SEPA
Identifying Opportunities
for Methane Recovery at
U.S. Coal Mines:
Profiles of Selected Gassy
Underground Coal Mines
1997-2001
EPA Publication: EPA 430-K-04-003
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Identifying Opportunities for Methane Recovery at
U.S. Coal Mines:
Profiles of Selected Gassy Underground Coal Mines
1997-2001
EPA 430-K-04-003
July 2004
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)
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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.
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Table of Contents
Page#
Acknowledgements i
List of Figures vi
List of Tables vi
Frequently Used Terms vii
Frequently Used Abbreviations viii
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
Summary of Opportunities for Project Development 1-5
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. Sand 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
Pennsylvania 3-2
Consolidation Coal Company 3-3
Blacksville No. 2 Mine 3-3
Virginia 3-3
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CONSOL 3-3
Buchanan No. 1 Mine 3-4
VP No. 8 Mine 3-4
West Virginia 3-4
Eastern Associated Coal (Peabody) 3-4
Federal No. 2 Mine 3-4
U.S. Steel Mining 3-5
Pinnacle No. 50 Mine 3-5
Summary 3-5
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 4-7
Other Utilization Possibilities 4-8
Ventilation Air Methane Emission 4-8
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
TableS: Mines Listed by 2001 Coal Production 5-10
Table 9: Mines Employing Drainage Systems 5-11
Table 10: Mines Listed by Estimated Total Methane Liberated in 2001 5-12
Table 11: Mines Listed by Daily Ventilation Emissions in 2001 5-13
Table 12: Mines Listed by Estimated Daily Methane Drained in 2001 5-14
Table 13: Mines Listed by Estimated Specific Emissions in 2001 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
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6. Profiled Mines
Data Summary6-1
Alabama 6-1
Colorado 6-2
Illinois 6-2
Indiana 6-3
Kentucky 6-3
New Mexico 6-4
Ohio 6-4
Oklahoma 6-5
Pennsylvania 6-5
Utah 6-6
Virginia 6-7
West Virginia 6-8
Mine Profiles (profiles appear in alphabetical order by state)
Alabama Mines
Blue Creek No. 4 Ohio
Blue Creek No. 5 Nelms Cadiz Portal
Blue Creek No. 7 Powhatan No. 6
North River
Oak Grove Oklahoma
Shoal Creek Pollyanna No. 8
Colorado Mines Pennsylvania Mines
Bowie No. 2 Bailey
Sanborn Creek Cumberland
West Elk Eighty-Four Mine
Emerald
Illinois Mines Enlow Fork
Galatia
Monterey No. 1 Utah Mines
Pattiki Aberdeen
Rend Lake Dugout
Wabash Pinnacle
West Ridge
Indiana Mines
Gibson Virginia Mines
Buchanan
Kentucky Mines VP No. 3
Baker VP No. 8
Camp No. 11
Cardinal No. 2
Clean Energy No. 1
Leeco No. 68
Mine#1
Pontiki No. 2
New Mexico Mines
San Juan South
IV
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West Virginia Mines
Blacksville No. 2
Federal No. 2
Harris No. 1
Justice #1
Leverage No. 22
McElroy
U.S. Steel No. 50
Robinson Run No. 95
Sentinel
Shoemaker
Whitetail Kittanning
Upper Big Branch - South
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: Ohio Mines 6-5
Table 6-6: Pennsylvania Mines 6-6
Table 6-7 Utah Mines 6-7
Table 6-8: Virginia Mines 6-8
Table 6-9: West Virginia Mines 6-9
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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
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Frequently Used Abbreviations
b
Btu
CAA
CAAA
cf
CH4
CO2
DOE
EIA
EPA
FOB
GWP
m (or M)
mm (or MM)
MSHA
MW
NA
PUC
t
USBM
UMWA
Billion (109)
British Thermal Unit
Clean Air Act
Clean Air Act Amendments
Cubic Feet
Methane
Carbon Dioxide
Department of Energy
Energy Information Administration
Environmental Protection Agency
Freight on Board
Global Warming Potential
Thousand (103)
Million (106)
Mine Safety and Health Administration
Megawatt
Not Available (as opposed to Not Applicable)
Public Utility Commission
ton (short tons are used throughout this report)
U.S. Bureau of Mines
United Mine Workers
of
America
VII
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1. Executive Summary
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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 on-
going recovery projects at 10 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 September 1997, coalbed and coal mine methane
recovery and use have continued to develop and grow from an estimated 28 Bcf in 1997 to over 40 Bcf
in 2001. At a gas price of $3/mcf, this means that coal mine methane developers increased annual
revenues by an estimated $36 million between 1997 and 2001.
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 thanCO2 (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 (CO2) 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
process.
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 US, coal mines account for approximately 10% of all man-made methane emissions. Today,
there are methane recovery and use projects at mines in Alabama, 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
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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 mine recovering two billion cubic feet per year would result in emissions
reductions of 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 The Coalbed Methane Outreach Program (CMOP) has worked voluntarily with the
coal mining industry and associated industries since 1994 to recover and use methane (CH4) released
into and emitted from the 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 US mines that examine a range of end-use
options; and
managing a website that is an important information resource for the coal mine methane
industry.
Overview of CMM Recovery and Use Techniques
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.
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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.
1-3
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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 11 currently operate drainage systems, with drainage efficiencies in the range of 25 to 60 percent.
Ten 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
(12), followed by Kentucky (7), and Alabama (6). In 2001, the 50 mines profiled in this report liberated an
estimated 336 mmcf/d of methane, or about 123 Bcf/yr (93% 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 46% 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 10-29 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.
Please see Chapter 4 for a more detailed discussion of this issue.
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Number
State
Alabama
Colorado
Illinois
Indiana
Kentucky
New Mexico
Ohio
Oklahoma
Pennsylvania
Utah
Virginia
West Virginia
TOTAL:
Table 1-1: U.S. Summary Table
of Profiled Mines and Estimated Methane Liberated and Used in 2001 1
Operating but not Operating and
Using Methane Methane
Total Total
Number Methane Number Metha
of Mines Liberated of Mines Libera
(mmcf/d) (mmcf
1 5.6 5 79.7
3 23.5 0 0.0
5 14.2 0 0.0
1 1.3 0 0.0
7 8.3 0 0.0
1 0.3 0 0.0
2 2.2 0 0.0
1 0.9 0 0.0
5 45.0 0 0.0
4 2.9 0 0.0
1 0.6 2 88.5
19 28.8 3 34.5
40 133.6 10 202.7
Usmg All Mines Profiled in This Report
Total
ne Number Methane Estimated
ted of Mines Liberated Methane Use
/d) (mmcf/d) (mmcf/d)
6 85.3 37
3 23.5 0
5 14.2 0
1 1.3 0
7 8.3 0
1 0.3 0
2 2.2 0
1 0.9 0
5 45.0 0
4 2.9 0
3 89.1 107
12 63.3 9
50 336.3 153
Estimated Emissions and Avoided Emissions of Methane and CO2 M .. co
Equivalent from Operating Mines not Currently Using Methane (40 ._, 2.,
mines): (Bcf/y) (mmt/y)
2001 Estimated
Total Emissions
48.8 19.5
Estimated Annual Avoided Emissions if Recovery Projects are.-.-. on _ _ _ ....
Implemented 10.0-29.3 3.9-11.7
1Chapter4 explains how these data were estimated.
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 0.3 mmcf/d to over
70 mmcf/d. Similarly, specific emissions range from approximately 25 cf/ton to over 11,000 cf/ton.
Annual coal production ranges from approximately 300,000 tons at some mines to over 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
1-5
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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 1997.
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 5.
Chapter 6 lists state summaries and actual mine profiles, which should assist potential investors
in assessing the overall potential project profitability.
1-6
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2. Introduction
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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 September 1997, 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 decreased from 14
in 1997 to ten in 2001. However, the amount of methane recovered has increased from an estimated
28 Bcf in 1997 to nearly 40 Bcf in 2001. At a gas price of $3/mcf, this means that coal mine methane
developers increased revenues by an estimated $36 million from 1997 to 2001. The resulting
decrease in methane emissions has yielded additional benefits to the global environment through
greenhouse gas emission reductions of 5 MMT/year of CO2. 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 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 and 888 is removing 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 should encounter
fewer problems accessing available capacity of the nation's gas and electric transmission lines.
Introduction 2-1
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Figure 2-1: Mines with Active Coal Mine Methane Recovery Projects
Methane Recovery Projects (by State)
Pennsylvania
Alabama
Number of Mines with Methane Recovery Projects
(based on publicly available information)
Figure 2-2: Estimated Annual Use of Methane Recovered From U.S. Coal Mines
(based on publicly available information)
40,000-i
c- 30,000-
m
V
V)
^-a
x^
^j
7
/
^
?
X
s
1994 1995 1996 1997 1998 1999 2000 2001
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
carbon content and generally a higher methane content.4 The capacity to store methane increases as
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
2-2
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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 2001, while
only 38 percent of U.S. coal is produced in underground mines, these mines account for over 70
percent of estimated methane emissions from coal mining (USEPA, 2003a). 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 2001, coal mining emissions were estimated to account for
10.0 percent of total U.S. methane emissions (USEPA, 2003a), 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, but, the CMM released to the atmosphere by the mine ventilation system is typically below 1
percent. This methane vented from a coal mine exhaust shafts constitutes the largest source of coal
mine methane emissions in the U.S. In 2001, for example, 84 billion cubic feet (Bcf) or 64% of the
132 Bcf released from underground mines was released through mine ventilation shafts.
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 20 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 helps 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
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.
Introduction 2-3
-------
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.
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 operations5
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.
5 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).
Twenty one 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
-------
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 12 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 Borehoes
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.
Method
Vertical P re-
Mine Wells
Gob Wells
Horizontal
Boreholes
Longhole
Horizontal
Boreholes
Cross-measure
Boreholes
Source: USEPA
Table 2-1
Summary of Drainage Methods
Description Gas Quality Drainage
Efficiency3
Produces nearly up to 70%
pure methane.
Drilled from surface
to coal seam months
or years in advance
of mining.
Drilled from surface
to a few feet above
coal seam just prior
to mining.
Drilled from inside
the mine to degasify
the coal seam
shortly prior to
mining.
Drilled from inside
the mine to degasify
the coal seam
shortly prior to
mining.
Drilled from inside
the mine to degasify
surrounding rock
strata shortly prior to
mining.
(1993b) & USEPA (2003a)
Current Use in U.S.
Coal Mines"
Used by 8 mines.
Produces methane
that is sometimes
contaminated with
mine air.
Produces nearly
pure methane.
Produces nearly
pure methane.
Produces methane
that is sometimes
contaminated with
mine air.
up to 50% Used by 21 mines.
up to 20% Used by 12 mines.
up to 50%
Up to 20%
Used by at least 2
mines.
Not widely used in
theU.S.c
3 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 prep-
plants 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 Recovery Method
(Btu/cf)
Pipeline Injection > 950 Vertical Wells
Power Generation (Pre-mining
Local Use (at on-site coal prep plant or to fuel degasification)
mine vehicles, or at nearby industrial or
institutional facilities)
Pipeline Injection - requires: 300 to 950 Gob Wells
(1) maintaining pipeline quality, or
(2) gas enrichment
Power Generation
Local Use
Pipeline Injection up to 950 In-Mine Boreholes
Power Generation
Local Use
Use ventilation air methane as combustion air 1 to 20 Ventilation Air
in gas-fired 1C engines, gas turbines or coal-
fired boilers; thermal oxidation; catalytic
reactors; VOC concentrators; lean fuel gas
turbines
Sources: USEPA (1990); USEPA (1991); USEPA (2003a)
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, 10 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
Mining Company Number of State
Jim Walter Resources
U.S. Steel Mining
Drummond Coal
Consolidation
Company
Number of
Active Mines
1
Coal 1
Eastern Associated Coal
(Peabody)
CONSOL Coal Group
Alabama
Alabama, West Virginia
Alabama
West Virginia/Pennsylvania*
West Virginia
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
recovered from vertical or gob wells, it may be possible to use the gas recovered from in-mine
boreholes to supplement production.
Introduction
2-9
-------
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 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 US projects, additional
power generation projects are reported to be operating at coal mines in 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
(1C) 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 Mine in Ohio where a 250 kW Direct FuelCellฎ, 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.
Introduction 2-10
-------
Currently, the most likely generator choice for a coalbed methane project would be either a gas
turbine or an 1C 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 1C 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 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 1.5 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,6 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 (CANMETVarennes, 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.
' 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 1,000ฐC
[1,832ฐF]) 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 350ฐC [662ฐF]). 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 &
CH4
Heat Exchange
Medium
Heat 4
w Exchanger
Heat Exchange
Medium
Air, CO;
H2O &
Heat*
Valve #1 open = ^
Valve #2 open -^-
SHeat recovery piping not
shown
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 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 800ฐC [1472ฐF]). 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-to-
air heat exchanger that is embedded in a section of the reactor that stays below 800ฐC (1472ฐF).
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 prove 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 (1200ฐC [2192ฐF]) 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 US 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 high-
temperature 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 US 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
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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 CCtee, VAM-derived power projects in the US 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 US 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 2003b).
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
(US EPA, 1999).
Green Pricing Projects
With the advent of competition in the electric utility industry, utilities are recognizing the need to
provide new services to the customers. One such service is "green pricing". Under green pricing,
customers have a choice regarding the type of electricity they choose to purchase. Customers could
choose conventional power, which they could purchase at a standard rate, or they could 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.
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
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.
Introduction 2-17
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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
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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 necessary to address technical issues.
Introduction 2-19
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3. Overview of Existing Coal Mine Methane Projects
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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 10 mines profiled in Chapter 6. In 2001, total methane sales from coal
mine methane projects at profiled mines was nearly 40 billion cubic feet, which is the equivalent of
nearly 16 million tons of carbon dioxide.7 At the current wellhead gas price of roughly $4 per
thousand cubic feet, and assuming that all recovered gas was sold to a pipeline, these projects
collectively will have grossed approximately $160 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, 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 and Tuscaloosa Counties, 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 2,200 - 5,800 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 34 million cubic feet of gas per day (Alabama Oil & Gas, 2002). 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) 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. The quantity of methane recovered
in 2001 represents 45 percent of total methane liberated from the mines. Depending on the mine,
recovery from vertical pre-mine wells in 2001 made up approximately 15-35 percent of production,
while gob wells and in-mine boreholes made up the remaining 65 - 85 percent of production.
7 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.
Overview 3-1
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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 east-
central 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 2001, 44 pre-
drainages wells that are scheduled to be mined-through during the next few years produced nearly 3
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 2001, only two of these wells remained in production, producing 500 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 SONAT Exploration Co., Taurus Exploration, Inc., Kukui Operating Co., and El
Paso Production Co. Nearly 60 wells are located within the 5-year mine plan and produced about 3
mmcf of methane per day for pipeline sales in 2001. In 2000, the mine drilled its first two gob wells,
which produced an average of 240 mcf/d in 2001.
Pennsylvania
There is one methane recovery and use project underway in Pennsylvania. The project involves three
mines owned by Consolidation Coal Company. 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 the CONSOL Energy)
Overview 3-2
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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 No. 1 and VP No. 8 mines. The CONSOL Coal Group owns both mines.
CONSOL
CONSOL recovers methane from two of the gassiest mines in the southwestern region of Virginia:
Buchanan No. 1 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 107 mmcf/d in 2000 and
2001 (Virginia, 2002). This number significantly exceeds ventilation emissions of 18 - 20 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 107 mmcf/d of methane that CONSOL currently recovers, approximately 70 mmcf/d can be
attributed to emissions reduction at the mines, with an additional 1.5 mmcf/d being used on-site in a
thermal dryer. The remaining amount is sold to a pipeline and used in the 88 MW power plant. Of the
total recovered methane, gob wells and in-mine horizontal boreholes account for approximately 69
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 31 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 No. 1 Mine
Overview 3-3
-------
A deep and gassy mine, Buchanan No. 1 is actively mining at a depth of about 1,500 feet and has an
in-situ gas content of about 600 cf/ton. Beginning in May 1995, Buchanan No. 1 began using
recovered methane, instead of coal, as fuel in its thermal dryer. As of May 1997, the thermal dryer
consumes 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.
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).
West Virginia
There are two methane recovery and use projects currently underway in West Virginia8. 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.
Eastern Associated Coal (Peabody)
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 1 mmcf/d in 2000 and 2001. 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 1C engines
and gas turbines (U.S.DOE, 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.
Another project involving three West Virginia mines is discussed under the "Pennsylvania" section earlier in this chapter, for
reasons explained in therein.
Overview 3-4
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U.S. Steel Mining
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 is drilled first and the target coal seam is
cavitated. Then a horizontal hole is kicked off from a second well and intersects 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 is drilled through the cavity along the coal seam for up to 4800
feet. When the drill is pulled back along this main branch, paired branches are drilled at 45 degrees
to the main, yielding a "barbed" appearance from a plan view. This process continues 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 2000 and 2001, the Pinnacle Mine recovered and sold approximately 8 mmcf/d of gas from its pre-
mine drainage wells. The mine benefited directly with emissions reductions of 3.5 and 5.5 mmcf/d,
respectively, when they mined through the pre-drained regions. In addition, the mine uses gob vent
boreholes to drain methane, but currently does not recover this gas.
Summary
Table 3-1 summarizes the methane recovery and use projects discussed in this chapter.
Overview 3-5
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Table 3-1: Summary of Existing Methane Recovery and Use Projects
Mine Name
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
Oak Grove
Shoal Creek
Buchanan No. 1
VP#8
Blacksville No. 1
Federal No. 2
US Steel No. 50
Mine
Location
(State)
Alabama
Alabama
Alabama
Virginia
Pennsylvania
West Virginia
West Virginia
Approximate
Amount of Gas
Used in 2001
27 mmcf/day
3 mmcf/day
7 mmcf/day
1 07 mmcf/day
4mmcf/day
1 mmcf/day
8 mmcf/day
Methane Use
Option
Pipeline Sales
Pipeline Sales
Pipeline Sales
Pipeline Sales
On-Site Use
Power
Generation
Pipeline Sales
Pipeline Sales,
Power
Generation
(planned)
Pipeline Sales
Notes
The three mines collectively
produced 34 mmcf/day
of gas in 2001, but only 27
mmcf/d is credited to emissions
avoided.
Most of the production in the
Oak Grove Field is beyond the
limits of the mine plan.
Most of the production from the
White Oak Field is outside the
limits of the mine plan.
These two mines collectively
produced 107 mmcf/day of gas
in 2001, of which 70 mmcfd
contributes to emissions
reduction at the mines. A small
portion (1.5 mmcf/d) of the total
gas production is used
on-site in a thermal dryer.
Gas is produced from two
abandoned mines that are part
of the project, but over 4
mmcf/d is from the active mine
alone.
Project continues to expand as
mine grows. A second project
using methane to generate
electricity is planned.
A unique, horizontal pre-mine
drainage program is utilized.
NA means not available
1 Unless otherwise specified
2Mine not profiled in this report
Overview
3-6
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4. A Key to Evaluating Mine Profiles
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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, 2002). 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 2002 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 (2002) and the Keystone Coal Industry Manual (Keystone, 2002).
State: Mines included in this report are located in the following states - Alabama, Colorado, Illinois,
Indiana, Kentucky, New Mexico, Ohio, Pennsylvania, Utah, Virginia, or West Virginia. Summary
Table 2 shows the mines listed by state.
Key 4-1
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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" (Canon City Field, Piceance Basin, Raton Mesa, 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 2001 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 U.S. 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 and the
Keystone Coal Industry Manual (Keystone, 2002).
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 (2002).
Previous Owner: The name of any previous mine owners is 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.
General Information
Number of Employees: This field shows the number of people employed by the mine, as reported in
the Keystone Coal Industry Manual. The number of employees reflects the latest year for which data
were available. In some cases, the data are from the early 1990's, because the number of employees
at the mine was not included in more recent editions of the Keystone Coal Industry Manual. For
mines that are categorized as closed, the profile lists the number of persons employed by the mine
when it was operating.
Year of Initial Production: Year of initial production indicates the age of the mine, as reported in the
Keystone Coal Industry Manual.
Key ฃ2
-------
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 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 room-and-pillar, based on Coal 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 room-and-pillar 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. 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).
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 1997 to 2001.
Coal Production: 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
with data from coal producing states. Summary Table 9 lists the coal mines by the amount of coal
they produced in 2001.
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
Key 4^3"
-------
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 1997-2001. Summary Table 10 shows mines listed by their
estimated total daily methane liberation for 2001.
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 2001 ventilation emissions, based on MSHA data.
Estimated Methane Drained: Mines that employ degasification systems emit large quantities of
methane in high concentrations. Summary Table 14 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 25 U.S. mines
that have drainage systems in place. A list of the mines that have drainage systems is shown in
Summary Table 12. For the purpose of estimating emissions from drainage systems, if a mine is
listed as having a drainage system in place, it is assumed that the system was in place from 1993
onward.
Specific Emissions: "Specific emissions" refers 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
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.
Key 4-4
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Drainage System Used: Twenty 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 pre-
mine (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.
CO? 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 Ib / 453.59 g x 1 ton / 2000 Ibs]
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 period9
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.
