"United States
Environmental Protection
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Air and
Radiation
6202J
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EPA/430/R-94/007
April 1994
Tlie Environmental and \
Economic Benefits of Coalbed
Methane Development in the
Appalachian Region
Washington, DC 20460
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1007
The Environmental
and Economic Benefits of
Coalbed Methane Development
in the Appalachian Region
April 1994
Dina W. Kruger
Global Change Division
Office of Air and Radiation
U.S. Environmental Protection Agency
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Table of Contents
Executive Summary 1
1. Introduction 2
2. The Importance of Reducing Methane Emissions 3
3. Overview of U.S. Coalbed Methane Development 6
3.1 Key Coalbed Methane Producing Regions 7
3.2 Methane Recovery at Coal Mines 9
4. Coalbed Methane in the Appalachian Basin 13
4.1 Production Potential . 13
4.2 Production Scenarios 14
5. Uses of Coalbed Methane in Appalachia 15
5.1 Pipeline Injection 15
5.2 Power Generation . . . .' 16
5.3 Direct Industrial Use 17
6. The Benefits of Appalachian Coalbed Methane Development 17
6.1 Methodology 17
6.2 Employment Benefits ; '. 19
6.3 Revenue Benefits 20
6.4 Environmental Benefits 21
7. Encouraging Coalbed Methane Development 21
7.1 Address the Ownership of Coalbed Methane 21
7.2 Provide a Financial Incentive for Methane Recovery at Coal Mines 22
7.3 Encourage Electric Utilities to Support Power Generation 24
7.4 Identify-and Promote Direct Use Options 26
7.5 Identify and Remove Barriers to Pipeline Sale 26
7.6 Develop Links to Other Climate Change Actions 27
7.7 Foster Appropriate State and Federal Regulatory Frameworks 28
8. Summary and Conclusions 28
9. References 29
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List of Figures
Figure 1: U.S. Anthropogenic Methane Emissions, by' Source
Figure 2: 1988 Methane Emissions from Coal' Mining
Figure 3: Emissions Reductions, by Source
Figure 4: Coalbed Methane Production, 1980-1992
Figure 5: Map of U.S. Coal Basins .
Figure 6: Methods for Recovering Methane from Underground Coal Mines
4
. 4
5
6
7
11
List of Tables
Table 1: Summary of Methods for Recovering Methane from Underground Mines
Table 2: Methane Recovery at Selected U.S. Underground Mines
Table 3: Coalbed Methane Characteristics of the Appalachian and Black Warrior Basins
Table 4: Appalachian Coalbed Methane Scenarios
Table 5: Utilization Options for Coalbed Methane
Table 6: U.S. Coalbed Methane Production Forecasts by State
Table 7: State Revenue Policies
Table 8: Estimated Employment Associated with Coalbed Methane Production .
Table 9: Estimated State Revenues Associated with Coalbed Methane Production ....
10
12
14
14
15
18
19
20
20
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Executive Summary
Development of the Appalachian Basin's large coalbed methane resources could result in
significant regional economic benefits, as well as reduce emissions of methane to the
atmosphere. Coal mines in the Appalachian region are some of the gassiest in the United States,
with underground mines releasing an estimated 120 to 200 billion cubic feet (Bcf) of methane in
1988. The waste of methane from coal mines in the Appalachian region could be significantly.
reduced if key barriers to methane recovery and use were removed and appropriate incentives
provided. Such projects could improve the profitability of the mining operations, benefit the
environment, and strengthen regional employment and revenue bases.
The technologies for producing methane from coal seams have been economically demonstrated
in other U.S. regions over the last decade and are readily transferrable to the Appalachian Basin.
With currently available technology, it is feasible to produce large amounts of coalbed methane
in the Appalachian region. An estimated 50 to 90 Bcf of methane could be cost-effectively
produced in 2000, for example.
Aggressive development of coalbed methane in the Appalachian region will create numerous jobs
and generate revenue for state governments. At projected production levels, an estimated 2,000
to 3,000 jobs could be created by 2000 and more than 7,500 jobs could be created by 2010.
In addition, state governments could realize revenues of $6 million or more in 2000 and $20 to
$25 million in 2010.
The recovery of coalbed methane by coal mines will also have important environmental benefits,
since methane is a potent greenhouse gas. Much of the methane currently.liberated and wasted
by coal mines could be cost-effectively recovered and used. In 2000, for example, methane
reductions of 50 to 115 Bcf could be profitable in the United States, and reductions of 20 to 35
Bcf could be profitable in the Appalachian region. If all profitable emission reductions are
achieved in 2000, moreover, methane emissions from coal mines could be reduced by more than
25 percent.
Given the many benefits of coalbed methane development, states and the Federal government
should work together to encourage the development of this resource in the Appalachian region.
Under President Clinton's Climate Change Action Plan, which was released in October 1993, the
Federal government will undertake two major initiatives to encourage the development of coalbed
methane projects at U.S. coal mines. The U.S. Environmental Protection Agency (EPA) will
implement the Coalbed Methane Outreach Program, aimed at identifying profitable methane
emission reduction projects at U.S. mines and removing the barriers to their development. The
U.S. Department of Energy (DOE) will implement the Coal Mine Methane Research, Development,
and Deployment (RD&D) program, which will demonstrate new technologies for expanding
methane recovery and use at coal mines.
EPA's Coalbed Methane Outreach Program recognizes that widespread coalbed methane
development will not occur in the Appalachian region-unless legal, regulatory, and other barriers
are addressed and the multiple benefits of such projects are widely publicized. Among the most
important issues to be addressed are:
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• Coalbed Methane Ownership: Under Section 1339 of the 1992 Energy Policy Act, the
U.S. Bureau of Land Management (BLM) is promulgating regulations to encourage
coalbed methane development in states where uncertain coalbed methane ownership
provisions have constrained coalbed methane development. Affected states-those states
that do not have mechanisms for allowing coalbed methane development-have until
October 1995 to enact coalbed methane development legislation. Those that do not
enact state-level legislation will become subject to Federal legislation administered by the
BLM. The Federal legislation will facilitate coalbed methane development through "forced
pooling" provisions modelled on the 1990 Virginia Oil and Gas Act. Experience in Virginia
indicates that developing a mechanism to address coalbed methane ownership claims
will lead to coalbed methane development.
• Development of Utilization Options for Methane Recovery at Coal Mines: Methane
recovered by coal mines can be used in numerous ways, including pipeline sales,
electricity generation, direct use at the mine or in nearby industries, and as a chemical
feedstock or transportation fuel. Lack of familiarity with these options, on the part of both
the producing mine and its potential project partners (for example, gas transmission
companies or electric utilities) may limit project development. In addition, institutional
barriers, inappropriate regulatory frameworks, and other legal or operational issues may
be obstacles to project development. In certain regions, for example, utilities may
discourage projects for generating electricity at coal mines. These types of obstacles
must be identified on a case-by-case'basis and addressed through Federal, state and
local actions to promote coalbed methane recovery.
* . Outreach on Project Benefits: A third necessary action is outreach on the benefits of
coalbed methane recovery projects at coal mines. The audiences for such outreach
should include the coal industry, gas transmission companies, electric utilities, and
Federal, state and local government agencies.
It may also be desirable to provide incentives to overcome, initial technical uncertainty and
perceived project risks related to coalbed methane development in the Appalachian region
(where development has lagged), particularly at coal mines. A tax credit of $0.50 per thousand
cubic feet (mcf) of methane (roughly equivalent to $5 per ton of carbon equivalent) could
increase recovery from mining operations by an estimated 10 Bcf in 2000 and 15 Bcf in 2010, in
addition to encouraging additional production in non-mining areas. If the value of carbon
reductions is $20 per ton of carbon equivalent, the equivalent value for methane would be $2.30
per mcf and additional methane reductions of 20 Bcf could be obtained in 2000.
