 

Manual and Coal Magazine Annual 

Longwall Surveys 

Parent Company Past versions of Keystone Coal 

Manual and recent coal industry 

publications 

Phone/Address/Contact 

Information 

Past versions of Keystone Coal 

Manual and EIA reports. 

General Information: 

 Number of 

Employees 

Past versions of Keystone Coal 

Manual 

Year of Initial 

Production 

MSHA; Past versions of Keystone 

Coal Manual and articles in coal 

industry publications 

Life Expectancy: Past versions of Keystone Coal 

Manual 

Sulfur Content Past versions of Keystone Coal 

Manual 

Mining Method Past versions of Keystone Coal 

Manual and Coal Magazine 

Longwall Survey 

Primary Use Past versions of Keystone Coal 

Manual 

Production, Ventilation, 

and Drainage Data 

Coal Production MSHA (2004), EIA (2003) 

 Emissions from 

Ventilation 

Systems 

MSHA (1997 - 2004) 

 Estimated 

Methane Drained 

The number of mines assumed to 

have drainage systems is based on 

calls to individual MSHA districts. 

Drainage emissions are estimated by 

assuming that they are 40% of total 

liberation, unless otherwise noted. 
Data Item Sources Calculations 

 Estimated Total 

Methane 

Liberated 

Sum of “emissions from ventilation 

systems” and “estimated methane 

drained.” 

Degasification 

Information 

Drainage system 

Used 

Based on calls to individual MSHA 

districts offices.

 Estimated Assumed to be 40% unless otherwise 

Current Drainage noted for mines where the drainage 

Efficiency efficiency is known. 

Energy and 

Environmental Value 

CO2 Equivalent Global Warming Potential of Estimated 2003 CH4 liberated (mmcf/yr) x 

of Methane Methane Compared to CO2 based recovery efficiency x 19.2 g/cf x 21 g 

Emissions on IPCC (1997). GWP is 21 over CO2/1 g CH4 x 1 lb / 453.59 g x 1 ton / 

Reductions (mm 100 years. 2000 lbs 

tons) 

CO2 Equivalent CO2/BTU ratio based on average Fraction = [CO2 equivalent of CH4 

of Methane state values in EIA (1992) emissions reductions 

Emissions (lbs)] / [2003 coal 

Reductions/CO2 production (tons) x 

Emissions from BTUs/ton x CO2 emitted 

Coal Combustion lbs/BTU x 99% (fraction 

oxidized) 

BTU Value of BTU/ton value for coal production Fraction = [2003 CH4 liberated 

Recovered based on information in Keystone (cf/yr) x rec. efficiency x 

Methane/BTU or on average state values from 1000 BTUs/cf] / [2003 

Value of Coal EIA (1992) coal production (tons) x 

Produced BTUs/ton] 

Power Generation 

Potential 

Electricity Directory of Electric Utilities 

Supplier 

 Potential Electric 

Generating 

Capacity 

 Mine Electricity Mine electricity needs (24 kWh/ton) 

Demand is based on ICF Resources (1990a) 

Ventilation systems are assumed to 

account for 25% of total electricity 

demand and to run 24 hours a day 

(8760 hours/year). Other mine 

operations are assumed to account 

Capacity = Estimated CH4 liberated 

in cf/day x recovery 

efficiency x 1 day/24 

hours x 1000 BTUs/cf x 

kWh/11000 BTUs 

Demand (MW) = Demand from 

Ventilation Systems + Demand 

from Mine Operations 

+ Demand from Prep Plant 

Demand (MW) ventilation systems = 

[25% x 24 kWh/ton x tons/year]/ 
Data Item Sources Calculations 

for 75% of electricity demand and 

to run 16 hours a day 220 days per 

year (3520 hours/year). 

 [8760 hours/year] 

Demand (MW) mine operations = 

[75% x 24 kWh/ton x tons/year]/ 

 [3520 hours/year] 

Demand (GWh/year) = Demand from 

Mine + Demand from Prep. Plant 

Demand from Mine = [24 kWh/ton x 

tons/year]/ 106 

Demand from Prep. Plant = [6 kWh/ton x 

tons/year]/ 106

 Prep Plant 

Electricity 

Demand 

Based on Keystone Coal Manual 

(2004) and Coal magazine annual 

Prep Plant surveys. If tons 

processed per year at the prep 

plant is available in the Keystone, 

then that value is used. Otherwise, 

coal processed is assumed to be 

equal to mine production. Prep 

plant electric needs of 6 kWh/ton 

based on ICF Resources (1990a). 

Prep plants are assumed to 

operate 3520 hours/year. 

Demand (MW) prep plant = 

[6 kWh/ton x tons/year]/ 3520 

hours/year] 

Pipeline Potential 

 Potential Annual Estimated methane liberated (mmcf/d) x 

Gas Sales 365 days/yr x recovery efficiency 

 All other ICF Resources (1990b) 

information 

Other Utilization 

Potential 

Name of Coal 

Fired Boiler 

Located Near 

Mine (if any) 

 Distance to 

Boiler 

Electric Power (2002) 

Electric Power (2002)