CO? Equivalent of CH4 Emissions Reductions/CO? 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
is multiplied by an emissions factor of from 203 to 210 Ibs CO2 per million Btu.10 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 (Ibs)] / [annual coal production
(tons) x Btus/ton x Ibs CO2 emitted / Btu x 99% (fraction oxidized)].
The ratio is calculated assuming a 20%, 40% and 60% recovery efficiencies.
For further information on the global warming potential of various greenhouse gases see Intergovernmental Panel on
Climate Change (1997)
10 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 Ibs CO2/mm Btu.
Key 41"
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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.
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]
Key 4-6
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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): 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 Btus/cf, 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.
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 emissions 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 20.
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.
Key 4T
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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 profiles 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.
Ventilation Air Methane Emissions
Table 18 in Chapter 5 summarizes certain characterizations 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.
Key 4-8
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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 2001 Coal Production
Table 9: Mines Employing Drainage Systems
Table 10: Mines Listed by Estimated Total Methane Liberated in 2001
Table 11: Mines Listed by Daily Ventilation Emissions in 2001
Table 12: Mines Listed by Daily Methane Drained in 2001
Table 13: Mines Listed by Estimated Specific Emissions in 2001
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
Aberdeen
Bailey Mine
Baker
Blacksville No. 2
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
Bowie No. 2
Buchanan Mine
Cadiz Portal
Camp #11
Cardinal No. 2
Clean Energy No. 1
Cumberland Mine
Dugout Canyon Mine
Eighty-Four Mine
Emerald Mine
EnlowFork Mine
Federal No. 2
Galatia
Gibson
Harris No. 1 Mine
Justice #1
Leeco No. 68
Loveridge No. 22
State
UT
PA
KY
WV
AL
AL
AL
CO
VA
OH
KY
KY
KY
PA
UT
PA
PA
PA
WV
IL
IN
WV
WV
KY
WV
Mine Name
Me Elroy Mine
Mine#1
Monterey No. 1
North River Mine
Oak Grove Mine
Pattiki Mine
Pinnacle
Pollyanna No. 8
Pontiki No. 2
Powhatan No. 6 Mine
Rend Lake
Robinson Run No. 95
San Juan South
Sanborn Creek
Sentinel Mine
Shoal Creek
Shoemaker Mine
Tiller No. 1
Upper Big Branch - South
US Steel No. 50
VP No. 8
Wabash
West Elk Mine
West Ridge Mine
Whitetail Kittanning Mine
State
WV
KY
IL
AL
AL
IL
UT
OK
KY
OH
IL
WV
NM
CO
WV
AL
WV
VA
WV
WV
VA
IL
CO
UT
WV
Mine Summary Tables
Page 5-1
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Table 2: Mines Listed by State and County
Mine Name
North River Mine
Oak Grove Mine
Shoal Creek
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
Bowie No. 2
Sanborn Creek
West Elk Mine
Rend Lake
Monterey No. 1
Galatia
Wabash
Pattiki Mine
Gibson
Cardinal No. 2
Pontiki No. 2
Leeco No. 68
Clean Energy No. 1
Mine#1
Camp #11
Baker
San Juan South
Powhatan No. 6 Mine
Cadiz Portal
State
AL
AL
AL
AL
AL
AL
CO
CO
CO
IL
IL
IL
IL
IL
IN
KY
KY
KY
KY
KY
KY
KY
NM
OH
OH
County
Fayette
Jefferson
Jefferson
Tuscaloosa
Tuscaloosa
Tuscaloosa
Delta
Gunnison
Gunnison
Jefferson
Macoupin
Saline
Wabash
White
Gibson
Hopkins
Martin
Perry
Pike
Pike
Union
Webster
San Juan
Belmont
Harrison
Mine Name
Pollyanna No. 8
Bailey Mine
Cumberland Mine
Emerald Mine
Enlow Fork Mine
Eighty-Four Mine
Aberdeen
Dugout Canyon Mine
Pinnacle
West Ridge Mine
Buchanan Mine
VP No. 8
Tiller No. 1
Sentinel Mine
Harris No. 1 Mine
Justice #1
Robinson Run No. 95
Loveridge No. 22
Me Elroy Mine
Shoemaker Mine
Blacksville No. 2
Federal No. 2
Whitetail Kittanning Mine
Upper Big Branch - South
US Steel No. 50
State
OK
PA
PA
PA
PA
PA
UT
UT
UT
UT
VA
VA
VA
WV
WV
WV
WV
WV
WV
WV
WV
WV
WV
WV
WV
County
Le Flore
Greene
Greene
Greene
Greene
Washington
Carbon
Carbon
Carbon
Carbon
Buchanan
Buchanan
Tazewell
Barbour
Boone
Boone
Harrison
Marion
Marshall
Marshall
Monongalia
Monongalia
Preston
Raleigh
Wyoming
Mine Summary Tables
Page 5-2
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Table 3: Mines Listed by Coal Basin
Coal Basin/
Mine Name
Arkoma
Pollyanna No. 8
Central Appalachian
Buchanan Mine
Cardinal No. 2
Clean Energy No. 1
Harris No. 1 Mine
Leeco No. 68
Mine#1
Pontiki No. 2
Tiller No. 1
Upper Big Branch - South
US Steel No. 50
VP No. 8
Central Rockies
Bowie No. 2
Dugout Canyon Mine
Illinois
Baker
Camp #11
Galatia
Gibson
Monterey No. 1
Pattiki Mine
Rend Lake
Wabash
Northern Appalachian
Bailey Mine
Blacksville No. 2
Cadiz Portal
Cumberland Mine
Eighty-Four Mine
Estimated Specific
Emissions (cf/ton)
827
1,463
133
231
106
201
202
182
397
125
1,928
11,063
25
103
366
103
436
291
83
408
290
382
241
658
174
888
1,022
Coal Basin/
Mine Name
Emerald Mine
Enlow Fork Mine
Federal No. 2
Justice #1
Loveridge No. 22
Me Elroy Mine
Powhatan No. 6 Mine
Robinson Run No. 95
Sentinel Mine
Shoemaker Mine
Whitetail Kittanning Mine
San Juan
San Juan South
Uinta
Aberdeen
Pinnacle
Sanborn Creek
West Elk Mine
West Ridge Mine
Warrior
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
North River Mine
Oak Grove Mine
Shoal Creek
Estimated Specific
Emissions (cf/ton)
410
346
1,336
275
1,835
382
114
375
1,208
372
142
166
848
383
908
1,169
120
2,290
5,865
4,887
629
1,751
615
Mine Summary Tables
Page 5-3
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Table 4: Mines Listed by Coalbed
Mine Name
Cardinal No. 2
Leeco No. 68
West Elk Mine
Sanborn Creek
Bowie No. 2
Blue Creek No. 7
Oak Grove Mine
Blue Creek No. 5
Shoal Creek
Blue Creek No. 4
Harris No. 1 Mine
Upper Big Branch - South
Dugout Canyon Mine
Pollyanna No. 8
Rend Lake
Pattiki Mine
Monterey No. 1
Sentinel Mine
Whitetail Kittanning Mine
Pinnacle
Aberdeen
Cadiz Portal
West Ridge Mine
San Juan South
Enlow Fork Mine
Coalbed
#11
Aberdeen
B & E Seams
B and D Seams
B&D Seams
Blue Creek
Blue Creek
Blue Creek
Blue Creek, Mary Lee
Blue Creek, Mary Lee
Eagle
Eagle, Powellton
Gilson, Rock Canyon
Hart
Herrin No. 6
Herrin No. 6
Herrin No. 6
Kittanning
Kittanning
L. Sunnyside, Gilson, Aberdeen
L. Sunnyside, Gilson, Aberdeen
Lower Freeport
Lower Sunnyside
No 9, No. 8
Pittsburgh
Mine Name
Blacksville No. 2
Loveridge No. 22
Me Elroy Mine
Robinson Run No. 95
Shoemaker Mine
Bailey Mine
Federal No. 2
Eighty-Four Mine
Cumberland Mine
Powhatan No. 6 Mine
Emerald Mine
Buchanan Mine
VP No. 8
US Steel No. 50
Mine#1
Clean Energy No. 1
Pontiki No. 2
Justice #1
North River Mine
Galatia
Wabash
Gibson
Tiller No. 1
Baker
Camp #11
Coalbed
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh No. 8
Pittsburgh No. 8
Pittsburgh No. 8
Pocahantas No. 3
Pocahontas No. 3
Pocahontas No. 3
Pond Creek
Pond Creek
Pond Creek
Powellton, Buffalo Crk
Pratt
Springfield
Springfield No. 5
Springfield No.5
Tiller
W. Kentucky No. 13
W. Kentucky No. 9
Mine Summary Tables
Page 5-4
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Parent Company
Aero Energy Co. Inc.
Alliance Coal LLC
Alliance Resources Partners
American Coal Company
American Electric Power
Andalex Resources, Inc.
Table 5: Mines Listed by Company
Owner Mine Name
Anker Energy
Arch Coal Co.
BHP/Billiton
Chevron Texaco
CONSOL Energy
Aero Energy Co. Inc.
White County Coal L.L.C.
Gibson County Coal LLC
The American Coal Co.
AEP Coal, Inc.
Andalex Resources, Inc.
Andalex Resources, Inc.
West Ridge Resources
Philippi Development, Inc.
Canyon Fuel Co., LLC
Mountain Coal Co.
San Juan Coal Co.
Mine#1
Pattiki Mine
Gibson
Galatia
Cadiz Portal
Aberdeen
Pinnacle
West Ridge Mine
Sentinel Mine
Dugout Canyon Mine
West Elk Mine
San Juan South
Pittsburg & Midway Coal Mining North River Mine
Consolidation Coal Co.
Rend Lake
Mine Summary Tables
Page 5-5
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Parent Company
Consol Energy Inc.
Table 5: Mines Listed by Company (cont.)
Owner Mine Name
Drummond Co., Inc.
El Paso Corporation
Excel Mining
ExxonMobil Coal & Minerals
HMI
James River Coal Co.
Lodestar Energy, Inc.
Massey Energy Co.
Ohio Valley Coal Company
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Consol Energy Inc.
Eighty-Four Mining Co.
Drummond Co., Inc.
Coastal Coal Co.
Excel Mining LLC
Monterey Coal Co.
HMI
Leeco, Inc.
Lodestar Energy, Inc
Independence Coal Co.
Knox Creek Coal Corp.
Massey Energy Co.
Performance Coal Co.
Ohio Valley Coal Co.
Shoemaker Mine
Enlow Fork Mine
VP No. 8
Bailey Mine
Robinson Run No. 95
Blacksville No. 2
Buchanan Mine
Loveridge No. 22
Me Elroy Mine
Eighty-Four Mine
Shoal Creek
Whitetail Kittanning Mine
Pontiki No. 2
Monterey No. 1
Pollyanna No. 8
Leeco No. 68
Baker
Justice #1
Tiller No. 1
Clean Energy No. 1
Upper Big Branch - South
Powhatan No. 6 Mine
Mine Summary Tables
Page 5-6
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Parent Company
Oxbow Mining, Inc.
Peabody Energy
Table 5: Mines Listed by Company (cont.)
Owner Mine Name
RAG American Coal Co.
RAG Coal International AG
Roberts Brothers Coal Co.
Union Pacific
USX Corp.
Walter Industries, Inc.
Oxbow Mining, Inc.
Peabody Energy
Peabody Energy
Peabody Energy
RAG Cumberland Resources, LP
RAG Emerald Resources, LP
RAG Midwest Coal Holding Co.
Roberts Brothers Coal Co., Inc.
Bowie Resources LTD.
U.S. Steel Mining Co., L.L.C.
U.S. Steel Mining Co., L.L.C.
Jim Walter Resources, Inc
Jim Walter Resources, Inc.
Jim Walter Resources, Inc.
Sanborn Creek
Harris No. 1 Mine
Federal No. 2
Camp #11
Cumberland Mine
Emerald Mine
Wabash
Cardinal No. 2
Bowie No. 2
Oak Grove Mine
US Steel No. 50
Blue Creek No. 5
Blue Creek No. 7
Blue Creek No. 4
Mine Summary Tables
Page 5-7
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Table 6: Mines Listed by Mining Method
Mine Name
Cadiz Portal
Cardinal No. 2
Clean Energy No. 1
Gibson
Justice #1
Leeco No. 68
Mine#1
Pattiki Mine
Pollyanna No. 8
Pontiki No. 2
Sentinel Mine
Tiller No. 1
Wabash
Whitetail Kittanning Mine
Bowie No. 2
Camp #11
Galatia
San Juan South
Sanborn Creek
West Ridge Mine
Aberdeen
Bailey Mine
Baker
Blacksville No. 2
Blue Creek No. 4
Method
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Longwall
Longwall
Longwall
Longwall
Longwall
Longwall
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Mine Name
Blue Creek No. 5
Blue Creek No. 7
Buchanan Mine
Cumberland Mine
Dugout Canyon Mine
Eighty-Four Mine
Emerald Mine
Enlow Fork Mine
Federal No. 2
Harris No. 1 Mine
Loveridge No. 22
Me Elroy Mine
Monterey No. 1
North River Mine
Oak Grove Mine
Pinnacle
Powhatan No. 6 Mine
Rend Lake
Robinson Run No. 95
Shoal Creek
Shoemaker Mine
Upper Big Branch - South
US Steel No. 50
VP No. 8
West Elk Mine
Method
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Longwall/Continuous
Mine Summary Tables
Page 5-8
-------
Table 7: Mines Listed by Primary Coal Use
Mine Name
Blue Creek No. 4
Upper Big Branch - South
US Steel No. 50
Aberdeen
Baker
Blacksville No. 2
Bowie No. 2
Cadiz Portal
Camp #11
Cardinal No. 2
Cumberland Mine
Dugout Canyon Mine
Enlow Fork Mine
Federal No. 2
Galatia
Gibson
Leeco No. 68
Loveridge No. 22
Me Elroy Mine
Monterey No. 1
North River Mine
Pattiki Mine
Pinnacle
Pollyanna No. 8
Pontiki No. 2
Primary Use
Metallurgical
Metallurgical
Metallurgical
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Mine Name
Powhatan No. 6 Mine
Robinson Run No. 95
San Juan South
Shoal Creek
Shoemaker Mine
Tiller No. 1
Wabash
West Elk Mine
West Ridge Mine
Whitetail Kittanning Mine
Bailey Mine
Blue Creek No. 5
Buchanan Mine
Clean Energy No. 1
Eighty-Four Mine
Emerald Mine
Harris No. 1 Mine
Justice #1
Mine#1
Oak Grove Mine
Rend Lake
Sentinel Mine
VP No. 8
Blue Creek No. 7
Sanborn Creek
Primary Use
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical
Steam, Metallurgical, Industrial
Steam, Metallurgical, Industrial
Mine Summary Tables
Page 5-9
-------
Mine Name
Bailey Mine
Enlow Fork Mine
Galatia
Emerald Mine
Cumberland Mine
Me Elroy Mine
Bowie No. 2
Blacksville No. 2
West Elk Mine
Robinson Run No. 95
Federal No. 2
Powhatan No. 6 Mine
Buchanan Mine
Shoal Creek
Shoemaker Mine
Harris No. 1 Mine
Camp #11
Justice #1
Baker
North River Mine
Monterey No. 1
US Steel No. 50
Upper Big Branch - South
Sanborn Creek
Blue Creek No. 4
Table 8: Mines Listed by 2001 Coal Production
MM Tons Mine Name MM Tons
10.3 Whitetail Kittanning Mine 2.4
10.3 VPNo. 8 2.3
7.0 West Ridge Mine 2.3
6.7 Dugout Canyon Mine 2.0
6.7 Rend Lake 2.0
6.6 Cardinal No. 2 1.9
5.4 Mine#1 1.9
5.0 Pattiki Mine 1.9
5.0 Oak Grove Mine 1.8
4.9 Blue Creek No. 7 1.8
4.9 Cadiz Portal 1.7
4.6 Gibson 1.7
4.5 Eighty-Four Mine 1.6
4.1 Blue Creek No. 5 1.5
4.1 Wabash 1.5
3.7 Clean Energy No. 1 1.3
3.6 LeecoNo. 68 1.2
3.4 PontikiNo. 2 1.2
3.4 Loveridge No. 22 1.1
3.2 San Juan South 0.7
3.2 Tiller No. 1 0.6
3.1 Aberdeen 0.5
2.9 Pollyanna No. 8 0.4
2.8 Sentinel Mine 0.4
2.5 Pinnacle 0.3
Mine Summary Tables
Page 5-10
-------
Table 9: Mines Employing Methane Drainage Systems
Mine Name
Bailey Mine
Blacksville No. 2
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
Bowie No. 2
Buchanan Mine
Cumberland Mine
Emerald Mine
Enlow Fork Mine
Federal No. 2
Loveridge No. 22
Oak Grove Mine
Robinson Run No. 95
Sanborn Creek
Shoal Creek
Shoemaker Mine
US Steel No. 50
VP No. 8
West Elk Mine
Type of Drainage System
Vertical Gob
Vertical Gob, Horizontal Pre-Mine
Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Vertical Gob
Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Vertical Gob, Horizontal Pre-Mine
Vertical Gob, Horizontal Pre-Mine
Vertical Gob
Vertical Gob, Horizontal Pre-Mine
Vertical Gob, Horizontal Pre-Mine
Vertical Pre-Mine, Vertical Gob
Vertical Gob, Horizontal Pre-Mine
Vertical Gob
Vertical Pre-Mine, Vertical Gob
Vertical Gob
Directional Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
Vertical Gob
Estimated Current
Drainage Efficiency
1%
26%
50%
44%
40%
24%
42%
28%
22%
1%
40%
40%
28%
20%
25%
5%
15%
43%
90%
25%
Mine Summary Tables
Page 5-11
-------
Table 10: Mines Listed by Estimated Total Methane Liberated in 2001
Mine Name
VP No. 8
Blue Creek No. 7
Blue Creek No. 5
Federal No. 2
Buchanan Mine
US Steel No. 50
Cumberland Mine
West Elk Mine
Blue Creek No. 4
Enlow Fork Mine
Blacksville No. 2
Oak Grove Mine
Galatia
Emerald Mine
Sanborn Creek
Shoal Creek
Me Elroy Mine
Bailey Mine
Loveridge No. 22
North River Mine
Robinson Run No. 95
Eighty-Four Mine
Shoemaker Mine
Baker
Justice #1
MMCF/D
70.6
24.5
23.6
17.9
17.9
16.6
16.2
16.1
15.9
9.8
9.1
8.8
8.4
7.6
7.0
6.9
6.9
6.8
5.8
5.6
5.0
4.6
4.2
3.4
2.5
Mine Name
Pattiki Mine
Rend Lake
Wabash
Powhatan No. 6 Mine
Sentinel Mine
Gibson
Aberdeen
Harris No. 1 Mine
Mine#1
Upper Big Branch - South
Camp #11
Pollyanna No. 8
Whitetail Kittanning Mine
Clean Energy No. 1
Cadiz Portal
West Ridge Mine
Monterey No. 1
Cardinal No. 2
Leeco No. 68
Tiller No. 1
Pontiki No. 2
Dugout Canyon Mine
Bowie No. 2
San Juan South
Pinnacle
MMCF/D
2.1
1.5
1.5
1.4
1.4
1.3
1.2
1.1
1.0
1.0
1.0
0.9
0.9
0.9
0.8
0.8
0.7
0.7
0.7
0.6
0.6
0.6
0.4
0.3
0.3
Mine Summary Tables
Page 5-12
-------
Table 11: Mines Listed by Daily Ventilation Emissions in 2001
Mine Name
Blue Creek No. 7
Blue Creek No. 5
West Elk Mine
Cumberland Mine
Federal No. 2
Buchanan Mine
Enlow Fork Mine
US Steel No. 50
Galatia
Blue Creek No. 4
VP No. 8
Me Elroy Mine
Bailey Mine
Blacksville No. 2
Shoal Creek
Oak Grove Mine
Emerald Mine
North River Mine
Sanborn Creek
Eighty-Four Mine
Robinson Run No. 95
Shoemaker Mine
Loveridge No. 22
Baker
Justice #1
MMCF/D
14.7
13.2
12.1
11.7
10.7
10.3
9.7
9.5
8.4
8.0
7.3
6.9
6.7
6.7
6.6
6.3
5.9
5.6
5.2
4.6
4.0
3.5
3.5
3.4
2.5
Mine Name
Pattiki Mine
Rend Lake
Wabash
Powhatan No. 6 Mine
Sentinel Mine
Gibson
Aberdeen
Harris No. 1 Mine
Mine#1
Upper Big Branch - South
Camp #11
Pollyanna No. 8
Whitetail Kittanning Mine
Clean Energy No. 1
Cadiz Portal
West Ridge Mine
Monterey No. 1
Cardinal No. 2
Leeco No. 68
Tiller No. 1
Pontiki No. 2
Dugout Canyon Mine
San Juan South
Pinnacle
Bowie No. 2
MMCF/D
2.1
1.5
1.5
1.4
1.4
1.3
1.2
1.1
1.0
1.0
1.0
0.9
0.9
0.9
0.8
0.8
0.7
0.7
0.7
0.6
0.6
0.6
0.3
0.3
0.3
Mine Summary Tables
Page 5-13
-------
Table 12: Mines Listed by Estimated Daily Methane Drained in 2001
Mine Name
VP No. 8
Blue Creek No. 5
Blue Creek No. 7
Blue Creek No. 4
Buchanan Mine
Federal No. 2
US Steel No. 50
Cumberland Mine
West Elk Mine
Oak Grove Mine
Blacksville No. 2
Loveridge No. 22
Sanborn Creek
Emerald Mine
Robinson Run No. 95
Shoemaker Mine
Shoal Creek
Bowie No. 2
Bailey Mine
Enlow Fork Mine
Cardinal No. 2
North River Mine
Aberdeen
Me Elroy Mine
Justice #1
MMCF/D
63.3
10.4
9.8
8.0
7.5
7.1
7.1
4.5
4.0
2.5
2.4
2.3
1.8
1.7
1.0
0.6
0.3
0.1
0.1
0.1
0.0
0.0
0.0
0.0
0.0
Mine Name
Gibson
Leeco No. 68
Pinnacle
San Juan South
Sentinel Mine
Galatia
Powhatan No. 6 Mine
Pontiki No. 2
Clean Energy No. 1
Camp #11
Baker
Mine#1
Wabash
Dugout Canyon Mine
Pattiki Mine
Cadiz Portal
Monterey No. 1
Whitetail Kittanning Mine
Upper Big Branch - South
Harris No. 1 Mine
Tiller No. 1
Eighty-Four Mine
West Ridge Mine
Pollyanna No. 8
Rend Lake
MMCF/D
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Mine Summary Tables
Page 5-14
-------
Table 13: Mines Listed by Estimated Specific Emissions in 2001
Mine Name
VP No. 8
Blue Creek No. 5
Blue Creek No. 7
Blue Creek No. 4
US Steel No. 50
Loveridge No. 22
Oak Grove Mine
Buchanan Mine
Federal No. 2
Sentinel Mine
West Elk Mine
Eighty-Four Mine
Sanborn Creek
Cumberland Mine
Aberdeen
Pollyanna No. 8
Blacksville No. 2
North River Mine
Shoal Creek
Galatia
Emerald Mine
Pattiki Mine
Tiller No. 1
Pinnacle
Me Elroy Mine
CF/Ton
11,063
5,865
4,887
2,290
1,928
1,835
1,751
1,463
1,336
1,208
1,169
1,022
908
888
848
827
658
629
615
436
410
408
397
383
382
Mine Name
Wabash
Robinson Run No. 95
Shoemaker Mine
Baker
Enlow Fork Mine
Gibson
Rend Lake
Justice #1
Bailey Mine
Clean Energy No. 1
Mine#1
Leeco No. 68
Pontiki No. 2
Cadiz Portal
San Juan South
Whitetail Kittanning Mine
Cardinal No. 2
Upper Big Branch - South
West Ridge Mine
Powhatan No. 6 Mine
Harris No. 1 Mine
Dugout Canyon Mine
Camp #11
Monterey No. 1
Bowie No. 2
CF/Ton
382
375
372
366
346
291
290
275
241
231
202
201
182
174
166
142
133
125
120
114
106
103
103
83
25
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
VP No. 8
Blue Creek No. 7
Blue Creek No. 5
Federal No. 2
Buchanan Mine
US Steel No. 50
Cumberland Mine
West Elk Mine
Blue Creek No. 4
Enlow Fork Mine
Blacksville No. 2
Oak Grove Mine
Galatia
Emerald Mine
Sanborn Creek
Shoal Creek
Me Elroy Mine
Bailey Mine
Loveridge No. 22
North River Mine
Robinson Run No. 95
Eighty-Four Mine
Shoemaker Mine
Baker
Justice #1
MM Tons
2.29
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
79
76
58
58
,54
,53
52
52
32
29
29
,27
25
23
23
22
22
,19
,18
,16
,15
,14
,11
08
CO2/Yr
-6.87
-2.