1. Introduction
Coalbed methane development presents the Appalachian region with an attractive opportunity
to unite the goals of economic development and environmental protection. The Appalachian
region has large coalbed methane resources, but development has lagged behind other U.S.
regions due to a variety of barriers. As a result, the region's clean-burning coalbed methane
resources remain untapped, and every year coal mines waste millions of dollars worth of gas by
venting it to the atmosphere.
The technologies exist for developing the Appalachian region's coalbed methane resources. At
many Appalachian coal mines, methane routinely recovered by mine degasification systems and
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vented to the atmosphere could be profitably collected and used as fuel. Unless actions are
taken to remove existing barriers, however, these types of projects will not be developed and the
wasteful venting of a non-renewable resource will continue.
This study investigates the potential for coalbed methane development in the Appalachian region,
at coal mines and in non-mining areas, and it evaluates the many benefits associated with such
projects. Among the benefits quantified in this study are increased employment, additional state
revenues, and lower emissions of methane, a potent greenhouse gas. In addition, because the
projects are cost-effective, coal mines and other companies that develop them will realize a return
on their investments.
The study also focuses on the barriers to coalbed methane development in the Appalachian
region, which include uncertain ownership of coalbed methane resources, limited access to
natural gas and/or electricity transmission lines, unwillingness on. the part of electric utilities or
natural gas companies to participate in or support coaibed methane development projects, lack
of awareness of the benefits of resource development at all levels, and other regulatory issues.
Activities are underway to address many of these barriers, and with continued progress the full
potential for coalbed methane development could be realized by the year 2000. A number of
options for overcoming these barriers are presented for consideration by states and the Federal
government.
2. The importance of Reducing Methane Emissions
Projects to recover coalbed methane at coal mines in the Appalachian region are desirable for
many reasons, including the potential to reduce emissions of methane, a potent greenhouse gas.
In recent years, the atmospheric concentration of methane has been increasing at a rapid rate,
with concentrations more than doubling over the last two centuries (IPCC, 1990). This increase
in atmospheric concentrations is believed-to be related to increasing emissions from various
human sources, and it is serious because methane is considerably more potent than carbon
dioxide as a greenhouse gas. Methane is about 20 times more effective at trapping heat in the
atmosphere than carbon dioxide over a 100 year time period (USEPA, 1993a).1 The higher
potency of methane, combined with its shorter atmospheric lifetime, mean, that reducing
methane's atmospheric concentration will have a rapid impact on mitigating potential climate
change.
Coal mining is one of several human sources of methane. Globally, coal mining activities are
estimated to account for about 10 percent of the methane emissions associated with human
activities (USEPA, 1994). In the United States, however, coal mines represent a larger share of
human-related methane emissions. As shown in Figure 1, recent estimates indicate that coal
mines accounted for about 15 to 20 percent of total emissions in 1990, making this source the
third largest in the United States, after landfills and domesticated livestock (USEPA, 1993a).
The major source of methane emissions from coal mines are underground mines, which tend to
emit more methane than surface mines because the coal is buried more deeply and is gassier.
As shown in Figure 2, underground mines accounted for an estimated 70 to 80 percent of coal
1 Methane is reported with a direct global warming potential (GWP) of 11 over a 100-year time frame and with
Indirect effects that could be comparable in magnitude^ its direct effects (IPCC, 1992). The GWP reflects the
effect that releasing a kilogram of methane would have over a specified time horizon, relative to releasing a
kilogram of carbon dioxide.
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Figure 1
U.S. Anthropogenic Methane Emissions, by Source
Domestic
Livestock
21%
Landfills
36%
10%
Natural Gas
Systems
17%
Coal Mining
Other
Sources
10%
Livestock
Manure
Source: USEPA, 1993a
mine methane emissions in 1988. About two-thirds of this methane was emitted in very low
concentrations in mine ventilation air. The remaining one-third of emissions, an estimated 25 to
95 Bcf of methane, was emitted by mine degasification systems (USEPA, 1993a). There is
uncertainty in the level of emissions from degasification systems because U.S. mines are not
required to report their emissions from these systems to government agencies. This methane
is recovered in higher concentrations and may be suitable for use as fuel.
Figure 2
1988 Methane Emissions from Coal Mining
Underground
Vent i I at ion
Under-ground
Degas If i cat ion
Systems
In 1988, coal mines in the Appalachian region
were the largest emitters of methane from this
source. USEPA estimates that underground
mines in this region accounted for about 50
percent of U.S. methane emissions from coal
mining, emitting an estimated 120 to 200 Bcf
of methane in 1988, of which an estimated 20
to 75 Bcf was produced by mine
degasification systems. (USEPA, 1993a).
In the future, the emissions associated with
coal mining in the Appalachian region are
expected to become even more significant.
By 2000, this region is projected to represent
about two-thirds of U.S. emissions from this
source. Degasification system emissions from
Appalachian mines could also increase, ranging from 20 to 85 Bcf in 2000 and 25 to 110 Bcf in
2010 (USEPA, 1993a).
Another EPA study estimates that 50 to 115 Bcf of methane emitted in by U.S. coal mines could
be cost-effectively recovered in 2000, associated with projects at as many as 25 coal mines
(USEPA, 1993b). These reductions would represent more than a 25 percent reduction in
methane emissions from coal mining, and would account for an estimated 10 to 20 percent of
Po-st.-Mi ni
Surface Mines
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the cost-effective methane reductions from a variety of sources in the United States, as shown
in Figure 3. In addition to the 25 Bcf of methane being recovered by existing projects at 11 U.S.
coal mines, another 15 coal mines could develop profitable projects. It is anticipated that
Appalachian mines would undertake most of these projects, and the additional methane emission
reductions. EPA estimates that profitable projects could be developed at 25 to 30 coal mines
in 2010, and that anywhere from 85 to 160 Bcf of methane could be produced as a result.
Landfills
57%
15%
Coal
6%
Livestock
Manure
7%
Natural Gas
15%
Livestock
Source: USEPA, 1993a
These reductions will represent an integral part of any plan to reduce greenhouse gas emissions
and mitigate global warming. Under the President's Climate Change Action Plan, for example,
programs to reduce methane emissions in 2000 account for 15 percent of the greenhouse gas
emission reductions required to stabilize emissions at 1990 levels (CCAP, 1993). Voluntary
projects at coal mines.are the third largest source of methane emission reductions (after two
actions aimed at reducing methane emissions from landfills). Coal mine methane reductions
represent 20 percent of the methane emission reductions and three percent of the total
greenhouse gas emission reductions projected under the plan.
Achieving these methane emission reductions will require rapid action to address the barriers to
project development, however. EPA analysis indicates that although these projects are expected
to be economic, their development may be constrained unless certain barriers to methane
recovery and use are addressed. Actions to resolve one of the most important hurdles to
coalbed methane recovery and use in the Appalachian region-uncertain coalbed methane
ownership-is already underway as a result of the 1992 Energy Policy Act (H.R. 776, Section
1339). Other activities will be initiated by EPA as part of its Coalbed Methane Outreach Program,
mandated under the 1993 Climate Change Action Program. In addition, over the next several
years DOE will be working with industry.to, develop new technologies that should make even
larger methane reductions technically and economically feasible, as part of its program to expand
research and development for methane recovery from coal mining,
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3. Overview of U.S. Coalbed Methane Development
Coalbed methane is currently the fastest growing natural gas resource in the United States, with
production increasing from 11 Bcf in 1985 to about 550 Bcf in 1992. Although coalbed methane
represents only 3 percent of total U.S. gas'production, many of the gas wells drilled in recent
years have been coalbed methane wells. In 1990, moreover, recoverable resources of coalbed
methane were reported to be 145 Tcf, which represents a 61 percent increase over the 1989
resource estimate and almost 20 percent of total U.S. recoverable gas resources (PGC, 1990).