-2.
- 1.
- 1.
- 1.
- 1.
- 1.
- 1.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
38
29
74
74
61
58
56
55
95
88
86
82
74
68
68
67
66
56
54
49
45
41
33
25
Mine Name
Pattiki Mine
Rend Lake
Wabash
Powhatan No. 6 Mine
Sentinel Mine
Gibson
Aberdeen
Harris No. 1 Mine
Mine#1
Upper Big Branch - South
Camp #11
Pollyanna No. 8
Whitetail Kittanning Mine
Clean Energy No. 1
Cadiz Portal
West Ridge Mine
Monterey No. 1
Cardinal No. 2
Leeco No. 68
Tiller No. 1
Pontiki No. 2
Dugout Canyon Mine
Bowie No. 2
San Juan South
Pinnacle
MM Tons
0.07
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
,05
,05
,05
04
04
04
03
03
03
03
03
03
03
03
02
02
02
02
02
02
02
,01
,01
,01
CO2/Yr
- 0.21
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
,15
,15
,14
,13
,13
,12
,10
,10
,10
,10
,09
,09
08
08
,07
,07
- 0.07
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
- 0.
06
06
06
,05
04
03
03
Mine Summary Tables
Page 5-16
-------
Table 15: Mines Listed by Electric Utility Supplier
Utility Parent Company
Mine Name
Allegheny Power Systems, Inc.
Federal No. 2
Robinson Run No. 95
Whitetail Kittanning
Loveridge No. 22
Blacksville No. 2
Bailey Mine
Cumberland Mine
Emerald Mine
Eighty-Four Mine
Enlow Fork Mine
American Electric Power Co., Inc.
VP No. 8
Buchanan Mine
Justice #1
Tiller No. 1
Harris No. 1 Mine
Upper Big Branch - South
US Steel No. 50
Leeco No. 68
Pontiki No. 2
Me Elroy Mine
Shoemaker Mine
Cinergy
Gibson
CIPSCO, Inc.
Rend Lake
Galatia
DPL Inc.
Powhatan No. 6 Mine
Dynergy, Inc.
Monterey No. 1
Utility Company
Monongahela Power Co.
Monongahela Power Co.
Monongahela Power Co.
Monongahela Power Co.
Monongahela Power Co.
West Penn Power Co.
West Penn Power Co.
West Penn Power Co.
West Penn Power Co.
West Penn Power Co.
Appalachian Power Co.
Appalachian Power Co.
Appalachian Power Co.
Appalachian Power Co.
Appalachian Power Co.
Appalachian Power Co.
Appalachian Power Co.
Kentucky Power Co.
Kentucky Power Co.
Wheeling Power Co.
Wheeling Power Co.
PSI
Central Illinois Public Service
Central Illinois Public Service
The Dayton Power & Light Co.
Illinois Power Company
Mine Summary Tables
Page 5-17
-------
Table 15: Mines Listed by Electric Utility Supplier (cont.)
Utility Parent Company
Mine Name
FirstEnergy Corp.
Cadiz Portal
KU Energy
Mine#1
Baker
Clean Energy No. 1
Camp #11
Municipal Owned
Pattiki Mine
Sentinel Mine
OGE Energy Corp.
Pollyanna No. 8
PacifiCorp
Dugout Canyon Mine
Pinnacle
West Ridge Mine
Aberdeen
Public Service of New Mexico
San Juan South
The Southern Co.
North River Mine
Blue Creek No. 7
Oak Grove Mine
Shoal Creek
Blue Creek No. 5
Blue Creek No. 4
Touchstone Energy Cooperatives
West Elk Mine
Sanborn Creek
Bowie No. 2
Cardinal No. 2
Wabash
Utility Company
Ohio Edison
Kentucky Utilities Co.
Kentucky Utilities Co.
Kentucky Utilities Co.
Kentucky Utilities Co.
Carmi Water & Light Dept.
Philippi Municipal Electric
OGE Energy Corp
PacifiCorp
PacifiCorp
PacifiCorp
Price City Utilities, Utah Power & Light
Public Service of New Mexico
Alabama
Alabama
Alabama
Alabama
Alabama
Alabama
Power Co.
Power Co.
Power Co.
Power Co.
Power Co.
Power Co.
Delta Montrose Elec. Assoc./Gunnison County Elec.
Delta-Montrose Electric Coop
Delta-Montrose Electric Coop
Kenergy Corp
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
VP No. 8
Blue Creek No. 7
Blue Creek No. 5
Federal No. 2
Buchanan Mine
US Steel No. 50
Cumberland Mine
West Elk Mine
Blue Creek No. 4
Enlow Fork Mine
Blacksville No. 2
Oak Grove Mine
Galatia
Emerald Mine
Sanborn Creek
Shoal Creek
Me Elroy Mine
Bailey Mine
Loveridge No. 22
North River Mine
Robinson Run No. 95
Eighty-Four Mine
Shoemaker Mine
Baker
Justice #1
Megawatts
53.5 - 107.0
18.5 - 37.1
17.9 - 35.7
13.5 -27.1
13.5 -27.0
12.6 -25.1
12.3 -24.5
12.2 - 24.4
12.'
7,
6,
6,
6,
5,
5,
5,
5,
5,
4,
4,
3,
3,
3,
2
1
.4
.9
.7
.3
.7
.3
.3
.2
.2
.4
.2
.8
.5
.2
.6
.9
1 -24.1
- 14.8
- 13.8
- 13.4
- 12.7
- 11.5
- 10.6
- 10.5
- 10.5
- 10.3
- 8.7
- 8.4
- 7.6
- 7.0
-6.3
- 5.1
- 3.8
Mine Name
Pattiki Mine
Rend Lake
Wabash
Powhatan No. 6 Mine
Sentinel Mine
Gibson
Aberdeen
Harris No. 1 Mine
Mine#1
Upper Big Branch - South
Camp #11
Pollyanna No. 8
Whitetail Kittanning Mine
Clean Energy No. 1
Cadiz Portal
West Ridge Mine
Monterey No. 1
Cardinal No. 2
Leeco No. 68
Tiller No. 1
Pontiki No. 2
Dugout Canyon Mine
Bowie No. 2
San Juan South
Pinnacle
1.
1.
1.
1.
1.
1.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
Megawatts
6 - 3.2
2 -2.3
2 -2.3
1 -2.2
0 -2.1
0 -2.0
,9 - 1.9
8 - 1.6
8
8
8
,7
,7
,6
,6
,6
,6
5
5
,5
,4
,4
3
2
2
- 1
- 1
- 1
- 1
- 1
- 1
- 1
- 1
- 1
- 1
- 1
- 0,
- 0,
- 0,
- 0,
- 0,
- 0,
.6
.5
.5
.4
.4
.3
.2
.1
.1
.1
.0
.9
.9
.8
.6
.5
.5
Mine Summary Tables
Page 5-19
-------
Table 17: Mines Listed by Potential Annual Gas Sales*
(Assuming 20% -60% Recovery Efficiency)
Mine Name
VP No. 8
Blue Creek No. 7
Blue Creek No. 5
Federal No. 2
Buchanan Mine
US Steel No. 50
Cumberland Mine
West Elk Mine
Blue Creek No. 4
Enlow Fork Mine
Blacksville No. 2
Oak Grove Mine
Galatia
Emerald Mine
Sanborn Creek
Shoal Creek
Me Elroy Mine
Bailey Mine
Loveridge No. 22
North River Mine
Robinson Run No. 95
Eighty-Four Mine
Shoemaker Mine
Baker
Justice #1
BCF/Yr
5.2 - 15.5
1.8 - 5.4
1.7 - 5.2
1.3 - 3.9
1.3 - 3.9
1.2 - 3.6
1.2 - 3.5
1.2 - 3.5
1.2 - 3.5
0.7 -2.1
0.7 -2.0
0.6 - 1.9
0.6 - 1.8
0.6 - 1.7
0.5 - 1.5
0.5 - 1.5
0.5 - 1.5
0.5 - 1.5
0.4 - 1.3
0.4 - 1.2
0.4 - 1.1
0.3 - 1.0
0.3 - 0.9
0.2 - 0.7
0.2 - 0.6
Mine Name
Pattiki Mine
Rend Lake
Wabash
Powhatan No. 6 Mine
Sentinel Mine
Gibson
Aberdeen
Harris No. 1 Mine
Mine#1
Upper Big Branch - South
Camp #11
Pollyanna No. 8
Whitetail Kittanning Mine
Clean Energy No. 1
Cadiz Portal
West Ridge Mine
Monterey No. 1
Cardinal No. 2
Leeco No. 68
Tiller No. 1
Pontiki No. 2
Dugout Canyon Mine
Bowie No. 2
San Juan South
Pinnacle
BCF/Yr
0.2 -0.5
0.1 -0.3
0.1 -0.3
0.1 -0.3
0.1 -0.3
0.1 -0.3
0.1 -0.3
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.1 -0.2
0.0 -0.1
0.0 -0.1
0.0 -0.1
0.0 -0.1
0.0 -0.1
0.0 -0.1
0.0 -0.1
* Mine's actual gas sales may differ from the potential
Mine Summary Tables
Page 5-20
-------
Table 18: Mine Shaft Emissions
Mine Name
Aberdeen
Bailey
Bailey
Bailey
Baker
Blacksville
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
Blue Creek No. 7
Bowie No. 2
Buchanan
Cadiz Portal
Camp #11
Cardinal No. 2
Clean Energy No. 1
Cumberland
Cumberland
Cumberland
Cumberland
Cumberland
Dugout Canyon
Eighty-Four Mine
Eighty-Four Mine
Eighty-Four Mine
Emerald
Emerald
Enlow Fork
Enlow Fork
Enlow Fork
Federal No. 2
Galatia
Gibson
Harris No. 1
Shaft Name
Aberdeen
Bleeder 12A
Bleeder 1E
Bleeder 7B
Baker
#2
#4, North fan
#5, 5-7 fan
#7, South fan
#7, South fan
No.2
#1
#11
#2
#1
#1
#6
Bleeder #1
Bleeder #2
Bleeder #3
Lang
Smith
Zediker
Bleeder #4
Emerald #7
A11 bleeder
B6 bleeder
E1 bleeder
#2
Galatia
Gibson
#1
Shaft Vent
Air Flow
CFM
517,249
193,738
219,398
150,385
738,685
3,001,534
2,023,813
1,656,540
1,563,218
1,904,878
423,768
3,101,292
245,339
500,176
162,322
473,924
308,439
540,459
167,909
104,608
197,806
395,517
130,365
157,370
538,793
206,017
684,012
270,518
255,353
238,607
2,018,301
1,788,102
208,240
444,809
Shaft
Methane
Flow
CFM
2,608
577
2,230
634
1,718
4,930
6,915
7,766
6,165
5,678
85
8,278
932
844
410
1,264
1,344
2,130
2,614
1,306
1,071
119
917
1,389
853
1,806
1,318
2,178
1,735
2,126
6,259
5,802
469
618
Shaft
Methane
Cone. %
0.50
0.30
1.02
0.42
0.23
0.16
0.34
0.47
0.39
0.30
0.02
0.27
0.38
0.17
0.25
0.27
0.44
0.39
1.56
1.25
0.54
0.03
0.70
0.88
0.16
0.88
0.19
0.80
0.68
0.89
0.31
0.32
0.23
0.14
Weighted
Mine
Methane
Cone. %
0.50
I
> 0.61
0.23
0.16
0.34
0.47
I 0.34
0.02
0.27
0.38
0.17
0.25
0.27
0.64
0.03
I
> 0.38
I 0.35
> 0.79
0.31
0.32
0.23
0.14
Mine Summary Tables
Page 5-21
-------
Table 18: Mine Shaft Emissions (cont.)
Mine Name
Justice #1
Justice #1
Leeco No. 68
Loveridge No. 22
McElroy
Mine#1
Monterey No. 1
North River
North River
Oak Grove
Oak Grove
Oak Grove
Pattiki
Pinnacle
Pollyanna No. 8
Pontiki No. 2
Powhatan No. 6
Rend Lake
Robinson Run
San Juan South
Sanborn Creek
Sentinel
Shoal Creek
Shoal Creek
Shoemaker
Tiller No. 1
U.S. Steel No. 50
U.S. Steel No. 50
U.S. Steel No. 50
Upper Big Branch
VP No. 8
Wabash
West Elk
West Ridge
Whitetail Kittanning
Shaft Name
Licks bleeder
Whites Br bleeder
22
McElroy
#1
#1
Cedar Cr
Tyro Cr
#1
#4
#5
Pattiki
Pinnacle
No.8
#2
#6
Robinson Run
South
Sanborn Creek
Sentinel
#2
#4
#1
8A
Dale
South Fork
Upper Big Branch
#8
West Elk
Shaft Vent
Air Flow
CFM
222,761
206,935
387,748
1,405,850
1,425,538
605,988
764,901
422,891
509,182
680,844
610,557
463,871
361,495
199,051
185,939
294,519
871,079
1,620,913
1,347,678
90,807
636,551
867,540
514,181
470,259
1,672,768
19,070
353,691
396,627
649,707
275,127
2,693,001
1,063,658
1,519,703
190,696
381,391
Shaft
Methane
Flow
CFM
546
1,226
318
3,576
4,610
685
673
1,118
2,249
683
2,552
1,030
1,681
434
182
215
784
1,572
2,808
6
3,683
1,211
1,538
1,081
3,178
0
2,477
2,496
1,967
111
5,852
1,106
7,231
19
381
Shaft
Methane
Cone. %
0.24 1
0.59 J
0.08
0.25
0.32
0.11
0.09
0.26 1
0.44 J
0.47
0.22
0.10
0.07
0.09
0.10
0.21
0.01
0.58
0.14
0.30 "I
0.23 J
0.19
0.00
0.70 1
0.63
0.30 J
0.28
0.22
0.10
0.48
0.01
0.10
Weighted
Mine
Methane
Cone. %
} 0.41
0.08
0.25
0.32
0.11
0.09
y 0.36
> 0.24
0.47
0.22
0.10
0.07
0.09
0.10
0.21
0.01
0.58
0.14
\ 0.27
0.19
0.00
> 0.50
0.28
0.22
0.10
0.48
0.01
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 ten 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 USX Corp.,
and one mine is owned by Drummond Coal. All five mines sell methane to pipelines. Based on
information obtained from the State of Alabama, Division of Oil & Gas, these five mines recovered and
sold an average of 31 mmcf/d in 2001. 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 No. 1 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 No. 1 Mine could reduce annual methane emissions by 0.4-1.2
Bcf/yr.
Mine
Company
Table 6-1
2001 Coal
Production
(mm tons)
: Alabama Mines
2001 Ventilation, Drainage and Use Data1
Ventilation Estimated Estimated
Emissions Methane Total
(mmcf/d) Drained Methane
(mmcf/d) Liberated
(mmcf/d)
Estimated
Specific
Emissions
(cf/ton)
Mines Using Methane (mines at which recovery and use projects have already been developed):
Blue Creek No. 4 Jim Walter Res. 2.5 8.0 8.0 15.9 2,290
Blue Creek No. 5 Jim Walter Res. 1.5 13.2 10.4 23.6 5,865
Blue Creek No. 7 Jim Walter Res. 1.8 14.7 9.8 24.5 4,887
Oak Grove USX Corp. 1.8 6.3 2.5 8.8 1,751
Shoal Creek Drummond 4.1 6.6 0.3 6.9 615
Total for All Mines Using Methane
Operating But Not Using Methane:
North River No. 1 Pitts. & Midway
TOTAL:2
11.7
3.2
14.9
48.8 31.0 79.8
5.6 0.0 5.6
54.4 31.0 85.4
Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent
From Operating Mines Not Currently Using Methane (North River No. 1):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Project is Implemented
629
Methane
(Bcf/yr)
2.0
0.4-1.2
Estimated
Methane
Used
(mmcf/d)
8.0
10.4
9.8
2.5
0.3
31.0
0.0
31.0
C02
(mmt/yr)
0.8
0.2-0.5
1 Chapter 4 explains how these were estimated.
2 Values shown here do not always sum to totals due to rounding.
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.
Colorado has three operating mines that are potential candidates for methane recovery: Bowie No. 2,
Sanborn Creek/Elk Creek, and West Elk. Table 6-2 shows coal production, methane ventilation, and
drainage data. Among the three operating mines, West Elk had the highest methane emissions,
totaling 12.1 mmcf/d, in 2001. All three mines employ degasification systems using vertical gob vent
boreholes. West Elk also incorporates horizontal gob wells. Table 6-2 shows that methane
emissions from the three Colorado mines totaled an estimated 8.6 Bcf in 2001. Table 6-2 also shows
that the implementation of methane recovery and use projects at the three mines now not using
methane could reduce annual methane emissions by 1.7-5.1 Bcf/yr.
Table 6-2: Colorado Mines
Mine
Company
Operating But Not Using Methane:
Bowie No. 2 Bowie Resources
Sanborn Creek/Elk Creek Oxbow Mining
West Elk Mountain Coal
2001 Coal
Production
(mm tons)
5.4
2.8
5.0
TOTAL:2 13.2
2001 Ventilation and Drainage Data1
Ventilation Estimated Estimated Estimated
Emissions Methane Total Specific
(mmcf/d) Drained Methane Emissions
(mmcf/d) Liberated (cf/ton)
(mmcf/d)
0.3 0.1
5.2 1.8
12.1 4.0
17.6 5.9
Estimated Emissions and Avoided Emissions of Methane and CO2
Equivalent From Operating Mines Not Currently Using Methane (three
mines):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects are Implemented
0.4
7.0
16.1
23.5
Methane
(Bcf/yr)
8.6
1.7-5.1
25
908
1,165
CO2
(mmt/yr)
3.4
0.7-2.0
1 Chapter 4 explains how these data were estimated.
2 Values shown here do not always sum to totals due to rounding.
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.
Five 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 five Illinois mines totaled an estimated 5.7 Bcf in 2001. Table 6-3 shows
that the implementation of methane recovery and use projects at the nine profiled mines that are
operating but not currently using methane could reduce annual methane emissions by 1.1 - 3.1 Bcf/yr.
Mine Summary Tables
Page 6-2
-------
Table 6-3: Illinois Mines
Mine
Operating But Not Using
Galatia No. 56
Monterey No. 1
Pattiki
Rend Lake
Wabash
TOTAL2:
Company
Methane:
Kerr-McGee
Monterey Coal
MAPCO
CONSOL
RAG America
2001 Coal
Production
(mm tons)
7.0
3.2
1.9
2.0
1.5
15.6
2001 Ventilation and Drainage Data1
Ventilation Estimated
Emissions Methane
(mmcf/d) Drained
(mmcf/d)
8.4 0.0
0.7 0.0
2.1 0.0
1.5 0.0
1.5 0.0
14.2 0.0
Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent
From Operating Mines Not Currently Using Methane (nine mines):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects are Implemented
1 Chapter 4 explains how
Estimated
Total
Methane
Liberated
(mmcf/d)
8.4
0.7
2.1
1.5
1.5
14.2
Methane
(Bcf/yr)
5.7
1.1 -3.1
Estimated
Specific
Emissions
(cf/ton)
436
83
408
290
382
-
C02
(mmt/yr)
2.3
0.4-1.2
these data were estimated.
2 Values shown here do not always sum to totals due to rounding.
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 1.7 million tons in 2001. Gibson Mine reported total methane emissions of approximately
0.47 billion cubic feet in 2001, 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 seven 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 only one of three mines with methane emissions greater
than 1 mmcfd. The Camp No. 11 mine is also located in the Illinois Coal Basin. The Freedom Energy
No. 1, Clean Energy No. 1, Pontiki No. 2, Cardinal No. 2 and Leeco No. 68 mines are located in
eastern Kentucky, in the Central Appalachian Basin.
Table 6-4 shows that methane emissions from the seven Kentucky mines totaled an estimated 3.0 Bcf
in 2001. Implementation of methane recovery and use projects at these eight mines could reduce
annual methane emissions by an estimated 0.6 -1.7 Bcf/yr.
Mine Summary Tables
Page 6-3
-------
Table 6-4: Kentucky Mines
Mine
Operating But Not Using
Baker
Camp No. 11
Clean Energy No. 1
Cardinal No. 2
Freedom Energy No. 1
Leeco No. 68
Pontiki No. 2
TOTAL:2
Company
Methane:
Renco Coal Group
Peabody
AT. Massey
Sidney Coal Co.
MAPCO
2001 Coal
Production
(mm tons)
3.4
3.6
1.3
1.9
1.9
1.2
1.2
14.5
2001 Ventilation and Drainage Data1
Ventilation Estimated
Emissions Methane
(mmcf/d) Drained
(mmcf/d)
3.4 0.0
1.0 0.0
0.9 0.0
0.7 0.0
1.0 0.0
0.7 0.0
0.6 0.0
8.3 0.0
Estimated Emissions and Avoided Emissions of Methane and CO2
Equivalent From Operating Mines Not Currently Using Methane (eight
mines):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects are Implemented
1 Chapter 4 explains how
Estimated
Total
Methane
Liberated
(mmcf/d)
3.4
1.0
0.9
0.7
1.0
0.7
0.6
8.3
Methane
(Bcf/yr)
3.0
0.6-1.7
Estimated
Specific
Emissions
(cf/ton)
366
103
231
133
202
201
182
-
C02
(mmt/yr)
1.2
0.2-0.7
these data were estimated.
2 Values shown here do not always sum to totals due to rounding.
New Mexico
The San Juan Mine, which is owned by the BMP Billiton, is the only New Mexico mine profiled in this
report. This longwall mine opened in 2002. While little data is available, ventilation emissions are
expected to exceed 1 mmcfd when the mine is in full production. The mine employs a degasification
system which uses both vertical gob vent boreholes and in-mine, horizontal, pre-drainage boreholes.
The mine is expected to produce up to 6 million tons of coal annually. Based on this limited
information, a coalmine methane use project may be possible at the San Juan Mine.
Ohio
As with the Illinois mines, Ohio mines tend to be less gassy than mines in other regions of the country.
Two operating Ohio mines are profiled in this report: the Nelms-Cadiz Portal, and the Powhatan No.
6. Coal production, ventilation, and drainage data on these mines are shown in Table 6-5. The
Nelms-Cadiz Portal Mine purchases electricity generated from methane drained at the Nelms No. 1
Mine, which is permanently closed. Table 6-5 shows that the implementation of methane recovery
and use projects at these two Ohio mines could reduce annual methane emissions by 0.2 - 0.5 Bcf/yr.
Mine Summary Tables
Page 6-4
-------
Table 6-5: Ohio Mines
Mine
Operating But Not Using
Nelms-Cadiz Portal2
Powhatan No. 6
TOTAL:3
Company
Methane:
Harrison Mining
Ohio Valley Coal
2001 Coal
Production
(mm tons)
1.7
4.6
6.3
2001 Ventilation and Drainage Data1
Ventilation Estimated
Emissions Methane
(mmcf/d) Drained
(mmcf/d)
0.8 0.0
1.4 0.0
2.2 0.0
Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent
From Operating Mines Not Currently Using Methane (all five mines):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects are Implemented
1 Chapter 4 explains how these data were estimated.
2 As discussed in the text, the Nelms-Cadiz Portal Mine uses electricity generated from
the adjacent Nelms No. 1 Mine (about 0.18 mmcf/d).
3 Values shown here do not always sum to totals due to rounding.
Estimated
Total
Methane
Liberated
(mmcf/d)
0.8
1.4
2.2
Methane
(Bcf/yr)
0.8
0.2-0.5
Estimated
Specific
Emissions
(cf/ton)
174
114
CO2
(mmt/yr)
0.3
0.1 -0.2
methane drained from
Oklahoma
A single Oklahoma mine, the Sunrise Coal Mine, is profiled in this report. This room-and-pillar
operation, which opened in 1996, is currently considered the gassiest underground mine in
Oklahoma. Beginning in 2001, the mine produced 0.4 million tons annually, doubled its production.
As a result of the increased production, the mine had reported total methane emissions of
approximately 0.33 billion cubic feet in 2001. Based on these emissions, and a history of gassy mines
in the Arkoma Basin, a coalmine methane project may be viable at the Sunrise Coal 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 6-6.
In 2001, the five mines shown in Table 6-6 liberated about 45.0 mmcf/d (16.4 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 No. 1
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.
Mine Summary Tables
Page 6-5
-------
Table 6-6 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 3.3-9.8
Bcf/yr.
Table 6-6: Pennsylvania Mines
Mine
Company
Operating But Not Using Methane:
Bailey CONSOL
Cumberland RAG America
Emerald No. 1 RAG America
Enlow Fork CONSOL
Mine 84 CONSOL
TOTAL:2
2001 Coal
Production
(mm tons)
10.3
6.7
6.7
10.3
1.6
35.6
2001 Ventilation and Drainage Data1
Ventilation Estimated
Emissions Methane
(mmcf/d) Drained
(mmcf/d)
6.7 0.1
11.7 4.5
5.9 1.7
9.7 0.1
4.6 0.0
38.6 6.4
Estimated Emissions and Avoided Emissions of Methane and CO2
Equivalent From Operating Mines Not Currently Using Methane (ten
mines):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects are Implemented
Estimated
Total
Methane
Liberated
(mmcf/d)
6.8
16.2
7.6
9.8
4.6
45.0
Methane
(Bcf/yr)
16.4
3.3-9.8
Estimated
Specific
Emissions
(cf/ton)
241
888
410
346
1,022
C02
(mmt/yr)
6.6
1.3-9.9
1 Chapter 4 explains how these data were estimated.
2 Values shown here do not always sum to totals due to rounding.
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. Four operating Utah mines are good candidates
for methane recovery and use and are profiled in this report.
The Aberdeen Mine is currently the gassiest in the state with 2001 emissions of 1.2 mmcfd. The mine
is located adjacent to the Pinnacle Mine. Both of these mines, as well as the West Ridge Mine, are
owned by Andalex Resources. These mines tend to have high specific emissions, and have
produced high total methane emissions depending on their yearly coal production. For example, the
Aberdeen Mine produced over 4 mmcfd during 1998-99, while the Pinnacle produced over 1 mmcfd
during the same two years. Table 6-7 shows that the implementation of methane recovery and use
projects at these four operating Utah mines could reduce annual methane emissions by 0.2 - 0.7
Bcf/yr.
Mine Summary Tables
Page 6-6
-------
Table 6-7: Utah Mines
Mine
Operating But Not Using
Aberdeen
Dugout
Pinnacle
West Ridge
TOTAL:2
Company
Methane:
Andalex Resources
Arch Coal Company
Andalex Resources
Andalex Resources
2001 Coal
Production
(mm tons)
0.5
2.0
0.3
Z3
5.1
Estimated Emissions and Avoided Emissions of Methane
From Operating Mines Not Currently Using Methane (two
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects
2001 Ventilation and Drainage Data1
Ventilation Estimated
Emissions Methane
(mmcf/d) Drained
(est.)
(mmcf/d)
1.2 0.0
0.6 0.0
0.3 0.0
OJ3 OJD
2.9 0.0
and CO2 Equivalent
mines):
are Implemented
Estimated
Total
Methane
Liberated
(mmcf/d)
1.2
0.6
0.3
OJ3
2.9
Methane
(Bcf/yr)
1.1
0.2-0.7
Estimated
Specific
Emissions
(cf/ton)
848
103
383
120
C02
(mmt/yr)
0.4
0.1 -0.3
1 Chapter 4 explains how these data were estimated.
2 Values shown here do not always sum to totals due to rounding.
Virginia
As Table 6-8 demonstrates, two of the mines at which successful methane recovery and use projects
have already been developed are located in Virginia. The Buchanan No. 1 and the VP No. 8 mines
are all longwall operations, and are all owned by subsidiaries of CONSOL. The total methane drained
at the two CONSOL Virginia mine properties equaled 71 mmcf/d in 2001. This number significantly
exceeds ventilation emissions of 18 mmcf/d, which indicates that recovery efficiencies (up to 90% at
VP No.8) are higher than standard EPA assumptions. Table 6-8 shows that Consol operates the
largest active methane recovery project in the United States.
Mine Summary Tables
Page 6-7
-------
Table 6-8: Virginia Mines
Mine
Company
2001 Coal
Production
(mm tons)
2001 Ventilation, Drainage and Use Data1
Ventilation Estimated
Emissions Methane
(mmcf/d) Drained
&Used
(mmcf/d)
Estimated
Total
Methane
Liberated
(mmcf/d)
Using Mines (mines at which recovery and use projects have already been developed):
Buchanan No. 1 CONSOL 4.5 10.3 63.3 73.6
VPNo. 8 CONSOL 2.3 7.3 7.5 14.8
Total:
Operating But Not Using Methane:
Tiller No. 2
TOTAL:2
6.8
0.6
7.4
17.6 70.8
0.6 0.0
18.2 70.8
Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent
From Mines Not Currently Using Methane (Tiller No. 2):
2001 Estimated Total Emissions
Estimated Annual Avoided Emissions if Recovery Projects are Implemented
88.4
1.0
88.4
Methane
(Bcf/yr)
0.2
0.05-0.1
Estimated
Specific
Emissions
(cf/ton)
1,463
11,063
383
C02
(mmt/yr)
0.1
0.02-0.06
1 Chapter 4 explains how these data were estimated.
2 Values shown here do not always sum to totals due to rounding.
West Virginia
Of the 50 mines profiled in this report, 12 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 6-9.
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 2001, these mines liberated an estimated 43.6 mmcf/d (15.9 Bcf/yr), while
recovering 8.6 mmcfd (3.2 Bcf/yr). Federal No. 2 recovered and sold about 0.4 Bcf of methane in
2001, while Pinnacle sold about 2.1 Bcf of methane to a gas marketing company, and the project at
Blacksville No. 2 sold about 0.8 Bcf in 2001.
Seven 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 five operating mines that are
profiled are located in the Central Appalachian Basin. Table 6-9 shows that the implementation of
methane recovery and use projects at the nine operating mines that do not already use methane
could reduce annual methane emissions by 2.1 - 6.3 Bcf/yr.
Mine Summary Tables
Page 6-8
-------
Mine
Company
Table 6-9:
2001 Coal
Production
(mm tons)
West Virginia Mines
2001 Ventilation, Drainage and Use Data1
Ventilation Estimated Estimated
Emissions Methane Total
(mmcf/d) Drained Methane
(mmcf/d) 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
Federal No. 2
Pinnacle No. 50
CONSOL
Peabody
USX Corp.
Total for All Mines Using Methane
5.0
4.9
3.1
13.0
6.7 2.4 9.1
10.7 7.1 17.9
9.5 7.1 16.6
26.9 16.6 43.6
658
1,336
1,928
-
1.0
2.1
5.5
8.6
Operating But Not Using Methane:
Harris No. 1
Justice No. 1
Loveridge No. 22
McElroy
Robinson Run No. 95
Sentinel
Shoemaker
Upper Big Branch So.
Whitetail-Kittanning
TOTAL:2
Peabody
Massey
CONSOL
CONSOL
CONSOL
Anker
CONSOL
Massey
Coastal
3.7
3.4
1.1
6.6
4.9
0.4
4.1
2.9
2.4
42.5
1.1 0.0 1.1
2.5 0.0 2.5
3.5 2.3 5.8
6.9 0.0 6.9
4.0 1.0 5.0
1.4 0.0 1.4
3.5 0.6 4.1
1.0 0.0 1.0
0.9 0.0 0.9
51.7 20.5 72.2
Estimated Emissions and Avoided Emissions of Methane and CO2 Equivalent From
Operating Mines Not Currently Using Methane (Nine Mines):
2001 Estimated Total
Emissions
Estimated Annual Avoided Emissions if Recovery
Project is Implemented
106
275
1,835
382
375
1,208
372
125
142
-
Methane
(Bcf/yr)
24.8
5.0-14.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
8.6
CO2
(mmt/yr)
9.9
2.0-6.0
1 Chapter 4 explains how these were estimated.
2 Values shown here do not always sum to totals due
to rounding.
Mine Summary Tables
Page 6-9
-------
6. Profiled Mines (continued)
Alabama Mines
Blue Creek No. 4
Blue Creek No. 5
Blue Creek No. 7
North River
Oak Grove
Shoal Creek
-------
Updated: 04/01/2003
Basin: Warrior
Coalbed: Blue Creek, Mary Lee
Current Owner: Jim Walter Resources, Inc.
Parent Company: Walter Industries, Inc.
Previous Owner(s): None in last 10 years
Status: Active
Blue Creek No. 4
GEOGRAPHIC DATA
State: AL
County: Tuscaloosa
CORPORATE INFORMATION
Parent Company Web Site: vwwv.jimwalterresources.com
Previous or Alternate Name of Mine: No. 4 Mine
Contact Name: Keith Shelvey
Mailing Address: 14730 Lock 17 Rd.
City: Brookwood
Number of Employees at Mine: 394
Year of Initial Production: 1975
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 2,000
MINE ADDRESS
Phone Number: (205) 554-6450
State: AL
ZIP 35444
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Metallurgical
Sulfur Content of Coal Produced: 0.75% - 0.95%
BTUs/lbof Coal Produced: 14,200
Seam Thickness (ft): 6.5
PRODUCTION, VENTILATION AND DRAINAGE DATA
1997 1998 1999
2000
2001
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 50%
Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
2.3
22.0
13.4
8.6
2156
8.5
1.9
23.8
14.1
9.8
2702
10.0
2.0
19.6
12.0
7.6
2151
7.8
2.4
21.4
11.0
10.3
1700
10.3
2.4
15.9
8.0
8.0
1145
7.9
-------
Blue Creek No. 4 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Alabama Power Co.
Parent Corporation of Utility: The Southern Co.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
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
Pipeline Diameter
20%
0.5
7.0%
1 .6%
40%
1.0
14.0%
3.2
60%
1.5
20.9%
4.8
Distance to Pipeline (miles): 0.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): 8.3
MW
20.1
15.8
4.3
12.1
24.1
36.2
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Ongoing CBM/CMM Project since 1980's
GWh/year
76.1
60.9
15.2
105.7
211.3
317.0
Bcf
1.2
2.3
3.5
NA
24.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Warrior
Coalbed: Blue Creek
Current Owner: Jim Walter Resources, Inc
Parent Company: Walter Industries, Inc.
Previous Owner(s): None in last 10 years
Status: Active
Blue Creek No. 5
GEOGRAPHIC DATA
State: AL
County: Tuscaloosa
CORPORATE INFORMATION
Parent Company Web Site: vwwv.jimwalterresources.com
Previous or Alternate Name of No. 5 Mine
Contact Name: Trent Thrasher, Mine Mgr.
Mailing Address: 12972 Lock 17 Rd.
City: Brookwood
Number of Employees at Mine: 389
Year of Initial Production: 1978
Life Expectancy: 2006
Prep Plant Located on Site? Yes
Depth to Seam (ft): 2,140
MINE ADDRESS
Phone Number: (205) 554-6550
State: AL
ZIP 35444
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 0.72% - 0.8%
BTUs/lbof Coal Produced: 13,300
Seam Thickness (ft): 8.3
PRODUCTION, VENTILATION AND DRAINAGE DATA
1997
1998
1999
2000
2001
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 44%
Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
1.2
15.0
9.6
5.4
2947
5.3
1.6
18.6
11.7
6.9
2620
6.9
1.7
22.7
14.3
8.4
3007
8.3
2.0
23.9
14.0
10.0
2575
9.9
2.0
23.6
13.2
10.4
3284
9.4
-------
Blue Creek No. 5 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Alabama Power Co.
Parent Corporation of Utility: The Southern Co.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
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
Pipeline Diameter
20%
0.8
19.1%
4.4%
40%
1.5
38.1%
8.8
60%
2.3
57.2%
13.2%
Distance to Pipeline (miles): 0.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): 10.0
MW
11.6
9.1
2.5
17.9
35.7
53.6
GWh/vear
44.0
35.2
8.8
156.4
312.8
469.3
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Ongoing CBM/CMM Project Since 1980's
Bcf
1.7
3.4
5.2
NA
24.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Warrior
Coalbed: Blue Creek
Current Owner: Jim Walter Resources, Inc.
Parent Company: Walter Industries, Inc.
Previous Owner(s): None in last 10 years
Status: Active
Blue Creek No. 7
GEOGRAPHIC DATA
State: AL
County: Tuscaloosa
CORPORATE INFORMATION
Parent Company Web Site: vwwv.jimwalterresources.com
Previous or Alternate Name of Mine: No. 7 Mine
Contact Name: Leon Robertson, Mine Mgr.
Mailing Address: 18069 Hannah Creek
City: Brookwood
Number of Employees at Mine: 407
Year of Initial Production: 1975
Life Expectancy: 2020
Prep Plant Located on Site? Yes
Depth to Seam (ft): 1790
MINE ADDRESS
Phone Number: (205) 554-6750
State: AL
ZIP 35444
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical,
Sulfur Content of Coal Produced: 0.58% -0.75%
BTUs/lbof Coal Produced: 12,205
Seam Thickness (ft): 5.1
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 40%
Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
1997
2.6
28.4
18.2
10.2
2535
10.4
1998
2.5
27.6
17.9
9.7
2667
9.7
1999
2.1
25.2
16.9
8.3
2993
8.4
2000
2.4
26.1
16.9
9.2
2522
9.3
2001
2.4
24.5
14.7
9.8
2935
9.9
-------
Blue Creek No. 7 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Alabama Power Co.
Parent Corporation of Utility: The Southern Co.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Open Hills/Open High Hills
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Mine owns pipeline that connects to trans, line
Pipeline Diameter
20%
0.8
17.3%
4.0%
40%
1.6
34.6%
8.0
60%
2.4
52.0%
12.0%
Distance to Pipeline (miles): 0.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): 13.3
MW
14.5
11.4
3.1
18.5
37.1
55.6
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Ongoing CBM/CMM Project Since 1980's
GWh/year
54.9
43.9
11.0
162.5
324.9
487.4
Bcf
1.8
3.6
5.4
NA
24.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003 Status: Active
North River Mine
GEOGRAPHIC DATA
Basin: Warrior State: AL
Coalbed: Pratt County: Fayette
CORPORATE INFORMATION
Current Owner: Pittsburg & Midway Coal Mining
Parent Company: Chevron Texaco Parent Company Web Site: vwwv.chevron.com/chevron_root/
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: 362 Mining Method: Longwall/Continuous
Year of Initial Production: 1974 Primary Coal Use: Steam
Life Expectancy: 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
1997 1998 1999 2000 2001
Coal Production (million short tons/year): 2.0 2.4 2.3 2.6 2.6
Estimated Total Methane Liberated (million cf/day): 2.3 2.7 5.2 3.8 5.6
Emission from Ventilation Systems: 2.3 2.7 5.2 3.8 5.6
Estimated Methane Drained: 0.0 0.0 0.0 0.0 0.0
Estimated Specific Emissions (cf/ton): 426 401 819 528 629
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 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.2 0.4 0.5
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 2.3% 4.5% 6.8%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.5% 1.0 1.6
Power Generation Potential
Utility Electric Supplier: Alabama Power Co.