In addition, proven reserves were estimated at 5.1 Tcf in 1990, an increase of almost 40 percent
over 1989 (USEIA, 1991).
As shown in Figure 4, coalbed methane production has increased dramatically over the last five
years, and this growth is expected to continue in the future, albeit at a slightly lower level. The
Gas Research Institute (GRI) forecasts that.coalbed methane production in the United States
could reach almost 0.7 Tcf in 1995, 0.9 Tcf in 2000 and 1.5 Tcf in 2010 (GRI, 1994). With more
aggressive policies to encourage coalbed methane development, particularly in the Appalachian
region, it is possible that U.S. coalbed methane resources could be developed more rapidly and
that total production could be higher than projected by GRI.
Figure 4
U.S. Coalbed Methane Production, 1980-1992
Gas Production (Bcf/Yr)
600 -r-
500
400 •••
300 ••
200 .-
100 •-
(0.5) (0.7) (2) (5) <9>
1980 1981 1982 1983 1984 1985
1990 .1991 1992
I a San Juan D Warrior • Other
Source: USEIA, 1994
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3.1 Key Coalbed Methane Producing Regions
The United States has several coalbed methane producing regions, as shown in Figure 5. To
date, the Black Warrior Basin and the San Juan Basin have accounted for more than 90 percent
of U.S. coalbed methane production. These basins are expected to remain the major coalbed
methane producing regions, but other regions are also expected to become significant
producers. In particular, GRI projects major growth in production in the Appalachian and
Piceance basins (GRI, 1994).
Western Washington
24Tcf
Wind River
2 Tcf
Greater Green
River
31Tcf
Uinta
1Tcf
Piceance
84 Tcf
Powder River
39Tcf
TT
Northern Appalachian
61 Tcf
Central
Appalachian
S.Tcf
San Juan
88 Tcf
Raton Mesa
18 Tcf
Arkoma
4 Tcf
Warrior
20 Tcf
The Black Warrior Basin
The Black Warrior Basin (BWB) in Alabama is a significant coal producing region, and it contains
some of the gassiest coal mines in the United States. Coal production was 27 million tons in
1988, which represented about 7 percent of U.S. underground coal production {USEPA, 1993a).
Most of this coal was produced in gassy mines; in fact, six of the 10 gassiest U.S. coal mines
are located in the BWB. In addition to coal production,'the BWB is also a major coalbed
methane producer. Regional coalbed methane reserves are estimated at 20 Tcf (GRI, 1986). In
1992, coalbed methane production exceeded 90 Bcf, from more than 2,900 wells (GRI, 1993).
Coalbed methane production began in the BWB during the 1970's at several of the region's coal
mines. As a result of increasing depth and gassiness, these mines found that ventilation costs
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were becoming prohibitively expensive and that mining would become uneconomical without the
use of additional techniques to drain high-quality methane from the coal seams in conjunction
with mining operations. A variety of technologies were successfully employed, including pre-
mining drainage using surface wells, in-mine horizontal boreholes, and surface gob wells. These
methods are now also used in other U.S mining areas, including in the Appalachian region.
The recovery of methane has had many benefits for the BWB's coal industry. In addition to
enabling commercial mining of deeper seams, pipeline quality methane is being recovered and
sold, thus generating an additional source of revenue for the coal companies. Methane recovery
has also reduced mine ventilation costs and enabled mines to increase coal production rates.
Currently, Black Warrior Methane-the gas operator for the Jim Walter Resources coal mines-is
producing 33 million cubic feet of gas daily from a variety of conventional vertical coalbed
methane wells, gob wells and in-mine boreholes (GRI, 1993).
Experience with mine degasification in the BWB demonstrated the economic potential for coalbed
methane production and contributed to the development of the coalbed methane industry in non-
\ mining areas in Alabama. Other gas producers began developing the resource aggressively
during the 1980s, in operations that were independent of mining. These producers were
attracted to the BWB because of the magnitude of the coalbed methane resource and the
proximity to major natural gas pipelines with access to eastern markets. Today, these non-
mining gas producers are responsible for about 80 percent of the "region's coalbed methane
production, while mines produce the remaining 20 percent.
Over the past decade, coalbed methane production has grown to over 250 million cubic feet per
day in the BWB. This growth has had major economic benefits for the region. According to a
study prepared by the University of .Alabama, during the 1980s approximately 13,000 jobs were
created directly and indirectly as a result of coalbed methane production in the BWB (UAL, 1989).
The state also earned additional revenues, conservatively estimated to be $2 to $3 million in 1990
as a result of the coalbed methane industry (Boland, 1992). Along with Jim Walter Resources
and U.S. SteeMhe original mining companies that pioneered coalbed methane production-there
are another 16 gas operators currently producing coalbed methane in the BWB. Three of these-
Black Warrior Methane Corp., The River Gas Corp., and Taurus Exploration Inc.-accounted for
75 percent of production in 1992 (GRI, 1993).
The San Juan Basin
->.
The San Juan Basin, located in southern Colorado and northern New Mexico, is currently the
largest coalbed methane producing region in the United States, with over 30 companies
operating almost 2,000 wells (GRI, 1993). Total coalbed methane reserves in the basin are
estimated at 50 Tcf, and total production was almost 440 Bcf in 1992 (?? GRI, 1993a).
Production increased by 62 percent between 1991 and 1992 and has almost tripled since 1990.
In 1992, three operators-Amoco Production Company, Meridian Oil Inc., and Devon Energy
Corp.^accounted for almost 75 percent of coalbed methane production in the basin (GRI, 1993).
Unlike Alabama, none of this production is associated with coal mining because the coal seams
are too deeply buried to mine. Aggressive development of coalbed methane in the SJB. began
in 1980, and production has grown dramatically in the past few years, coinciding with Alabama's
coalbed methane boom and driven in part by the provision of the Section 29 unconventional gas
production tax credit. In fact, coalbed methane development in the SJB has outpaced available
pipeline capacity to move the gas to market, which has resulted in a regional gas glut and a
8
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decline in regional gas prices. Three projects are underway to increase pipeline capacity and
expand access to gas markets in the Midwest and Northeast.
As in the BWB, coalbed methane development in the SJB has had significant benefits for the
local and regional economy. State and local governments have enjoyed higher revenues due
to severance taxes and the region has seen increased employment as well. The State of New
Mexic9 reports, for example, that direct employment in the oil and gas industry in San Juan
County increased 67 percent, to 2,900 people in 1990 as a result of coalbed methane production
(NM Energy Dept, 1991). Moreover, the state's revenue base increased by $50 million in 1991
due to the severance and other tax payments of coalbed methane producers.
Other Basins -.,<,,..
Although the BWB and SJB are the principal coalbed methane producing regions in the United
States, there are several other coal basins with the potential to produce significant quantities of
coalbed methane. In 1992, less than 5 percent of U.S. coalbed methane was produced outside
the SJB and BWB. By 2010, however, GRI forecasts production of more than 20 percent from
the Piceance and Appalachian coal basins (GRI, 1994). .
* Piceance Basin: Coalbed methane development began in the Piceance Basin in the early
1980s, but major production was not achieved until 1989. In 1992, coalbed methane
operations in the basin, which is located in northern Colorado, produced 3.2 Bcf of
methane from 95 wells, making it the fifth largest producing region in the United States
(GRI, 1993). Like the Appalachian Basin, production from the Piceance Basin is expected
to increase significantly in coming years, perhaps reaching 35 Bcf in 2000 and 130 Bcf
in 2010 (GRI, 1994).
• Appalachian Basin: The Appalachian region, particularly the Central Appalachian coal
basin, is the third largest coalbed methane producing region in the United States, after
the SJB and the BWB.' Approximately 10.5 Bcf of methane was produced in the Central
Appalachian Basin, primarily at a mine degasification project operated by Consolidation
Coal Co. By year-end 1992, 369 coalbed methane wells had been drilled in the Central
Appalachian coal basin, and 22 in the Northern Appalachian Basin, of which 293 were
producing (GRI, 1993). Several additional wells are expected to be drilled in 1993. GRI
forecasts that production from non-mining areas in the Appalachian Basin will increase
significantly in the future, reaching 54 Bcf in 2000 and 211 Bcf in 2010 (GRI, 1994).
3.2 Methane Recovery at Coal Mines
In underground mines, methane poses a serious safety hazard for miners because it is explosive
even in low concentrations. By law, methane concentrations may not exceed one percent in
mine working areas and two percent in all other locations. In some underground mines, methane
emissions can be controlled using ventilation systems alone. In particularly gassy mines,
however, the ventilation system must.be supplemented with at least one other degasification
system. Degasification systems reduce the quantity of methane in the working areas by
recovering gas before, during or after mining, depending on mining needs. In 1988, emissions
from degasification systems were estimated to account for one-fourth to nearly one-half of the
total methane emissions from underground mining (USEPA, 1993a).
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While degasification systems are currently used primarily for economic and safety reasons to
ensure that methane concentrations remain below acceptable levels, these systems can recover
methane that can be used 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 BTU/cf (British
Thermal Units per cubic foot), while a mixture of 50 percent methane and 50 percent air has a
heating value of approximately 500 BTU/cf. Degasification methods include vertical wells, gob
well, and horizontal and cross-measure boreholes. The preferred recovery method will depend,
in part, on how the methane will be used. In some cases, an integrated approach using a
combination of one or more of these methods will lead to the highest recovery of methane. The
key features of the methane recovery methods are summarized in Table 1 and are also depicted
in Figure 6. . •-.-. , ->.-•.
.: ':JS::'H?S:S:: • A:?-:.:- •: A; i;? K.-':iX "*?£ *i.iv J.'r'ij.y:' .V: .'S.i. iv.i :£ ;XA'':. ::- 5i;':.: ':'. :£&i, K..'i: 5J-'. :* <* yS"V i .::';'A:'::/::i*;:?'":??::j^:SS'!:: H'S'*"^*' ':" -''V^— ::^^
Jl ?i;J:yp;Sunimairy of Methods for Recovering Methane from U
Method
Vertical Wells
Gob Wells
Horizontal
Boreholes
Cross-
measure
'Boreholes
Description
Drilled from surface
to coal seam
several 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.
Drilled from inside
the mine to degasify
surrounding rock
strata.
Methane Quality
Recovers nearly
pure methane.
Recovers methane
that is sometimes
contaminated with
mine air.
Recovers nearly
pure methane. .
Recovers methane
that is sometimes
contaminated with
mine air.
Recovery
Efficiency0
up to 70%
up to 50%
up to 20%
up to 20%
Current Use in
U.S. Coal Mines
Used by at least 3
U.S. mining
companies in
about 10 mines.
Used by over 30
mines.
Used by over 10
mines.
Not widely used in
the U.S.
Sources: USEPA 1990; USEPA 1991; Northwest Fuel 1990.
a Percent of methane recovered that would otherwise be emitted.
EPA estimates that more than 30 U.S. coal mines currently produce" methane from mine
degasification systems, as shown in Table 2. Of these mines, 11 are collecting and selling the
recovered methane to pipelines. In 1992, the methane recovered by these mines represented
slightly less than 5 percent of total coalbed methane-production in the United States. These
mines used a variety of technologies for methane recovery, including in-mine drilling, gob
recovery, and vertical drilling in advance of mining. In addition to the gas production benefits,
the.. projects., also significantly^, improved coal mine safety and productivity and reduced
greenhouse gases to the atmosphere. '
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Methods for Recovering Methane from Underground Cba! Mines
Vertical Gob Well
Vertical Degaslflcatlon Well
Cross Measure and
Horizontal Boreholes
Surface Equipment
Table 2 also indicates that at least 20 other mines are recovering methane from mine
degasification systems but venting it to the atmosphere. Most of these mines are located in the
Appalachian region, in the states of Pennsylvania and West Virginia, although there are some
located in Illinois and the Western United States (USEPA, 1993a).'There are a number of reasons
why these mines have, not developed methane utilization projects, including uncertain "ownership,
emphasis within the company on coal production, and the difficulty of finding uses for methane
that may not-be pipeline quality. Encouraging these mines to use the gas they are currently
wasting would significantly reduce greenhouse gas emissions and could transform as much as
55 Bcf of methane from a waste product into a fuel source.
11
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Table 2 '
Methane Recovery at Selected U.S^ Underground Mines1
Mine Name.
Amonate No.31
"ArchNo.37
Arkwright -
Bailey
Baker
Bear Ridge No 1
Big Creek No.1
Big Creek No.2 '
Birchfield No.1
Blacksville No'.1
Blacksville No.2
Blue Creek No.3
Blue Creek No.4
Blue Creek No.5
Blue Creek No. 7
Brushy Creek
Buchanan No.1
Bullitt
Cambria
Chetopa
Cumberland Mine
Deserado
Dilworth
Dutch Creek M & B
Eagle No.2
_ Eagle No. 5 & 6
Emerald No.1
Federal No.2
Galatia No.56
Gary No.50'
Gateway
Golden Eagle
Green River No:9
Greenwich No.2
Grove
Hansford No. 4
Homer City
Humphrey No. 7
Ireland
Loveridge No. 22
Maple Meadow No.1
Maple Creek
1 The mines on this
systems.
Degas Utilize
System? Methane?
X
X
X
,._...
X
X
X X
X X
X X
X X
X X
X
X
x
X
X
x J
X
X
X
Mine Name Deqas Utilize
System? Methane?
Marion
Mary Lee No. 1
Mathies Mine
McClure No.1 • •'
McElroy
Meigs No.2
Meigs No.31
Mettiki " '
Mine 34 . '
Monterey No.2 "
North River No. 1
Oak Grove Mine X * X
Old Ben No.21
Old Ben No.24 '
Old Ben No.25 X
Old Ben No.26 X
Orchard Valley
Orient No.6
Osage No.3 X
Ovenfork - •
Pattiki
Peabody No. 10
Pontiki No.2
Pontiki No.1
Powhatan No.4
Rend Lake -
Robinson Run No.95 X
Sentinel
Shawnee X
Shoemaker
Soldier Canyon . X X
Southfield
Sunnyside No.1
Urling No.1
VP (Pocahontas) No.1 X X
VP (Pocahontas) No.3 X X
VP (Pocahontas) No.5 X X
VP (Pocahontas) No.6 X X
Wabash
Wheatcroft No.9 X
William Station No.9
Wolf Creek No.4
list emitted at least. 0.1 million cubic feet per day from their ventilation
12
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4. Coalbed Methane in the Appalachian Basin
The Appalachian coal basin includes the key coal producing states of Ohio, Pennsylvania,
Virginia and West Virginia, and in 1988, this region produced 400 million tons of coal (more than
40 percent of total U.S. coal production). Much of this production came from underground
mining of coals of high gas contents. While the Appalachian region is the oldest coal mining
area in the United States, coalbed methane development has lagged behind other regions,
primarily due to institutional barriers. Coal mining has been one of the most important industries
in the region and the strong energy base has attracted many industries. The region's substantial
gas resources are largely underdeveloped, however. This is particularly true for coalbed
methane, a resource which has historically been perceived as a safety hazard in underground
mining and has routinely been vented to the atmosphere by mining operations.