Parent Corporation of Utility: The Southern Co.
MW GWh/year
Total Electricity Demand (2001 data): 25.6 96.9
Mine Electricity Demand: 20.1 77.5
Prep Plant Electricity Demand: 5.5 19.4
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 4.2 37.0
Assuming 40% Recovery Efficiency: 8.4 73.9
Assuming 60% Recovery Efficiency: 12.7 110.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 Hills/Open High Hills
Transmission Pipeline in County? No
Owner of Nearest City of Berry
Distance to Pipeline (miles): 0.4 Pipeline Diameter 2.0
Owner of Next Nearest Pipeline: SNG Intrastate Pipeline
Distance to Next Nearest Pipeline (miles): 14.2 Pipeline Diameter 24.0
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Warrior
Coalbed: Blue Creek
Current Owner: U.S. Steel Mining Co., L.L.C.
Parent Company: USX Corp.
Previous Owner(s): None in last 10 years
Status: Active
Oak Grove Mine
GEOGRAPHIC DATA
State: AL
County: Jefferson
CORPORATE INFORMATION
Parent Company Web Site: vwwv.uss.com/ussteel/lndex.html
Previous or Alternate Name of Mine: None
Contact Name: John Hedrick
Mailing Address: 8800 Oak Grove Mine
City: Adger
Number of Employees at Mine: 450
Year of Initial Production: 1974
Life Expectancy: 2023
Prep Plant Located on Site? No
Depth to Seam (ft): 1,100
MINE ADDRESS
Phone Number: (205) 497-3602
State: AL
ZIP 35006
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 0.5% - 0.55%
BTUs/lbof Coal Produced: 14,000
Seam Thickness (ft): 5.8
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 28%
Drainage System Used: Vertical Pre-Mine, Vertical Gob
1997
2.4
8.3
5.6
2.7
830
2.7
1998
2.8
17.3
9.1
8.2
1182
8.0
1999
2.1
12.6
9.6
3.0
1633
2.9
2000
2.1
10.4
6.7
3.7
1162
3.0
2001
2.1
8.8
6.3
2.5
1261
2.5
-------
Oak Grove Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Alabama Power Co.
Parent Corporation of Utility: The Southern Co.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
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
Pipeline Diameter
20%
0.3
5.4%
1.3%
40%
0.6
10.8%
2.5
60%
0.9
16.2%
3.8
Distance to Pipeline (miles): 0.0
Owner of Next Nearest Pipeline: SNG Intrastate Pipeline
Distance to Next Nearest Pipeline (miles): 3.8
MW
14.6
11.4
3.1
6.7
13.4
20.0
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Ongoing CBM/CMM Project Operating
GWh/year
55.2
44.1
11.0
58.5
117.1
175.6
Bcf
0.6
1.3
1.9
NA
12.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Warrior
Coalbed: Blue Creek, Mary Lee
Current Owner: Drummond Co., Inc.
Parent Company: Drummond Co., Inc.
Previous Owner(s): None in last 10 years
Status: Active
Shoal Creek
GEOGRAPHIC DATA
State: AL
County: Jefferson
CORPORATE INFORMATION
Parent Company Web Site: vwwv.drummondco.com
Previous or Alternate Name of Mine: None
Contact Name: Jay Vilseck
Mailing Address: P.O. Box 1549
City: Jasper
Number of Employees at Mine: 830
Year of Initial Production: 1994
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 1,180
MINE ADDRESS
Phone Number: (205) 491-6200
State: AL
ZIP 35501
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.63% -1.1%
BTUs/lbof Coal Produced: 12,464
Seam Thickness (ft): 7.5, 2.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 5%
Drainage System Used: Vertical Pre-Mine, Vertical Gob
1997
3.9
3.1
3.1
0.0
293
0.0
1998
4.2
7.0
6.0
1.0
524
1.0
1999
4.1
6.8
6.6
0.2
589
0.2
2000
4.2
6.0
5.7
0.3
497
0.3
2001
4.2
6.9
6.6
0.3
584
0.4
-------
Shoal Creek (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.2 0.5 0.7
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 2.1% 4.3% 6.4%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.5% 1.0 1.5
Power Generation Potential
Utility Electric Supplier: Alabama Power Co.
Parent Corporation of Utility: The Southern Co.
MW GWh/year
Total Electricity Demand (2001 data): 32.6 123.5
Mine Electricity Demand: 25.6 98.8
Prep Plant Electricity Demand: 7.0 24.7
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 5.3 46.1
Assuming 40% Recovery Efficiency: 10.5 92.1
Assuming 60% Recovery Efficiency: 15.8 138.2
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.5
Assuming 40% Recovery (Bcf): 1.0
Assuming 60% Recovery (Bcf): 1.5
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 NA
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments: Ongoing CBM/CMM Gas Recovery Project for Pipeline Sales
-------
6. Profiled Mines (continued)
Colorado Mines
Bowie No. 2
Sanborn Creek
West Elk
-------
Updated: 04/01/2003
Basin: Central Rockies
Coalbed: B&D Seams
Current Owner: Bowie Resources LTD.
Parent Company: Union Pacific
Previous Owner(s): Coors Energy
Status: Active
Bowie No. 2
GEOGRAPHIC DATA
State: CO
County: Delta
CORPORATE INFORMATION
Parent Company Web Site: http://vwwv.uprr.com/customers/ener
Previous or Alternate Name of Mine: None
Contact Name: Allen Meckley
Mailing Address: 1855 Old Hwy. 133
City: Paonia
Number of Employees at Mine: 140
Year of Initial Production: 1998
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (970) 929-5240
State: CO
ZIP 81428
GENERAL INFORMATION
Mining Method: Longwall
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.5%
BTUs/lbof Coal Produced: 12,000
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 24%
Drainage System Used: Vertical Gob
1997
0.0
0.0
0.0
0.0
0
0.0
1998
1.2
0.0
0.0
0.0
0
0.0
1999
1.7
0.2
0.2
0.0
32
0.0
2000
5.0
0.2
0.2
0.1
11
0.0
2001
5.0
0.4
0.3
0.1
19
0.0
-------
Bowie No. 2 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.0 0.0 0.0
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 0.1% 0.2% 0.3%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.0% 0.0 0.1
Power Generation Potential
Utility Electric Supplier: Delta-Montrose Electric Coop
Parent Corporation of Utility: Touchstone Energy Cooperatives
MW GWh/year
Total Electricity Demand (2001 data): 42.7 161.7
Mine Electricity Demand: 33.5 129.3
Prep Plant Electricity Demand: 9.2 32.3
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.3 2.5
Assuming 40% Recovery Efficiency: 0.6 4.9
Assuming 60% Recovery Efficiency: 0.8 7.4
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.0
Assuming 40% Recovery (Bcf): 0.1
Assuming 60% Recovery (Bcf): 0.1
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Rocky Mountain Natural Gas
Distance to Pipeline (miles): < Pipeline Diameter 8.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Uinta
Coalbed: B and D Seams
Current Owner: Oxbow Mining, Inc.
Parent Company: Oxbow Mining, Inc.
Previous Owner(s): Pacific Basin Resources
Status: Active
Sanborn Creek
GEOGRAPHIC DATA
State: CO
County: Gunnison
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine: Sanborn Creek & Elk Creek
Contact Name: W.R. Litwiller
Mailing Address: P.O. Box 535
City: Somerset
Number of Employees at Mine: 178
Year of Initial Production: 1991
Life Expectance 2016
Prep Plant Located on Site? No
Depth to Seam (ft): 1,000
MINE ADDRESS
Phone Number: (970)929-5122
State: CO
ZIP 81434
GENERAL INFORMATION
Mining Method: Longwall
Primary Coal Use: Steam, Metallurgical,
Sulfur Content of Coal Produced: 0.5% - 0.62%
BTUs/lbof Coal Produced: 12,370
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 25%
Drainage System Used: Vertical Gob
1997
1.6
7.1
7.1
0.0
1609
0.0
1998
1.5
7.3
7.3
0.0
1744
0.0
1999
1.1
5.3
5.3
0.0
1790
0.0
2000
2.2
7.0
5.3
1.8
890
0.0
2001
2.2
7.0
5.2
1.8
680
0.0
-------
Sanborn Creek (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.2 0.5 0.7
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 3.2% 6.3% 9.5%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.7% 1.5 2.2
Power Generation Potential
Utility Electric Supplier: Delta-Montrose Electric
Parent Corporation of Utility: Touchstone Energy Cooperatives
MW GWh/year
Total Electricity Demand (2001 data): 22.3 84.3
Mine Electricity Demand: 17.5 67.5
Prep Plant Electricity Demand: 4.8 16.9
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 5.3 46.4
Assuming 40% Recovery Efficiency: 10.6 92.8
Assuming 60% Recovery Efficiency: 15.9 139.2
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.5
Assuming 40% Recovery (Bcf): 1.0
Assuming 60% Recovery (Bcf): 1.5
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Rocky Mountain Natural Gas
Distance to Pipeline (miles): < 25 miles Pipeline Diameter 8.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments: Closed In 2003, Adjacent Elk Creek Mine Opened in 2003
-------
Updated: 04/01/2003 Status: Active
West Elk Mine
GEOGRAPHIC DATA
Basin: Uinta State: CO
Coalbed: B & E Seams County: Gunnison
CORPORATE INFORMATION
Current Owner: Mountain Coal Co.
Parent Company: Arch Coal Co. Parent Company Web Site: vwwv.archcoal.com
Previous Owner(s): Atlantic Richfield/ITOCHU Previous or Alternate Name of Mine: Mt. Gunnison
MINE ADDRESS
Contact Name: Gene DiClaudio, Mine Manager 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: NA 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
1997 1998 1999 2000 2001
Coal Production (million short tons/year): 5.6 5.9 7.1 3.4 3.4
Estimated Total Methane Liberated (million cf/day): 9.0 9.3 11.8 15.7 16.1
Emission from Ventilation Systems: 9.0 9.3 11.8 11.8 12.1
Estimated Methane Drained: 0.0 0.0 0.0 3.9 4.0
Estimated Specific Emissions (cf/ton): 590 575 607 1283 876
Methane Recovered (million cf/day): 0.0 0.0 0.0 0.0 0.0
Estimated Current Drainage Efficiency: 25%
Drainage System Used: Vertical Gob
-------
West Elk Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.5 1.0 1.6
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 4.3% 8.6% 12.9%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.0% 2.0 3.0
Power Generation Potential
Utility Electric Supplier: Delta Montrose Elec. Assoc./Gunnison County
Elec. Assoc.
Parent Corporation of Utility: Touchstone Energy Cooperatives
MW GWh/vear
Total Electricity Demand (2001 data): 39.8 150.7
Mine Electricity Demand: 31.3 120.5
Prep Plant Electricity Demand: 8.6 30.1
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 12.2 106.7
Assuming 40% Recovery Efficiency: 24.4 213.4
Assuming 60% Recovery Efficiency: 36.5 320.1
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 1.2
Assuming 40% Recovery (Bcf): 2.3
Assuming 60% Recovery (Bcf): 3.5
Description of Surrounding Terrain: Hilly/Mountainous
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Rocky Mountain Natural Gas
Distance to Pipeline (miles): < 25 miles Pipeline Diameter 8.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
6. Profiled Mines (continued)
Illinois Mines
Galatia
Monterey No. 1
Pattiki
Rend Lake
Wabash
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: Springfield
Current Owner: The American Coal Co.
Parent Company: American Coal Company
Previous Owner(s): Kerr-McGee Coal Corp.
Status: Active
Galatia
GEOGRAPHIC DATA
State: IL
County: Saline
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine: None
Contact Name: Eric S. Grimm
Mailing Address: P.O. Box 727
City: Harrisburg
Number of Employees at Mine: 585
Year of Initial Production: 1983
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 400
MINE ADDRESS
Phone Number: (618) 268-6311
State: IL
ZIP 62946
GENERAL INFORMATION
Mining Method: Longwall
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 1.2%
BTUs/lbof Coal Produced: 12,000
Seam Thickness (ft): 7.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
5.0
9.3
9.3
0.0
681
1998
5.5
8.6
8.6
0.0
574
1999
6.5
8.6
8.6
0.0
483
2000
7.3
10.3
10.3
0.0
509
2001
7.3
8.4
8.4
0.0
436
-------
Galatia (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.3 0.5 0.8
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 1.6% 3.2% 4.8%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.7 1.1
Power Generation Potential
Utility Electric Supplier: Central Illinois Public Service
Parent Corporation of Utility: CIPSCO, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 55.6 210.3
Mine Electricity Demand: 43.6 168.2
Prep Plant Electricity Demand: 11.9 42.1
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 6.3 55.6
Assuming 40% Recovery Efficiency: 12.7 111.2
Assuming 60% Recovery Efficiency: 19.0 166.8
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.6
Assuming 40% Recovery (Bcf): 1.2
Assuming 60% Recovery (Bcf): 1.8
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 24.0
Owner of Next Nearest Pipeline: Trunkline
Distance to Next Nearest Pipeline (miles): 8.0 miles Pipeline Diameter 26"
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments: Gassiest Mine in the Illinois Basin
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: Herrin No. 6
Current Owner: Monterey Coal Co.
Status: Active
Monterey No. 1
GEOGRAPHIC DATA
State: IL
County: Macoupin
CORPORATE INFORMATION
Parent Company: ExxonMobil Coal & Minerals Co. Parent Company Web Site: vwwv.exxonmobil.com/Corporate
Previous Owner(s): Previous or Alternate Name of Mine: None
Contact Name: Howard C. Schulz, GM
Mailing Address: 14300 Brushy Mound
City: Carlinville
Number of Employees at Mine: 326
Year of Initial Production: 1970
Life Expectancy: 2010
Prep Plant Located on Site? No
Depth to Seam (ft): 300
MINE ADDRESS
Phone Number: (217)854-3291
State: IL
ZIP 62626
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.9%
BTUs/lbof Coal Produced: 10,300
Seam Thickness (ft): 6.8
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
2.9
0.7
0.7
0.0
82
1998
2.9
0.6
0.6
0.0
80
1999
3.1
0.6
0.6
0.0
75
2000
2.7
0.8
0.8
0.0
110
2001
2.7
0.7
0.7
0.0
83
-------
Monterey No. 1 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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% 0.7% 1.1%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2 0.2
Power Generation Potential
Utility Electric Supplier: Illinois Power Company
Parent Corporation of Utility: Dynergy, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 25.4 96.0
Mine Electricity Demand: 19.9 76.8
Prep Plant Electricity Demand: 5.5 19.2
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.6 4.8
Assuming 40% Recovery Efficiency: 1.1 9.7
Assuming 60% Recovery Efficiency: 1.7 14.5
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.1
Assuming 40% Recovery (Bcf): 0.1
Assuming 60% Recovery (Bcf): 0.2
Description of Surrounding Terrain: Irregular/Smooth Plains
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Illinois Power
Distance to Pipeline (miles): 1.7 Pipeline Diameter 6.0
Owner of Next Nearest Pipeline: Amren CIPS
Distance to Next Nearest Pipeline (miles): 10.0 Pipeline Diameter 4"
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: Herrin No. 6
Current Owner: White County Coal L.L.C.
Parent Company: Alliance Coal LLC
Previous Owner(s): MAPCO Coal, Inc.
Status: Active
Pattiki Mine
GEOGRAPHIC DATA
State: IL
County: White
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine: None
Contact Name: Mark Kitchen
Mailing Address: P.O. Box 457
City: Carmi
Number of Employees at Mine: 236
Year of Initial Production: 1985
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (618)382-4651
State: IL
ZIP 62821
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.8%
BTUs/lbof Coal Produced: 11,750
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
2.0
2.1
2.1
0.0
378
1998
2.2
2.0
2.0
0.0
339
1999
2.3
2.0
2.0
0.0
315
2000
2.4
2.5
2.5
0.0
375
2001
2.4
2.1
2.1
0.0
408
-------
Pattiki Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 1.5% 3.0% 4.5%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.7 1.0
Power Generation Potential
Utility Electric Supplier: Carmi Water & Light Dept.
Parent Corporation of Utility: Municipal Owned
MW GWh/year
Total Electricity Demand (2001 data): 15.0 56.7
Mine Electricity Demand: 11.8 45.3
Prep Plant Electricity Demand: 3.2 11.3
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 1.6 14.0
Assuming 40% Recovery Efficiency: 3.2 28.0
Assuming 60% Recovery Efficiency: 4.8 42.0
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.2
Assuming 40% Recovery (Bcf): 0.3
Assuming 60% Recovery (Bcf): 0.5
Description of Surrounding Terrain: Irregular Plains
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Texas Eastern Transmission Co.
Distance to Pipeline (miles): 3.3 Pipeline Diameter 24.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: Herrin No. 6
Current Owner: Consolidation Coal Co.
Parent Company: CONSOL Energy
Previous Owner(s): Inland Steel
Status: Active
Rend Lake
GEOGRAPHIC DATA
State: IL
County: Jefferson
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: Inland No. 1
Contact Name: Ron Fisher
Mailing Address: P.O. Box 566
City: Sesser
Number of Employees at Mine: NA
Year of Initial Production: 1967
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 600
MINE ADDRESS
Phone Number: (618) 625-2071
State: IL
ZIP 62884
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced:.81 %-1.81%
BTUs/lbof Coal Produced: 12,000
Seam Thickness (ft): 7.0-9.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
4.1
1.8
1.8
0.0
158
1998
4.1
1.9
1.9
0.0
173
1999
3.8
1.9
1.9
0.0
188
2000
2.7
2.2
2.2
0.0
298
2001
2.7
1.5
1.5
0.0
290
-------
Rend Lake (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 1.1% 2.1% 3.2%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.5 0.7
Power Generation Potential
Utility Electric Supplier: Central Illinois Public Service
Parent Corporation of Utility: CIPSCO, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 15.5 58.5
Mine Electricity Demand: 12.1 46.8
Prep Plant Electricity Demand: 3.3 11.7
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 1.2 10.3
Assuming 40% Recovery Efficiency: 2.3 20.6
Assuming 60% Recovery Efficiency: 3.5 30.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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? Yes
Owner of Nearest Pipeline: Amren CIPS
Distance to Pipeline (miles): 2.5 Pipeline Diameter 6.0
Owner of Next Nearest Pipeline: NGPL
Distance to Next Nearest Pipeline (miles): 18.3 Pipeline Diameter 30.0
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: Springfield No. 5
Status: Active
Wabash
GEOGRAPHIC DATA
State: IL
County: Wabash
CORPORATE INFORMATION
Current Owner: RAG Midwest Coal Holding Co.
Parent Company: RAG Coal International AG
Previous Owner(s): Amax Coal Co.
Parent Company Web Site: http://vwwv.rag-american.com/
Previous or Alternate Name of Mine: None
Contact Name: William Kelly, Gen. Mine Mgr.
Mailing Address: P.O. Box 144
City: Keensburg
Number of Employees at Mine: 177
Year of Initial Production: 1973
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (618) 298-2394
State: IL
ZIP 62852
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 1.5%
BTUs/lbof Coal Produced: 11,000
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
1.6
1.6
1.6
0.0
366
1998
1.4
0.8
0.8
0.0
205
1999
1.3
0.8
0.8
0.0
220
2000
1.5
1.2
1.2
0.0
298
2001
1.5
1.5
1.5
0.0
382
-------
Wabash (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 1.5% 3.0% 4.5%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.7 1.0
Power Generation Potential
Utility Electric Supplier: Wayne White Counties Elec. Coop./Morris Elec.
Coop.
Parent Corporation of Utility: Touchstone Energy Cooperatives
MW GWh/vear
Total Electricity Demand (2001 data): 11.6 43.9
Mine Electricity Demand: 9.1 35.1
Prep Plant Electricity Demand: 2.5 8.8
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 1.2 10.2
Assuming 40% Recovery Efficiency: 2.3 20.3
Assuming 60% Recovery Efficiency: 3.5 30.5
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 24.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments: One of Gassiest Mines in Illinois Basin
-------
6. Profiled Mines (continued)
Indiana Mines
Gibson
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: Springfield No.5
Current Owner: Gibson County Coal LLC
Status: Active
Gibson
GEOGRAPHIC DATA
State: IN
County: Gibson
CORPORATE INFORMATION
Parent Company: Alliance Resources Partners Parent Company Web Site: vwwv.arlp.com
Previous Owner(s): Alliance Resources Holdings Previous or Alternate Name of Mine: None
Contact Name: NA
Mailing Address: P.O.Box 1269, Route
City: Princeton
Number of Employees at Mine: 153
Year of Initial Production: 2000
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (812)385-1816
State: IN
ZIP 47670
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 12,800
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
1997 1998 1999
2000
2001
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0.0
1.3
1.3
0.0
291
-------
Gibson (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
20% 40% 60%
0.0 0.1 0.1
1.0% 2.0% 3.0%
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2%
Power Generation Potential
Utility Electric Supplier: PSI
Parent Corporation of Utility: Cinergy
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
MW
13.2
10.4
2.8
1.0
2.0
3.0
0.5
0.7
GWh/year
50.0
40.0
10.0
17.7
26.5
Bcf
0.1
0.2
0.3
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Texas Gas Transmission Co.