4.1 Production Potential
Recent investigations by GRI, EPA, and others indicate that the potential for profitable coalbed
methane production in the Appalachian region is large. There are technically and economically
feasible project opportunities to produce coalbed methane both in non-mining areas and at many
of the region's coal mines.
GRI estimates that the region's coalbed methane resources are roughly 66 Tcf, of which
approximately 13 Tcf are considered recoverable reserves (GRI, 1988a and 1988b). These
reserves are divided between the Northern and the Central Appalachian coal basins. While many
of the geologic characteristics of the basins are similar, there are some key differences that
distinguish them geologically. In particular, coals in the Northern basin are not buried as deeply
as Central Appalachian coals and tend to have lower gas contents and lower permeability. GRI
estimates that the coalbed methane resources of the Northern Appalachian Basin are 61 Tcf and
.that the Central Appalachian Basin has 5 Tcf of coalbed methane (GRI, 1988a and 1988b). ''
In many respects, coalbed methane production conditions in the Northern and Central
Appalachian Basins resemble those of the Black Warrior Basin of Alabama. Thus, some areas
of the Appalachian region could have similarly successful development programs. As shown in
Table 3, this may be particularly true for-the Central Appalachian coal basin.
While there is substantial production potential, coalbed methane development has been limited
in the Appalachian region and most efforts have focused on degasifying coal mines for safety
reasons. A few limited projects have been undertaken, including a project in Wetzel County,
West Virginia, which operated between 1931 and 1963 and produced approximately 2.3 Bcf from
the coal (Hobbs, 1990). During the 1970s and 1980s, the small projects that were undertaken
had limited success because of technical problems related to completion methods, stimulation
practices, gas production, and poor reservoir engineering. These technical problems have been
successfully addressed in other coal basins and should not pose significant problems for future
coalbed methane development in the region.
In the last few years, coal companies and coalbed methane developers have begun to pursue
a few coalbed methane projects in the Appalachian region. Currently,, the largest Appalachian
project is being undertaken by Consolidation Coal Company, at its Buchanan mine and four
Virginia Pocahontas mines recently acquired from Island Creek Coal Corp. Other projects are
being developed by O'Brien Methane Production Inc., BTI Energy Inc., Equitable Resource
Exploration Co., and the U.S. Department of Energy with the College of West Virginia (GRI, 1993)r
13
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Tables
Coalbed Methane Characteristics of the Appalachian and Black Warrior Basins
Basis of Comparison
Gas Content (SCF/ton)
Permeability (md)
Sorption Time (days)
Coal Rank
Gas in Place (TCP)
.Stratigraphic Position
Target Depth (ft)' .
Hydrostatic Gradient (psi/ft)
Black Warrior
300-500
2-30
3-5
Medium &
High-vol
Bituminous
20
Pottsville
450-4,000
0.35-0.43
Central Appalachia
Similar (205-660)
Similar (5-27)
Similar (1-3)
Low &
Medium-vol
Bituminous
5
Pottsville
: 1,500-2,500
0.35-0.43
Northern Appalachia
Lower (100-400)
Lower (0.1-26)
Slower (60-600)
High-vol
Bituminous
61
Above Pottsville
800-1,200
0.18-0.30
Source: GRI, 1991 ,
In addition, as discussed previously, several coal mines have implemented mine degasification
projects in order to mine their coal safely, but only the five Consol mines in Virginia are selling
the methane they recover. The other mine projects focus solely on mine degasification and the
methane recovered is released to the atmosphere. '
;^
^:^^
'
Year Scenario 1
Scenario 2
4.2 Production Scenarios
For the Appalachian region, GRI forecasts coalbed
methane production levels of 54 Bcf in 2000 and
211 Bcf in 2010 from stand-alone operations in non-
mining areas (GRI, 1994). In addition, ,U;S. EPA
estimates that U.S. coal mines will be able to cost-
effectively reduce the methane emissions
associated with mining by 35 Bcf in 2000 and 60
Bcf in 2010 (USEPA, 1993b).
By combining the GRI and EPA-forecasts, two
coalbed methane production scenarios for the
period 1990-2010 have been developed (see Table
4). Scenario 1 is-simply GRI's base case, and it
does not include any recovery of methane from ...,..-.
Appalachian coal mines. In Scenario 2, the production of coalbed methane in conjunction with
coal mining is included, based on EPA's estimate of profitable recovery options in the
Appalachian region. The recovery of methane from coal mining increases basin-wide coalbed
methane production by 60 percent in 2000 and 30 percent in 2010. ' -
1990
2000
2010
55
210
90
270
-------
5. Uses of Coalbed Methane in Appalachia
There are many attractive uses for coalbed methane in the Appalachian region. Coalbed
methane is almost identical to natural gas, and it can be used as a fuel for many processes. The
coalbed methane produced from non-mining areas in the Appalachian region will be high-quality,
suitable for injection into local pipelines with a minimal amount of processing. Some of the gas
produced by mining operations may also meet these standards, although some mine gas may
be of lower heating value as a result of contamination with mine ventilation air. Table 5
summarizes the potential uses for coalbed methane produced by coal mines. The most feasible
utilization "options for coalbed methane produced by coal mines will depend on site-specific
characteristics, such as gas quality and quantity, as well as local market conditions.
ttf:IW^
/.;:::::;-; :.;;;:;:;::: ;^
Recovery Method
Vertical Degas Wells '
Gob Wells
In-Mine Boreholes
Ventilation Air
Range of BTU
Quality
(BTU/cf)
> 950
300 to 950
Up to 950
10 to 20
Utilization Options
Pipeline Injection
. Power Generation
Pipeline Injection (requires (1) maintaining
pipeline quality or (2) gas enrichment)
Power Generation
Pipeline Injection
Power Generation
Use as combustion air in coal-fired boiler or
gas turbine (needs technical demonstration)
Source: USEPA, 1990 and USEPA, 1991.
This section briefly describes the potential uses of coalbed methane produced by coal mines in:
the Appalachian region, which include pipeline injection, power generation, direct industrial use,
and some less conventional -uses such as for transportation fuel or as a chemical feedstock.
5.1 Pipeline injection
The key issues affecting coalbed methane sale to.pipelines 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. All coalbed methane
requires processing to remove water, sand and other impurities. Some coalbed methane
produced by coal mines may be contaminated with air and may also require enrichment to
remove nitrogen, a.process that is not economic at prevailing gas prices. Project profitability will
depend on a number of factors, including the amount and quality of the methane recovered, and
the capital and operating costs.for wells, water disposal, compression and gathering systems.
15
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In the Appalachian region, one of the key issues affecting the development of projects to sell
coalbed methane to pipelines is likely to be the cost of constructing necessary gathering and
transmission systems. Although there are numerous pipelines in the region, the capacity of most
is constrained, particularly during peak winter demand periods. Thus, it may be difficult for
coalbed methane'producers to find firm gas buyers, or they may be required to construct long
gathering lines to transport their gas to a pipeline that will purchase the gas. Five Virginia coal
mines, for example, constructed a $100-million, 40-mile gathering line to move their coalbed
methane to market.
Exploiting opportunities for coal mines to sell their methane to gas transmission companies may
require investigation of pipeline capacity and gas storage conditions in different parts of the
region. Depending upon the outcome of these analyses, it may be necessary to promote the
development of storage capacity, the expansion of pipelines in the region, and other actions to
encourage methane recovery at mines. In some cases, it may also be necessary to upgrade the
quality of the recovered methane through nitrogen rejection prior to marketing. Appropriate, cost-
effective technologies for gas enrichment may need to be demonstrated at coal mines in order
to commercialize this approach.
5.2 Power Generation
Coalbed methane is an attractive fuel for power generation,.even when it is contaminated with
mine ventilation air. Gas turbines can generate power from methane with a heating value of only
350 Btu/cf, and in quantities similar to those recovered by mining operations. The power can
then be used for on-site purposes or sold to a nearby utility. On-site use may be a particularly
attractive option because coal mines use large amounts of power to run ventilation fans,
conveyor belts, transportation systems and other equipment.
In the Appalachian region, power generation projects have been constrained for several reasons.
Many utilities in the region have an over-supply of electricity and do not need new power
suppliers. As a result, they offer very low buyback prices to power producers and are unwilling
to purchase power from small power producers, like coal mines. One option for avoiding this
situation is for the local utility to "wheel" or transmit the electricity generated at the coal mine to
another utility with an interest in buying it. These projects may be constrained by limited
transmission capacity, however, and by the unwillingness of local utilities to cooperate in such
deals. Another option is for the coal mine to use the power on-site to meet its own energy
needs. Even this option may be discouraged by utilities that are reluctant to lose their largest
customers, however.
Overcoming the barriers to power generation will require dedicated efforts to publicize the many
benefits of methane recovery and utilization. Electric utilities and their,regulators must be
informed about the potential for using the methane recovered by coal mines to generate power
and the-many economic and environmental benefits associated with such projects. In addition,
the relationship between methane recovery projects at coal mines and the objectives of electric
utilities to reduce their emissions of greenhouse gases and acid rain precursors should be
explicitly determined and publicized.
Many utilities, for example, are interested in developing projects that can reduce emissions of
greenhouse gases. Under the Climate Change Action Plan, DOE is implementing a voluntary
program for electric utilities-called' Climate Challenge-in which utilities commit to develop
programs to reduce greenhouse gas emissions (CCAP,'1993). As a result of the Climate
16
-------
Challenge program, many utilities should become increasingly interested in opportunities to
reduce methane emissions at coal mines. Projects could be undertaken by utilities with coal
mines in their service territories or with more distant mines that supply their coal.
A second environmental benefit for electric utilities is the possibility that methane recovery
projects could contribute to lower emissions of sulfur dioxide and nitrogen oxides, as required
under the Clean Air Act Amendments of 1990. One option, for example, could be for the utility
to cofire coalbed methane recovered by a coal mine in a coal boiler. Generally, cofiring requires
injection of gas to produce 10 to 15 percent of the boiler's energy and reduces emissions by a
similar percentage. To date, several experiments have demonstrated the economic and technical
feasibility of cofiring with natural gas. Coalbed methane has not been used as a fuel, but should
be operationally indistinguishable from conventional natural gas in this application. If coal
companies can also provide the coalbed methane for co-firing projects, these projects will have
the added benefit, from the coal industry's perspective, of avoiding the loss of a market-share
to natural gas producers.
5.3 Direct Industrial Use
Coalbed methane could be used like natural gas in a variety of direct applications. It may be
possible to use mine gas as a fuel for coal preparation plants or coal drying facilities. Other
possibilities include its use as a chemical feedstock or compressing it for use as a vehicle fuel!
There may also be local industries that use natural gas as fuel which could use available coalbed
methane from nearby mines. These types of opportunities are likely to be site-specific; identifying
and developing them will require close examination of particular locations to determine'fuel
availability and the technical and economic feasibility of various use options.
6. The Benefits of Appalachian Coalbed Methane Development
The development of the Appalachian region's coalbed methane resources will have significant
economic benefits for the region, including the creation of jobs in gas production, infrastructure
development, and. indirect support services, and the generation of revenue for state and local
economies. Other states where extensive coalbed methane development has occurred-notably
Alabama and New Mexico-have evaluated the economic impacts and documented substantial
benefits, in terms of direct and indirect employment and revenue generation. • The states of the
Appalachian Basin would be expected to realize similar benefits.
This study presents the first attempt to quantify the benefits of coalbed methane development
for the Appalachian region. Several economic benefits, including job creation and increased
state revenues, are assessed for the key states of the Appalachian region. In addition, the
environmental benefits, associated with the development of projects at coal mines are quantified
and the potential for coalbed methane development to contribute to the U.S. goal of stabilizing
greenhouse gas emissions in 2000 at 1990 levels is determined.
6.1 Methodology
Coalbed methane production and the associated economic benefits were estimated by state for
the key coal producing states in the Appalachian region. In estimating the benefits, it was
17
-------
necessary to make certain assumptions about the distribution of production among states,
employment requirements for various production technologies, and state tax and revenue
policies. The principal assumptions are discussed below.
State impacts. Regional coalbed methane production for the two scenarios was apportioned
among states based on their forecasted shares of regional underground coal production (USEIA,
1994). The estimates are shown in Table 6. While coal production is not a perfect predictor of
coalbed methane production, it is likely that coalbed methane production wil! be greater in states
with larger coal reserves and more developed energy producing industries.
:::::-:'::-:.':'.- :"::- -o':.;o:.:o'o'::c'":.:''"'.:i"::':i::?:V;-:-::::'.^:":'-':'-;-::.;;:';-- '— .:''-;Vv':>;V>;"*T>:O*:'.-.':-::::' ? -ft :*'':
! '••'. ••'.'• ;V::1:;:":-r':',;:i'-'::;:':';;1':'!;:V;':'!":'::':-:''V::'::: :"''::"'-Tahlo'''fi:-::-'-1:.v:-'':- -•"•'-•.: o::' :'": .'•'•:•:'•': * :' : '-:'.--.';•- :-.:'::.:'--
'iSVi^K;.;.;^^^
N;W^Cbalb^;:M^harie:Pr^
;;lfi^
State
Ohio
Pennsylvania
Virginia
West Virginia
TOTAL
Scenario
J.
2000 2010
4
11
7
33
55
21
61
12
116
210
Scenario 2
2000
6
17
12
55
90
2010
"25
80
15
150
270
Recovery Technologies, Coalbed
methane can be produced using vertical
wells drilled from the surface or in-mine
boreholes. Because employment
requirements vary depending on which
technology is used, it was necessary to
apportion production among these
recovery technologies. In this analysis, it
was assumed that 10 percent of the
methane recovered by active coal mines
would be recovered using .in-mine
horizontal boreholes and that the
remaining 90 percent would be produced
using surface wells (either gob or vertical
pre-drainage). All of the.coalbed methane
produced in non-mining areas was
assumed to result from vertical wells.
Employment Estimates. Direct employment requirements were estimated based on information
collected about the number of people currently employed in various coalbed methane production
activities. Indirect employment was assumed to be twice direct employment. The assumed
employment requirements are summarized below:
• Vertical Well Development: It was assumed that approximately 20 people per Bcf of gas
would be required directly over a two year period for coalbed methane produced from
vertical wells. This figure was applied to the amount of gas assumed to be "in
development", which was calculated as the difference between production in the current
year and forecast production two years later. These jobs are associated with site
preparation, drilling, completing, permitting, etc.
• Vertical Well Production: Once the vertical wells enter a period of stable gas production,
the direct employment requirements drop significantly. It was estimated that only 6
people would be employed per Bcf of coalbed methane produced from vertical wells in
any given year. This figure was applied to current year production to estimate
employment requirements. These jobs are associated with gas production, water
disposal and treatment, and ongoing site maintenance requirements.
* In-Mine Methane Recovery: For in-mine methane recovery, a direct employment rate of
20 people per Bcf was assumed, based on information provided by coal companies.
These jobs are associated with the drilling of in-mine boreholes, construction and
• maintenance of in-mine pipelines and surface facilities, etc. At active coa! mines it was
18
-------
assumed that vertical well employment requirements would be the same as at non-mining
operations.