Distance to Pipeline (miles): < 5.0 Pipeline Diameter
Owner of Next Nearest Pipeline: Texas Eastern Transmission Co.
Distance to Next Nearest Pipeline (miles): <
10.0
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
4.0
20"
Distance to Plant (miles): NA
-------
6. Profiled Mines (continued)
Kentucky Mines
Baker
Camp No. 11
Cardinal No. 2
Clean Energy No. 1
Leeco No. 68
Mine#1
Pontiki No. 2
-------
Updated: 04/01/2003 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: vwwv.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) 664-6677
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: NA 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
1997 1998 1999 2000 2001
Coal Production (million short tons/year): 4.1 4.4 4.5 4.3 4.3
Estimated Total Methane Liberated (million cf/day): 2.3 2.1 2.2 2.2 3.4
Emission from Ventilation Systems: 2.0 1.9 2.0 2.2 3.4
Estimated Methane Drained: 0.2 0.2 0.2 0.0 0.0
Estimated Specific Emissions (cf/ton): 181 159 161 187 366
Methane Recovered (million cf/day): 0.0 0.0 0.0 0.0 0.0
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
-------
Baker (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 1.7% 3.4% 5.1%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.4% 0.8 1.2
Power Generation Potential
Utility Electric Supplier: Kentucky Utilities Co.
Parent Corporation of Utility: KU Energy
MW GWh/year
Total Electricity Demand (2001 data): 26.7 100.9
Mine Electricity Demand: 20.9 80.7
Prep Plant Electricity Demand: 5.7 20.2
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 2.6 22.4
Assuming 40% Recovery Efficiency: 5.1 44.7
Assuming 60% Recovery Efficiency: 7.7 67.1
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.2
Assuming 40% Recovery (Bcf): 0.5
Assuming 60% Recovery (Bcf): 0.7
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 26.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Illinois
Coalbed: W. Kentucky No. 9
Current Owner: Peabody Energy
Parent Company: Peabody Energy
Previous Owner(s): None in last 10 years
Status: Active
Camp #11
GEOGRAPHIC DATA
State: KY
County: Union
CORPORATE INFORMATION
Parent Company Web Site: vwwv.peapodyenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Louis Adams
Mailing Address: P.O. Box 120
City: Morganfield
Number of Employees at Mine: 300
Year of Initial Production: 1990
Life Expectancy: NA
Prep Plant Located on Site? Yes
Depth to Seam (ft): 350
MINE ADDRESS
Phone Number: (270)389-1007
State: KY
ZIP 42437
GENERAL INFORMATION
Mining Method: Longwall
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.89%
BTUs/lbof Coal Produced: 11,462
Seam Thickness (ft): 5.2
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
3.5
0.6
0.6
0.0
62
1998
3.4
1.0
1.0
0.0
105
1999
3.7
0.9
0.9
0.0
88
2000
3.8
1.3
1.3
0.0
125
2001
3.8
1.0
1.0
0.0
103
-------
Camp #11 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 0.4% 0.8% 1.2%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2 0.3
Power Generation Potential
Utility Electric Supplier: Kentucky Utilities Co.
Parent Corporation of Utility: KU Energy
MW GWh/year
Total Electricity Demand (2001 data): 28.2 106.5
Mine Electricity Demand: 22.1 85.2
Prep Plant Electricity Demand: 6.1 21.3
Potential Generating Capacity (2001 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 (2001 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 Hills
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Texas Gas Transmission Co.
Distance to Pipeline (miles): 4.0 Pipeline Diameter 26.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: #11
Status: Active
Cardinal No. 2
GEOGRAPHIC DATA
State: KY
County: Hopkins
CORPORATE INFORMATION
Current Owner: Roberts Brothers Coal Co., Inc.
Parent Company: Roberts Brothers Coal Co. Inc.
Previous Owner(s): Warrior Coal
Parent Company Web Site:
Previous or Alternate Name of Mine: None
Contact Name: NA
Mailing Address: P.O. Drawer 1210
City: Madisonville
Number of Employees at Mine: NA
Year of Initial Production: NA
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (270) 825-0652
State: KY
ZIP 42431
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced:
BTUs/lb of Coal Produced:
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
1.4
0.9
0.9
0.0
221
1998
1.7
0.9
0.9
0.0
188
1999
1.5
0.4
0.4
0.0
112
2000
1.6
0.8
0.8
0.0
177
2001
1.6
0.7
0.7
0.0
133
-------
Cardinal No. 2 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Kenergy Corp
Parent Corporation of Utility: Touchstone Energy Cooperatives
MW GWh/year
Total Electricity Demand (2001 data): 15.2 57.7
Mine Electricity Demand: 12.0 46.1
Prep Plant Electricity Demand: 3.3 11.5
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.5 4.6
Assuming 40% Recovery Efficiency: 1.1 9.3
Assuming 60% Recovery Efficiency: 1.6 13.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 30.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Pond Creek
Current Owner: Massey Energy Co.
Parent Company: Massey Energy Co.
Previous Owner(s): Sidney Coal Co., Clean
Status: Active
Clean Energy No. 1
GEOGRAPHIC DATA
State: KY
County: Pike
CORPORATE INFORMATION
Parent Company Web Site: vwwv.masseyenergyco.com
Previous or Alternate Name of Mine: None
Contact Name: Barry Dotson
Mailing Address: 29501 Mayo Trail
City: Sidney
Number of Employees at Mine:
Year of Initial Production: 1994
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: ( 60) 635-3720
State: KY
ZIP 41564
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 13,200
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
1.2
0.5
0.5
0.0
144
1998
1.3
1.1
1.1
0.0
308
1999
1.2
1.2
1.2
0.0
377
2000
1.1
1.0
1.0
0.0
332
2001
1.1
0.9
0.9
0.0
231
-------
Clean Energy No. 1 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: Kentucky Utilities Co.
Parent Corporation of Utility: KU Energy
MW GWh/year
Total Electricity Demand (2001 data): 10.6 40.2
Mine Electricity Demand: 8.3 32.2
Prep Plant Electricity Demand: 2.3 8.0
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.6 5.6
Assuming 40% Recovery Efficiency: 1.3 11.3
Assuming 60% Recovery Efficiency: 1.9 16.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 10.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Aberdeen
Current Owner: Leeco, Inc.
Parent Company: James River Coal Co.
Previous Owner(s): Transco Coal Co.
Status: Active
Leeco No. 68
GEOGRAPHIC DATA
State: KY
County: Perry
CORPORATE INFORMATION
Parent Company Web Site: vwwv.jamesrivercoal.com
Previous or Alternate Name of Mine: None
Contact Name: Jack Holbrook
Mailing Address: P.O. Box 309
City: Cornettsville
Number of Employees at Mine: NA
Year of Initial Production: 1995
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (606) 439-3075
State: KY
ZIP 41751
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.8%
BTUs/lbof Coal Produced: 13,250
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
1.5
0.3
0.3
0.0
70
1998
1.5
0.4
0.4
0.0
108
1999
1.4
0.5
0.5
0.0
128
2000
1.2
0.5
0.5
0.0
139
2001
1.2
0.7
0.7
0.0
201
-------
Leeco No. 68 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Kentucky Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Kentucky West Virginia Gas Co.
Distance to Pipeline (miles): < 2.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
20%
0.0
0.7%
0.2%
40%
0.0
1.3%
0.3
60%
0.1
2.0%
0.5
MW
9.5
7.5
2.0
0.5
1.0
1.5
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
GWh/year
36.0
28.8
7.2
4.4
8.8
13.1
Bcf
0.0
0.1
0.1
6.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Pond Creek
Current Owner: Aero Energy Co. Inc.
Status: Active
Mine#1
GEOGRAPHIC DATA
State: KY
County: Pike
CORPORATE INFORMATION
Parent Company: Aero Energy Co. Inc.
Previous Owner(s): Freedom Energy Mining Co.
Parent Company Web Site:
Previous or Alternate Name of Mine: Mine No. 1
Contact Name: Jonah Varney
Mailing Address: P.O. Box 299
City: Sydney
Number of Employees at Mine: NA
Year of Initial Production: NA
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (606) 353-0067
State: KY
ZIP 41564
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 1.67%
BTUs/lbof Coal Produced: 12,822
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
1.1
0.4
0.4
0.0
140
1998
1.2
0.8
0.8
0.0
235
1999
1.5
1.1
1.1
0.0
257
2000
1.5
1.1
1.1
0.0
281
2001
1.5
1.0
1.0
0.0
202
-------
Mine #1 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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% 2.0%
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 (2001 data): 15.1 57.0
Mine Electricity Demand: 11.8 45.6
Prep Plant Electricity Demand: 3.2 11.4
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.8 7.0
Assuming 40% Recovery Efficiency: 1.6 13.9
Assuming 60% Recovery Efficiency: 2.4 20.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Columbia Gas of Kentucky, Inc.
Distance to Pipeline (miles): < 2.0 Pipeline Diameter 10.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Pond Creek
Current Owner: Excel Mining LLC
Parent Company: Excel Mining
Previous Owner(s): Pontiki Coal Co.
Status: Active
Pontiki No. 2
GEOGRAPHIC DATA
State: KY
County: Martin
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine: None
Contact Name: John Small
Mailing Address: P.O. Box 802
City: Lovely
Number of Employees at Mine:
Year of Initial Production:
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 425
MINE ADDRESS
Phone Number: (606) 395-5352
State: KY
ZIP 41231
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.6% - 0.73%
BTUs/lbof Coal Produced: 12,900
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
0.9
0.0
0.0
0.0
0
1998
0.7
0.3
0.3
0.0
151
1999
0.8
0.6
0.6
0.0
283
2000
0.6
0.5
0.5
0.0
335
2001
0.6
0.6
0.6
0.0
182
-------
Pontiki No. 2 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 0.6% 1.2% 1.8%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.3 0.4
Power Generation Potential
Utility Electric Supplier: Kentucky Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
MW GWh/year
Total Electricity Demand (2001 data): 9.4 35.5
Mine Electricity Demand: 7.4 28.4
Prep Plant Electricity Demand: 2.0 7.1
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.4 3.9
Assuming 40% Recovery Efficiency: 0.9 7.8
Assuming 60% Recovery Efficiency: 1.3 11.7
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.0
Assuming 40% Recovery (Bcf): 0.1
Assuming 60% Recovery (Bcf): 0.1
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 6.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
6. Profiled Mines (continued)
New Mexico Mines
San Juan South
-------
Updated: 04/01/2003
Basin: San Juan
Coalbed: No 9, No. 8
Current Owner: San Juan Coal Co.
Parent Company: BMP Billiton
Previous Owner(s):
Status: Active
San Juan South
GEOGRAPHIC DATA
State: NM
County: San Juan
CORPORATE INFORMATION
Parent Company Web Site: vwwv.bhpbilliton.com
Previous or Alternate Name of Mine: None
Contact Name: Scott Langley
Mailing Address: P.O. Box 561
City: Waterflow
Number of Employees at Mine: 280
Year of Initial Production: 1997
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 300 -1,000
MINE ADDRESS
Phone Number: (505) 598-2000
State: NM
ZIP 87421
GENERAL INFORMATION
Mining Method: Longwall
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.8%
BTUs/lbof Coal Produced: 9,500
Seam Thickness (ft): 4.2 -14.6
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: Vertical Gob, Horizontal Pre-mine
1997
0.0
0.0
0.0
0.0
0.0
1998
0.2
0.0
0.0
0.0
0
0.0
1999
0.1
0.0
0.0
0.0
0
0.0
2000
0.0
0.0
0.0
0.0
0
0.0
2001
0.0
0.3
0.3
0.0
166
0.0
-------
San Juan South (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Public Service of New Mexico
Parent Corporation of Utility: Public Service of New Mexico
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
20%
0.0
0.8%
0.2%
40%
0.0
1.5%
0.4
60%
0.0
2.3%
0.5
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Western/Chuska
Distance to Pipeline (miles): < 10.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
MW
5.4
4.2
1.2
0.2
0.5
0.7
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments: Recently Began Underground Mining Operations
GWh/year
20.4
16.3
4.1
2.1
4.1
6.2
Bcf
0.0
0.0
0.1
16.0
Distance to Plant (miles): NA
-------
6. Profiled Mines (continued)
Ohio Mines
Cadiz Portal
Powhatan No. 6
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Lower Freeport
Current Owner: AEP Coal, Inc.
Parent Company: American Electric Power
Previous Owner(s): Harrison Mining Corp.
Status: Active
Cadiz Portal
GEOGRAPHIC DATA
State: OH
County: Harrison
CORPORATE INFORMATION
Parent Company Web Site: vwwv.aep.com
Previous or Alternate Name of Mine: Nelms Cadiz Portal
Contact Name: Bruce Hann
Mailing Address: 44961 Old Hopedale
City: Cadiz
Number of Employees at Mine: 223
Year of Initial Production: 1990
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 520
MINE ADDRESS
Phone Number: (659) 335-6906
State: OH
ZIP 43907
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.4%
BTUs/lbof Coal Produced: 13,050
Seam Thickness (ft): 5.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
1.4
0.8
0.8
0.0
201
1998
1.4
0.8
0.8
0.0
193
1999
1.2
0.7
0.7
0.0
207
2000
1.7
0.9
0.9
0.0
179
2001
1.7
0.8
0.8
0.0
174
-------
Cadiz Portal (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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% 1.2% 1.8%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.3 0.4
Power Generation Potential
Utility Electric Supplier: Ohio Edison
Parent Corporation of Utility: FirstEnergy Corp.
MW GWh/year
Total Electricity Demand (2001 data): 13.6 51.6
Mine Electricity Demand: 10.7 41.3
Prep Plant Electricity Demand: 2.9 10.3
Potential Generating Capacity (2001 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 (2001 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: Columbia Gas Transmission Co.
Distance to Pipeline (miles): Pipeline Diameter 8.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh No. 8
Current Owner: Ohio Valley Coal Co.
Parent Company: Ohio Valley Coal Company
Previous Owner(s): None in last ten years
Status: Active
Powhatan No. 6 Mine
GEOGRAPHIC DATA
State: OH
County: Belmont
CORPORATE INFORMATION
Parent Company Web Site: vwwv.ohiovalleycoal.com
Previous or Alternate Name of Mine: None
Contact Name: John Forrelli
Mailing Address: 56854 Pleasant Ridge
City: Alledonia
Number of Employees at Mine: 440
Year of Initial Production: 1972
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 270
MINE ADDRESS
Phone Number: (740)926-1351
State: OH
ZIP 43902
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 3.8% - 4.5%
BTUs/lbof Coal Produced: 12,600
Seam Thickness (ft): 5.3
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
5.1
1.3
1.3
0.0
94
1998
4.3
1.5
1.5
0.0
133
1999
4.4
1.0
1.0
0.0
84
2000
4.6
1.1
1.1
0.0
89
2001
4.6
1.4
1.4
0.0
114
-------
Powhatan No. 6 Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) .0 0.1 0.1
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 0.4% 0.8% 1.2%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2 0.3
Power Generation Potential
Utility Electric Supplier: The Dayton Power & Light Co.
Parent Corporation of Utility: DPL Inc.
MW GWh/year
Total Electricity Demand (2001 data): 36.6 138.3
Mine Electricity Demand: 28.7 110.7
Prep Plant Electricity Demand: 7.9 27.7
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 1.1 9.6
Assuming 40% Recovery Efficiency: 2.2 19.1
Assuming 60% Recovery Efficiency: 3.3 28.7
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.1
Assuming 40% Recovery (Bcf): 0.2
Assuming 60% Recovery (Bcf): 0.3
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 4.0
Owner of Next Nearest Pipeline: Texas Eastern Transmission
Distance to Next Nearest Pipeline (miles): 1.4 Pipeline Diameter 30.0
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
6. Profiled Mines (continued)
Oklahoma Mines
Pollyanna No. 8
-------
Updated: 04/01/2003
Basin: Arkoma
Coalbed: Hartshorne
Current Owner: HMI
Parent Company: HMI
Previous Owner(s): Sunrise Coal
Status: Active
Pollyanna No. 8
GEOGRAPHIC DATA
State: OK
County: Le Flore
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine: Sunrise Coal
Contact Name:
Mailing Address: P. O. Box 550
City: Henryetta
Number of Employees at Mine:
Year of Initial Production: 1995
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (918)962-9400
State: OK
ZIP 74437
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 14,100
Seam Thickness (ft):
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.2
0.0
0.0
0.0
0
1998
0.2
0.0
0.0
0.0
0
1999
0.2
0.0
0.0
0.0
0
2000
0.2
0.5
0.5
0.0
787
2001
0.2
0.9
0.9
0.0
827
-------
Pollyanna No. 8 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: OGE Energy Corp
Parent Corporation of Utility: OGE Energy Corp.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Arkansas Oklahoma Gas Co.
Distance to Pipeline (miles): 2.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
20%
0.0
2.5%
0.6%
40%
0.1
5.1%
1.2
60%
0.1
7.6%
1.8
MW
3.3
2.6
0.7
0.7
1.4
2.1
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
GWh/year
12.4
10.0
2.5
6.2
12.5
18.7
Bcf
0.1
0.1
0.2
6.0
Distance to Plant (miles): NA
-------
6. Profiled Mines (continued)
Pennsylvania Mines
Bailey
Cumberland
Eighty-Four Mine
Emerald
Enlow Fork
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Bailey Mine
GEOGRAPHIC DATA
State: PA
County: Greene
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Roy Pride
Mailing Address: 332 Enon Church
City: Graysville
Number of Employees at Mine: NA
Year of Initial Production: 1984
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 800
MINE ADDRESS
Phone Number: (724) 663-4781
State: PA
ZIP 15337
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 1.03% -2.41%
BTUs/lbof Coal Produced: 13,200
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 1%
Drainage System Used: Vertical Gob
1997
7.5
11.5
6.9
4.6
336
0.0
1998
8.3
11.7
7.0
4.7
308
0.0
1999
8.5
8.6
6.9
1.7
297
0.0
2000
9.9
7.6
7.6
0.1
279
0.0
2001
9.9
6.8
6.7
0.1
238
0.0
-------
Bailey Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.2 0.4 0.7
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 0.8% 1.6% 2.4%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.4 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 (2001 data): 81.9 309.8
Mine Electricity Demand: 64.3 247.9
Prep Plant Electricity Demand: 17.6 62.0
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 5.2 45.3
Assuming 40% Recovery Efficiency: 10.3 90.7
Assuming 60% Recovery Efficiency: 15.5 136.0
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.5
Assuming 40% Recovery (Bcf): 1.0
Assuming 60% Recovery (Bcf): 1.5
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 20.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh No. 8
Status: Active
Cumberland Mine
GEOGRAPHIC DATA
State: PA
County: Greene
CORPORATE INFORMATION
Current Owner: RAG Cumberland Resources, LP
Parent Company: RAG American Coal Co.
Previous Owner(s): Cyprus Amax, U. S. Steel
Parent Company Web Site: http://vwwv.rag-american.com/
Previous or Alternate Name of Mine: Cumberland
Contact Name: Sam Carlo
Mailing Address: 145 Elm Dr.
City: Waynesburg
Number of Employees at Mine: 557
Year of Initial Production: 1972
Life Expectancy: 2023
Prep Plant Located on Site? Yes
Depth to Seam (ft): 900
MINE ADDRESS
Phone Number: (724) 852-5845
State: PA
ZIP 15370
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.4%
BTUs/lbof Coal Produced: 13,000
Seam Thickness (ft): 6.5-7.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 28%
Drainage System Used: Vertical Gob, Horizontal Pre-Mine
1997
6.3
11.3
9.6
1.7
554
0.0
1998
6.3
11.4
9.7
1.7
563
0.0
1999
6.6
10.7
9.1
1.6
505
0.0
2000
6.5
17.4
12.9
4.5
721
0.0
2001
6.5
16.2
11.7
4.5
641
0.0
-------
Cumberland Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.5 1.1 1.6
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 3.0% 5.9% 8.9%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.7% 1.4 2.0
Power Generation Potential
Utility Electric Supplier: West Penn Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 52.8 199.6
Mine Electricity Demand: 41.4 159.7
Prep Plant Electricity Demand: 11.3 39.9
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 12.3 107.4
Assuming 40% Recovery Efficiency: 24.5 214.9
Assuming 60% Recovery Efficiency: 36.8 322.3
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 1.2
Assuming 40% Recovery (Bcf): 2.4
Assuming 60% Recovery (Bcf): 3.5
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 24.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Eighty-Four Mining Co.