Revenue Estimates. State revenues were estimated using current state gas prices and existing
state revenue and taxation policies, as summarized in Table 7. . This methodology likely
underestimates revenues because in the future states may increase their tax rates or natural gas
prices may rise, both of which would cause the associated state revenues to be higher..' .In
addition, only revenues from the severance taxes were estimated, whereas coalbed methane
producers may also pay property, school and other types of taxes.
mimSii
State
Ohio
Pennsylvania
Virginia
West Virginia .
sliHtSilSM
:;£ i^t^^Reycque^P
Type of tax
Severance
None
Local Severance
Severance
oftcies m ;;; : ; &$$i f 1
Tax Rate
Gas: $0.03/mcf of gas
produced
Not Applicable
Gas: 3 percent of
gross revenue
Gas: 5 percent of
gross revenue
6.2 Employment Benefits
Coalbed methane production in the Appalachian region could directly create up to 1,000 jobs
in 2000 and 2,500 jobs in 2010. Taking indirect employment benefits into account would result
in as many as 2,000 more jobs created in 2000 and 5,000 in 2010. Thus, the Appalachian region
could enjoy an employment increase of roughly 3,000 jobs in 2000 and 7,500 jobs in 2010; as
summarized in Table 8. It is likely that most of these jobs would be located in the states of
Pennsylvania and West Virginia, where the greatest coalbed methane development is expected.
If coalbed methane is aggressively developed in conjunction with mining, along the pathway
outlined in Scenario 2, the employment benefits to mining companies could be quite large. In
2000, more than 250 additional people could be directly employed by mining companies.
Including indirect labor, total employment associated with mining projects could reach almost 800
in 2000. For comparison, a large underground Appalachian coal mine may employ 250-500
people.
Comparing.the overall employment estimates to those prepared by other states indicates that this
analysis is conservative. The University of Alabama, for example, has estimated that by 1997,
6,700 jobs would be associated with the production of 109 Bcf of coalbed methane (UAL, 1989).
New Mexico, moreover, estimated additional direct employment of 1,000 people in San Juan
County alone, associated with the production of .131 Bcf of coalbed methane in 1990 (NM Energy
Dept, 1991).
19
-------
P <1f:|;?*!^
Estimated Employment Associated with
gftip^
State
Ohio
Pennsylvania
Virginia .
West Virginia
TOTAL
Scenario 1 Scenario 2
2000 2010 2000 2010
150 645 185 720
400 1,865 525 2,295
255 365 370 435
1,200 3,545 1,700 4,315
2,000 6,420 2,780 7,765
6.3 Revenue Benefits
In addition to employment benefits, coalbed methane production in the Appalachian region is
estimated to generate state revenues of more than $6 million in 2000 and $20 to $25 million in
2010, as shown in Table 9. These funds could be used by state and local governments for a
wide range of purposes, and they are comparable to those realized by other states that have
encouraged the development of coalbed methane resources. In New Mexico, for example,
revenues increased by $50 million in 1990, and in Alabama, 1990 state revenues associated with
coalbed methane were conservatively estimated to be $2-3 million.
:.-.'.'.-:.::":.:: : .': ::';::-.-V-.-. •": :. "
''•^•''^-'•f'^Vv"'^-'-^
i:'U;'t^v::-^VjVjv-
:- V ..• -• .- :- - : .... -•-- . ..:•
^;:.;-;;Table::9H:."
::'>::^/^'x'x:?K:v;'::;-'-':'::':?
"'••'-' •!>"-•!>,;'> ;;::- X'. ':~':--'. -
;•• -••' ':•_ *',- "-,,".- ':';]"
r;':••.••
wfthV
Y-: ::::••:•:_•"',.,
g|:p;!^^
State
Ohio
Pennsylvania
Virginia
West Virginia
TOTAL
Scenario 1
2000 2010
0.1 0.6
NA . NA
0.4 1.1
3.3 17.4
3.8 19.1
Scenario 2
2000
0.2
NA
0.7
5.5
6.4
2010
0.8
NA
1.4
22.5
24.6
20
-------
6.4 Environmental. Benefits
The environmental benefits of encouraging the development of the Appalachian region's coalbed
methane reserves will be significant.. In particular, encouraging such .development would
contribute to the reduction of methane emissions associated with coal mining. Since methane
is a potent greenhouse gas, emission reductions will help mitigate global warming. In addition,
methane contributes to other environmental problems, such as tropospheric ozone formation and
potentially stratospheric ozone depletion.
If all of the Appalachian region's profitable reductions are made in 2000, methane emissions from
underground coal mining could be reduced by 15 to 25 percent, and U.S. methane emissions
from coal mining by. 10 to 20 percent (USEPA, 1993b). These reductions would be equivalent
to 2 to 4 million tons of carbon. For comparison, these reductions represent the amount of CO2
emitted by 1 to 2 million cars. Similarly, in 2010, the emission reductions would represent 30 to
40, percent of the region's underground mining emissions and 1.5 to 25. percent of U.S. emissions
from underground coal mining. Achieving comparable greenhouse gas emissions through
transportation changes would require displacing 2 to 4 million cars.
In addition, these reductions would represent approximately 15 percent of the methane
reductions and about 3 percent of the total emission reductions needed in the United States to
stabilize greenhouse gas emissions in the year 2000 at 1990 levels, as called for in the
President's Climate Change Action Plan (CCAP, 1993).
7. Encouraging Coalbed Methane Development
Coalbed methane development has not yet occurred widely in the Appalachian region because
of legal, regulatory and other barriers. To the extent that it is in the region's interest, however,
the state or Federal government should consider addressing the barriers and encouraging
coalbed methane development. The importance of coalbed methane recovery projects to the
President's Climate Change Action Plan, for example, should provide an impetus to all involved
parties-including Federal and state agencies, the coal industry, pipeline companies, electric
utilities, and others-to identify the barriers constraining project development and develop plans
to remove them. Some possible areas for action are outlined below.
7.1 Address the 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
Federal and certain state legal systems has discouraged investment in coalbed methane projects
because of uncertainties as to which parties may demand compensation for development of the
resource. Over the last decade, coalbed methane forums have identified ownership as a serious
obstacle to methane recovery, particularly in the Appalachian region (Lewin, 1992).
Two Appalachian states-Virginia and West Virginia-have enacted legislative mechanisms for
addressing ownership issues. Virginia passed its legislation in 1990, and it has resulted in the
rapid development of coalbed methane projects in the State. Since passage of the legislation,
more than 300 coalbed methane wells have been drilled.and several coal mines have developed
methane recovery projects (GRI, 1993).
21
-------
The Virginia legislation provides mechanisms that allow for coalbed methane projects to proceed
in.instances when ownership is unclear or contested. In such situations, the Virginia Gas and
Oil Board may enact "forced pooling" of all potential interests in the coalbed methane. Until such
time as ownership is decided, payment of costs or proceeds attributable to the conflicting
interests are deposited in an escrow account (Lewin, 1992). This legislation is important as
development of coalbed methane need no longer wait for final determination of all of the owners
of the gas rights, a determination that could take many years. Following Virginia's example, West
Virginia enacted similar legislation in March 1994 (Streit, 1994).
The U.S. Congress has also enacted legislation to address ownership issues in those states
without mechanisms for allowing coalbed methane development. This legislation-Section 1339
of the 1992 Energy Policy Act-requires the Department of Interior's Bureau of Land Management
to develop a list of states that have significant coalbed methane resources and no mechanism
for addressing uncertain ownership. These "affected states" can either develop state-level.
legislation, as West Virginia has done, or become subject to Federal regulations concerning
ownership, which will take effect in October 1995. The Federal provisions are quite similar to the
Virginia law and mandate forced pooling.