Parent Company: Consol Energy Inc.
Previous Owner(s): Beth Energy Mines
Status: Active
Eighty-Four Mine
GEOGRAPHIC DATA
State: PA
County: Washington
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: Ellsworth or Livingston
Contact Name: Eric Schubel
Mailing Address: P.O. Box 284
City: Eighty Four
Number of Employees at Mine: NA
Year of Initial Production: NA
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 625
MINE ADDRESS
Phone Number: (724) 250-1577
State: PA
ZIP 15330
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 1.33% -1.71%
BTUs/lbof Coal Produced: 13,307
Seam Thickness (ft): 7.5
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
4.8
9.1
9.1
0.0
695
1998
5.9
6.5
6.5
0.0
398
1999
5.8
6.0
6.0
0.0
379
2000
4.2
6.1
6.1
0.0
531
2001
4.2
4.6
4.6
0.0
1022
-------
Eighty-Four Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 3.3% 6.6% 10.0%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.8% 1.5 2.3
Power Generation Potential
Utility Electric Supplier: West Penn Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 13.1 49.5
Mine Electricity Demand: 10.3 39.6
Prep Plant Electricity Demand: 2.8 9.9
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 3.5 30.7
Assuming 40% Recovery Efficiency: 7.0 61.3
Assuming 60% Recovery Efficiency: 10.5 92.0
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.3
Assuming 40% Recovery (Bcf): 0.7
Assuming 60% Recovery (Bcf): 1.0
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 20.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh No. 8
Status: Active
Emerald Mine
GEOGRAPHIC DATA
State: PA
County: Greene
CORPORATE INFORMATION
Current Owner: RAG Emerald Resources, LP
Parent Company: RAG American Coal Co.
Previous Owner(s): Cyprus Amax
Parent Company Web Site: http://vwwv.rag-american.com/
Previous or Alternate Name of Mine: Emerald No. 1
Contact Name: D.M. Conklin
Mailing Address: 145 Elm Dr., P. O. Box
City: Waynesburg
Number of Employees at Mine: 484
Year of Initial Production: 1977
Life Expectancy: 2013
Prep Plant Located on Site? Yes
Depth to Seam (ft): 650
MINE ADDRESS
Phone Number: (724)852-1200
State: PA
ZIP 15370
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 2.4%
BTUs/lbof Coal Produced: 13,000
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 22%
Drainage System Used: Vertical Gob, Horizontal Pre-Mine
1997
4.7
9.3
5.6
3.7
428
0.0
1998
5.4
9.4
5.7
3.8
385
0.0
1999
4.3
8.3
5.0
3.3
418
0.0
2000
6.4
7.5
5.8
1.6
332
0.0
2001
6.4
7.6
5.9
1.7
317
0.0
-------
Emerald Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.2 0.5 0.7
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 1.4% 2.7% 4.1%
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 (2001 data): 53.4 202.1
Mine Electricity Demand: 41.9 161.7
Prep Plant Electricity Demand: 11.5 40.4
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 5.7 50.2
Assuming 40% Recovery Efficiency: 11.5 100.3
Assuming 60% Recovery Efficiency: 17.2 150.5
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.6
Assuming 40% Recovery (Bcf): 1.1
Assuming 60% Recovery (Bcf): 1.7
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 24.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Enlow Fork Mine
GEOGRAPHIC DATA
State: PA
County: Greene
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Dave Hudson
Mailing Address: 322 Enon Church Rd.
City: West Finley
Number of Employees at Mine: NA
Year of Initial Production: 1990
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 800
MINE ADDRESS
Phone Number: (724) 663-7501
State: PA
ZIP 15377
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 1.00% -2.41%
BTUs/lbof Coal Produced: 13,000
Seam Thickness (ft): 5.7-6.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 1%
Drainage System Used: Vertical Gob
1997
8.4
16.1
9.7
6.4
422
0.0
1998
8.8
19.9
11.9
8.0
495
0.0
1999
9.8
13.9
11.1
2.8
411
0.0
2000
9.5
11.1
11.0
0.1
422
0.0
2001
9.5
9.8
9.7
0.1
343
0.0
-------
Enlow Fork Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.3 0.6 1.0
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 1.1% 2.3% 3.4%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.5 0.8
Power Generation Potential
Utility Electric Supplier: West Penn Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 81.9 309.8
Mine Electricity Demand: 64.3 247.8
Prep Plant Electricity Demand: 17.6 62.0
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 7.4 64.9
Assuming 40% Recovery Efficiency: 14.8 129.8
Assuming 60% Recovery Efficiency: 22.2 194.7
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.7
Assuming 40% Recovery (Bcf): 1.4
Assuming 60% Recovery (Bcf): 2.1
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 20.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
6. Profiled Mines (continued)
Utah Mines
Aberdeen
Dugout
Pinnacle
West Ridge
-------
Updated: 04/01/2003
Basin: Uinta
Coalbed: L. Sunnyside, Gilson, And Aberdeen
Status: Active
Aberdeen
GEOGRAPHIC DATA
State: UT
County: Carbon
Current Owner: Andalex Resources, Inc.
Parent Company: Andalex Resources, Inc.
Previous Owner(s): None
CORPORATE INFORMATION
Parent Company Web Site: vwwv.andalex.com
Previous or Alternate Name of Mine: Tower Division
Contact Name: Garth Neilsen
Mailing Address: P.O. Box 902
City: Price
Number of Employees at Mine: 31
Year of Initial Production: 1980
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (435) 637-5385
State: UT
ZIP 84501
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 11,991
Seam Thickness (ft): 6.0-8.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
1.9
2.4
2.4
0.0
478
1998
1.8
2.0
2.0
0.0
412
1999
1.5
4.4
4.4
0.0
1037
2000
1.6
4.4
4.4
0.0
1020
2001
1.6
1.2
1.2
0.0
848
-------
Aberdeen (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Price City Utilities, Utah Power & Light
Parent Corporation of Utility: PacifiCorp
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain: Tablelands; Open High/Low Mountains
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Questar Pipeline Company
Pipeline Diameter
20%
0.0
3.1%
0.7%
40%
0.1
6.2%
1.4
60%
0.1
9.2%
2.1
Distance to Pipeline (miles): -5.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA
MW
4.2
3.3
0.9
0.9
1.9
2.8
GWh/vear
16.0
12.8
3.2
8.2
16.5
24.7
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: Carbon
Comments:
Bcf
0.1
0.2
0.3
20.0
NA
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Uinta
Coalbed: Gilson, Rock Canyon
Current Owner: Canyon Fuel Co., LLC
Parent Company: Arch Coal Co.
Previous Owner(s):
Status: Active
Dugout Canyon Mine
GEOGRAPHIC DATA
State: UT
County: Carbon
CORPORATE INFORMATION
Parent Company Web Site: vwwv.archcoal.com
Previous or Alternate Name of Mine:
Contact Name: R.W. Olsen, Mine Mgr.
Mailing Address: P.O. Box 1029
City: Wellington
Number of Employees at Mine: 175
Year of Initial Production: 1998
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 1400
MINE ADDRESS
Phone Number: (435) 636-2860
State: UT
ZIP 84542
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 0.4% - 0.75%
BTUs/lbof Coal Produced: 11,700
Seam Thickness (ft): 7.5-8.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.0
0.0
0.0
0.0
1998
0.2
0.0
0.0
0.0
0
1999
0.8
0.1
0.1
0.0
62
2000
0.5
0.1
0.1
0.0
103
2001
0.5
0.6
0.6
0.0
103
-------
Dugout Canyon Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: PacifiCorp
Parent Corporation of Utility: PacifiCorp
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Questar Pipeline Company
Distance to Pipeline (miles): < 5.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
20%
0.0
0.4%
0.1%
40%
0.0
0.8%
0.2
60%
0.1
1 .2%
0.3
MW
15.7
12.3
3.4
0.4
0.8
1.3
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
GWh/year
59.4
47.5
11.9
3.7
7.4
11.1
Bcf
0.0
0.1
0.1
20.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Uinta
Coalbed: L. Sunnyside, Gilson, And Aberdeen
Status: Active
Pinnacle
GEOGRAPHIC DATA
State: UT
County: Carbon
Current Owner: Andalex Resources, Inc.
Parent Company: Andalex Resources, Inc.
Previous Owner(s):
CORPORATE INFORMATION
Parent Company Web Site: vwwv.andalex.com
Previous or Alternate Name of Mine: Tower Division
Contact Name: Garth Neilsen
Mailing Address: P.O. Box 902
City: Price
Number of Employees at Mine: NA
Year of Initial Production: 1980
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (435) 637-5385
State: UT
ZIP 84501
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 12,000
Seam Thickness (ft): 6.0-8.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.0
1.0
1.0
0.0
1998
0.0
1.4
1.4
0.0
1999
0.1
0.5
0.5
0.0
3264
2000
0.0
0.5
0.5
0.0
2775
2001
0.0
0.3
0.3
0.0
383
-------
Pinnacle (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
20% 40% 60%
0.0 0.0 0.0
1.4% 2.8% 4.2%
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3%
Power Generation Potential
Utility Electric Supplier: PacifiCorp
Parent Corporation of Utility: PacifiCorp
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Questar Pipeline Co.
Distance to Pipeline (miles): -10.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
MW
2.3
1.8
0.5
0.2
0.5
0.7
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
0.6
1.0
GWh/year
8.9
7.1
1.8
2.1
4.1
6.2
Bcf
0.0
0.0
0.1
20.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Uinta
Coalbed: Lower Sunnyside
Current Owner: West Ridge Resources
Parent Company: Andalex Resources, Inc.
Previous Owner(s):
Status: Active
West Ridge Mine
GEOGRAPHIC DATA
State: UT
County: Carbon
CORPORATE INFORMATION
Parent Company Web Site: vwwv.andalex.com/westridge.html
Previous or Alternate Name of Mine:
Contact Name: Gary Gray
Mailing Address: P.O. Box 1077
City: Price
Number of Employees at Mine: 76
Year of Initial Production: 2001
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 1200
MINE ADDRESS
Phone Number: (435)564-4015
State: UT
ZIP 84501
GENERAL INFORMATION
Mining Method: Longwall
Primary Coal Use: Steam
Sulfur Content of Coal Produced:
BTUs/lbof Coal Produced: 12,000
Seam Thickness (ft):
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.0
0.0
0.0
0.0
1998
0.0
0.0
0.0
0.0
1999
0.0
0.0
0.0
0.0
0
2000
0.5
0.0
0.0
0.0
0
2001
0.5
0.8
0.8
0.0
120
-------
West Ridge Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: PacifiCorp
Parent Corporation of Utility: PacifiCorp
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Questar Pipeline Co.
Distance to Pipeline (miles): < 10.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
20%
0.0
0.4%
0.1%
40%
0.0
0.9%
0.2
60%
0.1
1.3%
0.3
MW
18.2
14.3
3.9
0.6
1.1
1.7
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
GWh/year
68.7
55.0
13.7
5.0
10.0
14.9
Bcf
0.1
0.1
0.2
20.0
Distance to Plant (miles): NA
-------
6. Profiled Mines (continued)
Virginia Mines
Buchanan
Tiller No. 1
VP No. 8
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Pocahantas No. 3
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Buchanan Mine
GEOGRAPHIC DATA
State: VA
County: Buchanan
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: Buchanan No. 1
Contact Name: Terry Suder
Mailing Address: P.O. Box 230, Rte 632
City: Mavisdale
Number of Employees at Mine:
Year of Initial Production: 1983
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (276) 498-6921
State: VA
ZIP 24627
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 0.73%
BTUs/lbof Coal Produced: 13,831
Seam Thickness (ft): 5.4
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 42%
Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
1997
4.3
41.3
12.6
28.8
1055
26.9
1998
4.3
30.8
12.6
18.2
1068
17.4
1999
4.7
19.5
12.3
7.2
959
7.0
2000
4.5
21.6
11.8
9.8
963
9.8
2001
4.5
17.9
10.3
7.5
846
7.4
-------
Buchanan Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
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
Owner of Next Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG)
20%
0.6
4.6%
1.1%
40%
1.2
9.1%
2.1
60%
1.7
13.7%
3.2
MW
35.3
27.7
7.6
13.5
27.0
40.6
GWh/vear
133.6
106.9
26.7
118.5
236.9
355.4
Distance to Next Nearest Pipeline (miles): 1.0
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Ongoing CBM/CMM Program Since Early 1990's
Bcf
1.3
2.6
3.9
NA
8.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Tiller
Current Owner: Knox Creek Coal Corp.
Parent Company: Massey Energy Co.
Previous Owner(s):
Status: Active
Tiller No. 1
GEOGRAPHIC DATA
State: VA
County: Tazewell
CORPORATE INFORMATION
Parent Company Web Site: vwwv.masseyenergyco.com
Previous or Alternate Name of Mine: Tiller No. 2
Contact Name: David Kramer, Pres.
Mailing Address: P.O. Box 519
City: Raven
Number of Employees at Mine: 66
Year of Initial Production: 1995
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 120 - 270
MINE ADDRESS
Phone Number: (276) 963-7338
State: VA
ZIP 24639
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 14,000
Seam Thickness (ft): 6.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.1
0.0
0.0
0.0
0
1998
0.1
0.0
0.0
0.0
0
1999
0.2
0.0
0.0
0.0
0
2000
0.3
0.2
0.2
0.0
237
2001
0.3
0.6
0.6
0.0
397
-------
Tiller No. 1 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
20%
0.0
1 .2%
0.3%
40%
0.0
2.4%
0.6
60%
0.1
3.7%
0.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain:
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: CNG Energy
Distance to Pipeline (miles): < 4.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles):
MW
4.4
3.4
0.9
0.5
0.9
1.4
Pipeline Diameter
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA
Comments:
GWh/year
16.6
13.2
3.3
4.0
8.0
11.9
Bcf
0.0
0.1
0.1
8.0
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Pocahontas No. 3
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 5 years
Status: Active
VP No. 8
GEOGRAPHIC DATA
State: VA
County: Buchanan
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: VP No. 8
Contact Name: Neil Made
Mailing Address: Drawer L
City: Oakwood
Number of Employees at Mine: NA
Year of Initial Production: 1994
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 2050
MINE ADDRESS
Phone Number: (276) 498-7800
State: VA
ZIP 24631
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 0.75%
BTUs/lbof Coal Produced: 14,013
Seam Thickness (ft): 5.0 -5.1
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 90%
Drainage System Used: Vertical Pre-Mine, Vertical Gob, Horizontal Pre-Mine
1997
1.3
18.7
8.1
10.5
2246
18.7
1998
2.7
48.4
10.2
38.2
1361
37.0
1999
1.4
53.7
6.2
47.5
1667
46.3
2000
2.3
59.8
7.9
51.8
1284
51.5
2001
2.3
70.6
7.3
63.3
1150
63.0
-------
VP No. 8 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
20% 40% 60%
2.3 4.6 6.9
34.0% 68.1% 102.1
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced: 7.9%
Power Generation Potential
Utility Electric Supplier: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
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
Owner of Next Nearest Pipeline: Consolidated Natural Gas Supply Co. (CNG)
15.8%
23.7%
MW
18.5
14.5
4.0
53.5
107.0
160.5
GWh/vear
69.9
55.9
14.0
468.5
937.1
1405.0
Distance to Next Nearest Pipeline (miles): 1.0
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Ongoing CBM/CMM Program Since Early 1990's
Bcf
5.2
10.3
15.5
NA
6.0
Distance to Plant (miles): NA
-------
6. Profiled Mines (continued)
West Virginia Mines
Blacksville No. 2
Federal No. 2
Harris No. 1
Justice #1
Leverage No. 22
McElroy
U.S. Steel No. 50
Robinson Run No. 95
Sentinel
Shoemaker
Whitetail Kittanning
Upper Big Branch - South
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Blacksville No. 2
GEOGRAPHIC DATA
State: WV
County: Monongalia
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Byron Payne
Mailing Address: P.O. Box 24
City: Wana
Number of Employees at Mine: 479
Year of Initial Production: 1971
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 1375
MINE ADDRESS
Phone Number: (304) 662-6128
State: WV
ZIP 26590
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 1.97%
BTUs/lbof Coal Produced: 13,419
Seam Thickness (ft): 6.5
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 26%
Drainage System Used: Vertical Gob, Horizontal Pre-Mine
1997
3.4
14.2
8.5
5.7
902
0.4
1998
3.9
13.1
7.8
5.2
734
3.8
1999
4.6
11.1
6.7
4.4
524
3.4
2000
5.2
11.9
7.1
4.8
506
1.1
2001
5.2
9.1
6.7
2.4
485
2.1
-------
Blacksville No. 2 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 2.1% 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: Monongahela Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 39.9 151.0
Mine Electricity Demand: 31.3 120.8
Prep Plant Electricity Demand: 8.6 30.2
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 6.9 60.3
Assuming 40% Recovery Efficiency: 13.8 120.5
Assuming 60% Recovery Efficiency: 20.6 180.8
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.7
Assuming 40% Recovery (Bcf): 1.3
Assuming 60% Recovery (Bcf): 2.0
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 10.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments: Consol is Recovering CMM as part of Multi-Mine Project.
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Peabody Energy
Parent Company: Peabody Energy
Previous Owner(s): Eastern Associated Coal
Status: Active
Federal No. 2
GEOGRAPHIC DATA
State: WV
County: Monongalia
CORPORATE INFORMATION
Parent Company Web Site: vwwv.peabodyenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Blair McGill
Mailing Address: 1044 Miracle Run Rd.
City: Fairview
Number of Employees at Mine: 435
Year of Initial Production: 1968
Life Expectancy: 2011
Prep Plant Located on Site? Yes
Depth to Seam (ft): 800-1250
MINE ADDRESS
Phone Number: (304) 449-1911
State: WV
ZIP 26570
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.0% - 3.2%
BTUs/lbof Coal Produced: 13,300
Seam Thickness (ft): 7.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 40%
Drainage System Used: Vertical Gob, Horizontal Pre-Mine
1997
4.4
7.6
4.5
3.0
377
0.5
1998
4.8
11.8
7.1
4.7
542
0.6
1999
4.6
15.3
9.1
6.1
719
0.2
2000
4.3
12.8
7.7
5.1
658
1.0
2001
4.3
17.9
10.7
7.1
802
1.0
-------
Federal No. 2 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.6 1.2 1.7
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 4.3% 8.6% 12.9%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.0% 2.0 3.0
Power Generation Potential
Utility Electric Supplier: Monongahela Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 38.7 146.4
Mine Electricity Demand: 30.4 117.1
Prep Plant Electricity Demand: 8.3 29.3
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 13.5 118.5
Assuming 40% Recovery Efficiency: 27.1 237.1
Assuming 60% Recovery Efficiency: 40.6 355.6
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 1.3
Assuming 40% Recovery (Bcf): 2.6
Assuming 60% Recovery (Bcf): 3.9
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 10.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments: Planned DOE Co-funded CMM Power Project
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Eagle
Current Owner: Peabody Energy
Parent Company: Peabody Energy
Previous Owner(s): Hanson PLC
Status: Active
Harris No. 1 Mine
GEOGRAPHIC DATA
State: WV
County: Boone
CORPORATE INFORMATION
Parent Company Web Site: vwwv.peabodyenergy.com
Previous or Alternate Name of Mine:
Contact Name: Harry Stover
Mailing Address: HCR 78, Box 113
City: Morton
Number of Employees at Mine: 364
Year of Initial Production: 1966
Life Expectancy: 2005
Prep Plant Located on Site? No
Depth to Seam (ft): 310
MINE ADDRESS
Phone Number: (304) 247-6211
State: WV
ZIP 25208
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 0.88% - 0.92%
BTUs/lbof Coal Produced: 12,600
Seam Thickness (ft): 6.0
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
2.5
0.7
0.7
0.0
101
1998
3.6
0.7
0.7
0.0
67
1999
3.0
0.6
0.6
0.0
74
2000
3.9
0.8
0.8
0.0
70
2001
3.9
1.1
1.1
0.0
106
-------
Harris No. 1 Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 0.4% 0.7% 1.1%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2 0.3
Power Generation Potential
Utility Electric Supplier: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
MW GWh/year
Total Electricity Demand (2001 data): 29.1 110.1
Mine Electricity Demand: 22.8 88.1
Prep Plant Electricity Demand: 6.3 22.0
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.8 7.1
Assuming 40% Recovery Efficiency: 1.6 14.2
Assuming 60% Recovery Efficiency: 2.4 21.3
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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? Yes
Owner of Nearest Pipeline: Columbia Gas Transmission Co.
Distance to Pipeline (miles): <1.0 Pipeline Diameter 8.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Powellton, Buffalo Creek
Current Owner: Independence Coal Co.
Parent Company: Massey Energy Co.
Previous Owner(s):
Status: Active
Justice #1
GEOGRAPHIC DATA
State: WV
County: Boone
CORPORATE INFORMATION
Parent Company Web Site: vwwv.masseyenergyco.com
Previous or Alternate Name of Mine:
Contact Name: Dwayne Francisco, Pres.
Mailing Address: HC 78, Box 1800
City: Madison
Number of Employees at Mine: 117
Year of Initial Production: NA
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (180)076-6132
State: WV
ZIP 25130
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 12,600
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.3
0.2
0.2
0.0
333
1998
0.8
0.4
0.4
0.0
171
1999
1.8
1.4
1.4
0.0
283
2000
3.0
2.0
2.0
0.0
245
2001
3.0
2.5
2.5
0.0
275
-------
Justice #1 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 0.9% 1.9% 2.8%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.2% 0.4 0.7
Power Generation Potential
Utility Electric Supplier: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
MW GWh/year
Total Electricity Demand (2001 data): 26.7 100.9
Mine Electricity Demand: 20.9 80.7
Prep Plant Electricity Demand: 5.7 20.2
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 1.9 16.8
Assuming 40% Recovery Efficiency: 3.8 33.6
Assuming 60% Recovery Efficiency: 5.7 50.4
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 8.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Loveridge No. 22
GEOGRAPHIC DATA
State: WV
County: Marion
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: None
Contact Name: John Higgins
Mailing Address: P.O. Box 40
City: Fairview
Number of Employees at Mine: 184
Year of Initial Production: 1953
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 1250
MINE ADDRESS
Phone Number: (304) 285-2223
State: WV
ZIP 26570
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.69%
BTUs/lbof Coal Produced: 13,175
Seam Thickness (ft): 7.8
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 40%
Drainage System Used: Vertical Gob, Horizontal Pre-Mine
1997
4.8
6.8
4.1
2.7
308
0.2
1998
5.4
10.1
6.1
4.0
406
0.0
1999
1.1
0.0
0.0
0.0
0
0.0
2000
0.0
2.7
2.7
0.1
0.0
2001
0.0
5.8
3.5
2.3
1101
0.0
-------
Loveridge No. 22 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 6.0% 12.0% 17.9%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 1.4% 2.8 4.2
Power Generation Potential
Utility Electric Supplier: Monongahela Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 9.1 34.4
Mine Electricity Demand: 7.1 27.5
Prep Plant Electricity Demand: 2.0 6.9
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 4.4 38.3
Assuming 40% Recovery Efficiency: 8.7 76.6
Assuming 60% Recovery Efficiency: 13.1 114.9
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.4
Assuming 40% Recovery (Bcf): 0.8
Assuming 60% Recovery (Bcf): 1.3
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 10.0
Owner of Next Nearest Pipeline: Kentucky West Virginia Gas Company
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter 6"
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): Consolidation Coal Co.
Status: Active
Me Elroy Mine
GEOGRAPHIC DATA
State: WV
County: Marshall
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Dave Eraskovich, Supt.
Mailing Address: Rd. 4, Box 425
City: Moundsville
Number of Employees at Mine: NA
Year of Initial Production: 1968
Life Expectancy:
Prep Plant Located on Site? Yes
Depth to Seam (ft): 600-1200
MINE ADDRESS
Phone Number: (304) 843-3700
State: WV
ZIP 26041
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 3.98% -4.42%
BTUs/lbof Coal Produced: 12,300
Seam Thickness (ft): 5.0 - 5.4
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
5.2
5.7
4.6
1.1
324
0.0
1998
6.6
5.5
4.6
0.8
254
0.0
1999
7.0
8.0
6.8
1.2
355
0.0
2000
6.8
6.4
6.4
0.0
345
0.0
2001
6.8
6.9
6.9
0.0
382
0.0
-------
Me Elroy Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data) 20% 40% 60%
CO2 Equivalent of CH4 Emissions Reductions (mm tons) 0.2 0.4 0.7
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion: 1.3% 2.7% 4.0%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.6 0.9
Power Generation Potential
Utility Electric Supplier: Wheeling Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
MW GWh/year
Total Electricity Demand (2001 data): 52.3 198.0
Mine Electricity Demand: 41.1 158.4
Prep Plant Electricity Demand: 11.2 39.6
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 5.2 45.8
Assuming 40% Recovery Efficiency: 10.5 91.6
Assuming 60% Recovery Efficiency: 15.7 137.4
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.5
Assuming 40% Recovery (Bcf): 1.0
Assuming 60% Recovery (Bcf): 1.5
Description of Surrounding Terrain: High Hills/Hills
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Columbia Gas Transmission Co.
Distance to Pipeline (miles): 0.0 Pipeline Diameter 10.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: Ohio Power Kammer Plant Distance to Plant (miles): 10.0
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Robinson Run No. 95
GEOGRAPHIC DATA
State: WV
County: Harrison
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: No. 95
Contact Name: Jimmy Brock
Mailing Address: Rte. 2, P.O. Box 152
City: Mannington
Number of Employees at Mine: NA
Year of Initial Production: 1968
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 700
MINE ADDRESS
Phone Number: (304) 795-4421
State: WV
ZIP 26582
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 2.95% - 3.14%
BTUs/lbof Coal Produced: 13,100
Seam Thickness (ft): 6.5
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 20%
Drainage System Used: Vertical Gob, Horizontal Pre-Mine
1997
4.8
5.1
3.1
2.1
235
0.0
1998
5.6
5.1
3.1
2.0
201
0.0
1999
5.3
6.9
4.1
2.8
284
0.0
2000
6.0
5.1
4.1
1.0
247
0.0
2001
6.0
5.0
4.0
1.0
300
0.0
-------
Robinson Run No. 95 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 1.2% 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: Monongahela Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 38.9 147.3
Mine Electricity Demand: 30.6 117.8
Prep Plant Electricity Demand: 8.4 29.5
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 3.8 33.4
Assuming 40% Recovery Efficiency: 7.6 66.9
Assuming 60% Recovery Efficiency: 11.5 100.3
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 10.0
Owner of Next Nearest Pipeline: Consolidated Gas Supply
Distance to Next Nearest Pipeline (miles): 3.0 Pipeline Diameter 12.0
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: Harrison Distance to Plant (miles): 3.0
Comments: Located Near Power Plant
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Kittanning
Current Owner: Philippi Development, Inc.
Parent Company: Anker Energy
Previous Owner(s):
Status: Active
Sentinel Mine
GEOGRAPHIC DATA
State: WV
County: Barbour
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine: Ryanstone #1
Contact Name: Robby Mundy
Mailing Address: Rte. 3, Box 146
City: Philippi
Number of Employees at Mine: 182
Year of Initial Production: 1974
Life Expectancy: 2013
Prep Plant Located on Site? Yes
Depth to Seam (ft): 425
MINE ADDRESS
Phone Number: (304) 457-1895
State: WV
ZIP 26416
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam, Metallurgical
Sulfur Content of Coal Produced: 0.96% -1.34%
BTUs/lbof Coal Produced: 13,234
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used: None
1997
1.1
2.2
2.2
0.0
744
1998
1.0
2.5
2.5
0.0
875
1999
0.9
1.7
1.7
0.0
689
2000
0.5
1.6
1.6
0.0
1177
2001
0.5
1.4
1.4
0.0
1208
-------
Sentinel Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 3.9% 7.8% 11.8%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.9% 1.8 2.7
Power Generation Potential
Utility Electric Supplier: Philippi Municipal Electric
Parent Corporation of Utility: Municipal Owned
MW GWh/year
Total Electricity Demand (2001 data): 3.3 12.3
Mine Electricity Demand: 2.6 9.9
Prep Plant Electricity Demand: 0.7 2.5
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 1.0 9.0
Assuming 40% Recovery Efficiency: 2.1 18.1
Assuming 60% Recovery Efficiency: 3.1 27.1
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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 Low Mountains
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Hope Gas
Distance to Pipeline (miles): 0.5 Pipeline Diameter NA
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Pittsburgh
Current Owner: Consol Energy Inc.
Parent Company: Consol Energy Inc.
Previous Owner(s): None in last 10 years
Status: Active
Shoemaker Mine
GEOGRAPHIC DATA
State: WV
County: Marshall
CORPORATE INFORMATION
Parent Company Web Site: vwwv.consolenergy.com
Previous or Alternate Name of Mine: None
Contact Name: Rock Harris
Mailing Address: Rd. 1 Box 62 A
City: Dallas
Number of Employees at Mine: NA
Year of Initial Production: NA
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): 650
MINE ADDRESS
Phone Number: (304) 243-4200
State: WV
ZIP 26036
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 3.3%
BTUs/lbof Coal Produced: 12,172
Seam Thickness (ft): 5.0-5.5
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 15%
Drainage System Used: Vertical Gob
1997
4.8
4.8
4.1
0.7
310
0.0
1998
4.8
5.1
4.3
0.8
325
0.0
1999
4.4
5.2
4.4
0.8
364
0.0
2000
3.6
4.3
3.6
0.6
370
0.0
2001
3.6
4.2
3.5
0.6
316
0.0
-------
Shoemaker Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 1.3% 2.6% 3.9%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.3% 0.6 0.9
Power Generation Potential
Utility Electric Supplier: Wheeling Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
MW GWh/year
Total Electricity Demand (2001 data): 32.4 122.6
Mine Electricity Demand: 25.4 98.1
Prep Plant Electricity Demand: 7.0 24.5
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 3.2 27.7
Assuming 40% Recovery Efficiency: 6.3 55.3
Assuming 60% Recovery Efficiency: 9.5 83.0
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data) Bcf
Assuming 20% Recovery (Bcf): 0.3
Assuming 40% Recovery (Bcf): 0.6
Assuming 60% Recovery (Bcf): 0.9
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 10.0
Owner of Next Nearest Pipeline: NA
Distance to Next Nearest Pipeline (miles): NA Pipeline Diameter NA
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003
Basin: Central Appalachian
Coalbed: Eagle, Powellton
Current Owner: Performance Coal Co.
Parent Company: Massey Energy Co.
Previous Owner(s):
Status: Active
Upper Big Branch - South
GEOGRAPHIC DATA
State: WV
County: Raleigh
CORPORATE INFORMATION
Parent Company Web Site: vwwv.masseyenergyco.com
Previous or Alternate Name of Mine: None
Contact Name: Homer Wallace
Mailing Address: P.O. Box 69
City: Naoma
Number of Employees at Mine: 216
Year of Initial Production: NA
Life Expectancy: 2018
Prep Plant Located on Site? Yes
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (304) 854-3308
State: WV
ZIP 25140
GENERAL INFORMATION
Mining Method: Longwall/Continuous
Primary Coal Use: Metallurgical
Sulfur Content of Coal Produced: NA
BTUs/lbof Coal Produced: 12,600
Seam Thickness (ft): NA
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
4.6
0.5
0.5
0.0
42
1998
5.7
0.8
0.8
0.0
53
1999
5.1
1.0
1.0
0.0
70
2000
4.0
1.2
1.2
0.0
108
2001
4.0
1.0
1.0
0.0
125
-------
Upper Big Branch - South (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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: 0.4% 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: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
MW GWh/year
Total Electricity Demand (2001 data): 23.4 88.4
Mine Electricity Demand: 18.3 70.7
Prep Plant Electricity Demand: 5.0 17.7
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.8 6.7
Assuming 40% Recovery Efficiency: 1.5 13.4
Assuming 60% Recovery Efficiency: 2.3 20.1
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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: Columbia Gas Transmission Co.
Distance to Pipeline (miles): < 3.0 Pipeline Diameter 8.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
Updated: 04/01/2003 Status: Active
US Steel 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: vwwv.uss.com/ussteel/index.html
Previous Owner(s): None in last 10 years Previous or Alternate Name of Mine: Gary No. 50, Pinnacle No.
MINE ADDRESS
Contact Name: Jack Shroder, GM Pinnacle Phone Number: (304) 732-5200
Mailing Address: P.O. Box 338
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: 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
1997 1998 1999 2000 2001
Coal Production (million short tons/year): 5.0 4.8 3.9 3.7 3.7
Estimated Total Methane Liberated (million cf/day): 14.0 18.0 18.4 16.0 16.6
Emission from Ventilation Systems: 9.7 12.9 14.8 11.0 9.5
Estimated Methane Drained: 4.3 5.0 3.7 5.0 7.1
Estimated Specific Emissions (cf/ton): 713 974 1388 1094 1100
Methane Recovered (million cf/day): 2.8 1.4 2.3 3.5 5.6
Estimated Current Drainage Efficiency: 43%
Drainage System Used: Directional Pre-Mine, Vertical Gob, Horizontal Pre-Mine
-------
US Steel No. 50 (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 Data)
CO2 Equivalent of CH4 Emissions Reductions (mm tons)
CO2 Equivalent of CH4 Emissions Reductions/CO2
Emissions from Coal Combustion:
BTU Value of Recovered Methane/BTU Value of Coal Produced:
Power Generation Potential
Utility Electric Supplier: Appalachian Power Co.
Parent Corporation of Utility: American Electric Power Co., Inc.
Total Electricity Demand (2001 data):
Mine Electricity Demand:
Prep Plant Electricity Demand:
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency:
Assuming 40% Recovery Efficiency:
Assuming 60% Recovery Efficiency:
Pipeline Sales Potential
Potential Annual Gas Sales (2001 data)
Assuming 20% Recovery (Bcf):
Assuming 40% Recovery (Bcf):
Assuming 60% Recovery (Bcf):
Description of Surrounding Terrain: Low Mountains
Transmission Pipeline in County? Yes
Owner of Nearest Pipeline: Mine owns pipeline that connects to trans, line
Pipeline Diameter
20%
0.5
5.6%
1.3%
40%
1.1
11.1%
2.6
60%
1.6
16.7%
3.9
Distance to Pipeline (miles): 0.0
Owner of Next Nearest Pipeline: Cabot
Distance to Next Nearest Pipeline (miles): 0.5
MW
24.9
19.5
5.3
12.6
25.1
37.7
GWh/vear
94.2
75.3
18.8
110.0
220.1
330.1
Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: None
Comments: Utilizes CDX Gas' Pinnate Technology to Recovery CBM
Bcf
1.2
2.4
3.6
NA
NA
Distance to Plant (miles): NA
-------
Updated: 04/01/2003
Basin: Northern Appalachian
Coalbed: Kittanning
Current Owner: Coastal Coal Co.
Parent Company: El Paso Corporation
Previous Owner(s): Kingwood Coal Co.
Status: Active
Whitetail Kittanning Mine
GEOGRAPHIC DATA
State: WV
County: Preston
CORPORATE INFORMATION
Parent Company Web Site:
Previous or Alternate Name of Mine:
Contact Name: Richard L. Craig
Mailing Address: Rte. 1, Box249C
City: Newburg
Number of Employees at Mine: 209
Year of Initial Production: NA
Life Expectancy:
Prep Plant Located on Site? No
Depth to Seam (ft): NA
MINE ADDRESS
Phone Number: (304) 568-2460
State: WV
ZIP 26410
GENERAL INFORMATION
Mining Method: Continuous
Primary Coal Use: Steam
Sulfur Content of Coal Produced: 1.5% -1.7%
BTUs/lbof Coal Produced: 13,150
Seam Thickness (ft):
PRODUCTION, VENTILATION AND DRAINAGE DATA
Coal Production (million short tons/year):
Estimated Total Methane Liberated (million cf/day):
Emission from Ventilation Systems:
Estimated Methane Drained:
Estimated Specific Emissions (cf/ton):
Methane Recovered (million cf/day):
Estimated Current Drainage Efficiency: 0%
Drainage System Used:
1997
0.0
0.0
0.0
0.0
1998
0.0
0.0
0.0
0.0
1999
0.0
0.0
0.0
0.0
2000
0.3
0.1
0.1
0.0
158
2001
0.3
0.9
0.9
0.0
142
-------
Whitetail Kittanning Mine (continued)
ENERGY AND ENVIRONMENTAL VALUE OF EMISSIONS REDUCTIONS
Assumed Potential Recovery Efficiency
(Based on 2001 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% 0.9% 1.4%
BTU Value of Recovered Methane/BTU Value of Coal Produced: 0.1% 0.2 0.3
Power Generation Potential
Utility Electric Supplier: Monongahela Power Co.
Parent Corporation of Utility: Allegheny Power Systems, Inc.
MW GWh/year
Total Electricity Demand (2001 data): 18.9 71.5
Mine Electricity Demand: 14.8 57.2
Prep Plant Electricity Demand: 4.1 14.3
Potential Generating Capacity (2001 data)
Assuming 20% Recovery Efficiency: 0.7 6.2
Assuming 40% Recovery Efficiency: 1.4 12.3
Assuming 60% Recovery Efficiency: 2.1 18.5
Pipeline Sales Potential
Potential Annual Gas Sales (2001 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: Columbia Gas Transmission Co.
Distance to Pipeline (miles): -10.0 Pipeline Diameter 10.0
Owner of Next Nearest Pipeline:
Distance to Next Nearest Pipeline (miles): Pipeline Diameter
Other Utilization Possibilities
Name of Nearby Coal Fired Power Plant: NA Distance to Plant (miles): NA
Comments:
-------
7. References
Alabama Oil & Gas, 2002, http://www.ogb.state.al.us/
CONSOL 1997. Notes taken by LB. 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.
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.
IPCC (Intergovernmental Panel on Climate Change) 1997. Revised 1996IPCC Guidelines for National
Greenhouse Gas Inventories. Japan. 1997
Keystone. 1997-2001. Keystone Coal Industry Manual. Years 1997, 1998, 1999, 2000 and 2001. 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. 2002. Mine Safety and Health Administration listing of ventilation emissions from coal mines for
1997 - 2001, 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/ Foss/7 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). 1993a. Anthropogenic Methane Emissions in the United
States: Estimates for 1990. Report to Congress. Office of Air and Radiation (6202J). EPA430-R-
93-003. April 1993.
-------
USEPA (U.S. Environmental Protection Agency). 1993b. 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) 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 fora 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). 2003a. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2001, Office of Atmospheric Programs, EPA/430/R-03/004. April 2003.
USEPA (U.S. Environmental Protection Agency). 2003b. Assessment of the Worldwide Market Potential for
Oxidizing Coal Mine Ventilation Air Methane, EPA/430/R-03/002. July 2003.
-------
References and Calculations Used in the Mine Profiles
Data Item
Geographic Data (State,
County, Basin,
Coalbed)
Corporate Information:
Current Owner
Previous Owner
Parent Company
Phone/Address/Contact
Information
General Information:
Number of
Employees
Year of Initial
Production
Life Expectancy:
Sulfur Content
Mining Method
Primary Use
Production, Ventilation,
and Drainage Data
Coal Production
Emissions from
Ventilation
Systems
Estimated
Methane Drained
Sources
Keystone (2002)
Past versions of Keystone Coal
Manual and recent coal industry
publications
Past versions of Keystone Coal
Manual and Coal Magazine Annual
Longwall Surveys
Past versions of Keystone Coal
Manual and recent coal industry
publications
Past versions of Keystone Coal
Manual and EIA reports.
Past versions of Keystone Coal
Manual
MSHA; Past versions of Keystone
Coal Manual and articles in coal
industry publications
Past versions of Keystone Coal
Manual
Past versions of Keystone Coal
Manual
Past versions of Keystone Coal
Manual and Coal Magazine
Longwall Survey
Past versions of Keystone Coal
Manual
MSHA (2002)
MSHA (1997 -2002)
The number of mines assumed to
have drainage systems is based on
calls to individual MSHA districts.
Calculations
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
Estimated
Current Drainage
Efficiency
Based on calls to individual MSHA
districts offices.
Assumed to be 40% unless otherwise
noted for mines where the drainage
efficiency is known.
Energy and
Environmental Value
CO2 Equivalent
of Methane
Emissions
Reductions (mm
tons)
CO2 Equivalent
of Methane
Emissions
Reductions/CO2
Emissions from
Coal Combustion
Global Warming Potential of
Methane Compared to CO2 based
on IPCC (1997). GWP is 21 over
100 years.
CO2/BTU ratio based on average
state values in EIA (1992)
Estimated 2001 CH4 liberated (mmcf) x
recovery efficiency x 19.2 g/cf x21 g
C02/1 g CH4 x 1 Ib / 453.59 g x 1 ton /
2000 Ibs
Fraction = [CO2 equivalent of CH4
emissions reductions
(Ibs)]/[1996 coal
production (tons) x
BTUs/ton x CO2 emitted
Ibs/BTU x 99% (fraction
oxidized)
BTU Value of
Recovered
Methane/BTU
Value of Coal
Produced
BTU/ton value for coal production
based on information in Keystone
or on average state values from
EIA (2002)
Fraction = [2001 CH4 liberated
(cf/yr) x rec. efficiency x
1000 BTUs/cf]/ [1996
coal production (tons) x
BTUs/ton]
Power Generation
Potential
Electricity
Supplier
Potential Electric
Generating
Capacity
Mine Electricity
Demand
Directory of Electric Utilities
Mine electricity needs (24 kwh/ton)
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/11000BTUs
Demand (MW) = Demand from
Ventilation Systems + Demand
from Mine Operations
+ Demand from Prep Plant
Demand (MW) ventilation systems =
[25% x24 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
(2002) 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
Gas Sales
All other
information
Estimated methane liberated (mmcf/d) x
365 days/yr x recovery efficiency
ICF Resources (1990b)
Other Utilization
Potential
Name of Coal
Fired Boiler
Located Near
Mine (if any)
Distance to
Boiler
Electric Power (2001)
Electric Power (2001)
------- |