7.2 Provide a Financial Incentive for Methane Recovery at Coal Mines
In 1979, the U.S. Congress enacted the Section 29 tax credit in order to encourage the
development of unconventional gas resources, such as coalbed methane. In regions where
ownership appeared to be certain, this tax credit successfully provided a financial incentive to
companies to produce coalbed methane (Lewin, 1992). Development in the San Juan and Black
Warrior Basins provide an example of how the tax credit fostered development of coalbed
methane production, markets and pipelines. Due largely to legal ownership issues, however, the
Section 29 tax credit was not widely used in the Appalachian region. In addition, it was not
designed in a manner that effectively encouraged the recovery of methane in conjunction with
coal mining operations.
The eligibility of coalbed methane production for the Section 29 tax credit expired at the end of
1992, and gas produced from coalbed methane is only eligible for the credit if the production
wells were drilled prior to the expiration date. Section 29 was extended for certain other types
of unconventional gas production but coalbed methane is no longer eligible for the production
incentive.2 As a result, most coalbed methane development in the Appalachian Basin is
proceeding without a tax credit. If a credit similar to Section 29 were enacted, it could work
effectively to reduce the financial risk associated with initiating gas production in new coal basins.
Without some form of incentive, it is likely that commercial development of coalbed methane will
proceed more slowly in the Appalachian region.
One option for encouraging the more rapid development of coalbed methane resources in the
Appalachian Basin is to provide a production oriented incentive modelled on the Section 29 tax
credit, but targeted specifically at underdeveloped coalbed methane producing regions and at
the methane produced by coal mines. In designing such an incentive, the appropriate financial
value.must be determined and eligibility provisions established.
2 Section 29 was extended under the 1992 Energy Policy Act (Public Law 102-486} for biomass and synfuels
only.
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Determining an Appropriate Value for a Financial Incentive
If a financial incentive is offered to encourage, coalbed methane development and methane
recovery at coal mines, it must be set at an appropriate value. This determination must be made
by policy makers, taking into account the social value of encouraging coalbed methane
development and the financial cost of providing an incentive. One possible means of determining
an appropriate value would be to .set it based on the social value of reducing greenhouse gas
emissions. A tax credit of $0.57 per mcf would reflect a social value of $5 per ton of carbon
equivalent .for reducing greenhouse gas emissions. Such a credit would encourage the
additional production of 10 Bcf of methane from coal mines in 2000, and it is estimated that it
would cost the U.S. Treasury about $25 million in 2000 if targeted narrowly at coal mine emission
reduction projects.
Designing Eligibility Provisions
An incentive's eligibility provisions must be designed in a manner than ensures that the goal of
encouraging coalbed methane development is met at the lowest possible cost. If the objective
is to reduce methane emissions from coal mines, the credit must be targeted toward mining
operations. Under this approach, other types of coalbed methane production would not be
eligible for the cost-minimizing incentive. A number of options for narrowing eligibility could be
explored, including:
• Allowing the incentive (or emission reduction credit) to apply to a maximum level of
coalbed methane production per well, unless the well is recovering methane in
conjunction with coal mining (i.e., from gob wells or in-mine boreholes); or
» Allowing the incentive (or emission reduction credit) to apply only in states with less than
a minimum level of cumulative coalbed methane production unless production is in
conjunction with mining, to ensure that only production in new regions is encouraged.
In addition to these general provisions, several other options have been identified by industry as
important in an incentive designed to encourage methane recovery at coal mines:
• Third Party Sales Requirement: Under-Section 29, eligible gas production had.to be sold.
by the taxpayer to an unrelated party; coalbed methane used on-site was not eligible for
the Section 29 credit. 'Elimination of the .third-party sales requirement, or a specific
allowance .for qualified on-site uses (such as electricity generation or coal drying) would
encourage coal mines to develop uses for any methane liberations that are not
considered pipeline quality (i.e., higher than 95% methane concentration).
• Unconventional vs. Conventional Gas: Recovery of methane gas in conjunction with coal
mining involves production of methane from one or more coal seams and adjacent rock
strata. Methane produced from conventional gas bearing strata was not eligible for the
Section 29 tax credit, while coalbed methane gas was eligible for the credit. Where gob
wells are being used by mines, it can be difficult to distinguish which portion of the gas
is eligible for the credit. Given the environmental and energy interests in encouraging
methane recovery instead of venting, it would be desirable to provide the incentive to all
gas recovered by mine gob wells;'
• Alternative Minimum Tax: .In the current coal industry situation, many coal mining
operations may have net operating loss carryovers and no regular tax liability. In such
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cases, the coal company may be already at an alternative minimum tax level and find that
they cannot use a tax incentive. For methane that would otherwise be vented to the
atmosphere, it may be desirable to allow the use of the credit even in such instances.
Longer Extension Periods: In its final years, the Section 29 tax credit was extended
several times for periods of one to two years. For purposes of planning a major
investment, the short time horizon of these extensions was undesirable. Coalbed
methane development could be more effectively encouraged by providing a longer term
incentive that allowed coal mine operators and other coalbed methane developers to
include its value in their project planning.
7.3 Encourage Electric Utilities to Support Power Generation
One promising utilization option for methane recovered by coal mines is power generation.
These projects are attractive because mines have large electricity needs associated with
powering fans and other equipment. In addition, available power generation equipment can use
methane that is not pipeline quality, which is attractive to those coal .mines that are not
recovering high-quality gas.
To date, there has been no commercial development of methane-fired power generation projects
at U.S. coal mines. One of the major reasons is that many electric utilities in the Appalachian
region have excess capacity, low avoided costs, and have not supported power generation
projects at coal mines. Frequently, the coal mine is a major power customer, and the utility will
work aggressively to keep the mine from generating electricity for on-site use or for sale to
others.
Utilities have many ways of discouraging these projects. They can reduce the prices they charge
to the mine so as to undermine project economics and they can charge high prices for the back-
up power required by the mines. Utilities can also offer the mine low avoided cost payments
should the mine seek to sell excess power to the utility, and they may discourage wheeling and
the sale of power to other utilities with higher avoided cost rates. In some cases, these activities
may be explicit, but in many cases they are not. Determining that utilities are unfairly
discouraging projects can be costly and time-consuming, in addition to risking the alienation of
a current or potential coal customer.
To the'extent they seek to encourage the generation of electricity from environmentally beneficial
sources, state and Federal government agencies should encourage the use of coal mine
methane for power generation. A variety of mechanisms are available:
QF Status
The Public Utilities Regulatory Policies Act (PURPA) of 1978 guarantees a market for certain types
of small power producers and cogenerators that are considered as "Qualifying Facilities" {QFs).
According to rules implemented by the FERC, to be considered a QF and qualify for the benefits
of PURPA, a power producer must be either a cogeneration facility or a small power facility. A
cogenerator, often a commercial or industrial entity, sequentially produces steam and electricity.
A small power facility produces electricity using biomass, waste or other renewable sources, such
as hydro, solar or geothermal power, and has a power production capacity of up to 80 MW.
Utilities are required by law to purchase power from QFs and to sell back-up power to QFs at
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non-discriminatory rates. State public utility commissions set the electric power purchase rates
at the "avoided cost" of the utility.
Coal mining companies may be able to sell excess power that they generate from recovered
methane to utilities under PURPA if they qualify as QFs, which depends on whether FERC
classifies coalbed methane as "waste gas." The classification of coalbed methane has -been
questioned because of its similarity to' conventional gas. For example, under the current
definition of waste gas it is conceivable that FERC could decide that high quality coalbed
methane should be treated as conventional natural gas, which would prevent a mining operation
from achieving QF status and qualifying for the benefits of PURPA. This uncertainty about the
applicability of QF status increases project risk and imposes an additional hurdle for project
developers.
In at least one instance, however, methane recovered from a coal mine was classified as "waste
gas" by FERC. To encourage future projects, FERC should be encouraged to develop a clear
definition of waste gas that includes methane recovered from coal mining when it is
demonstrated that venting is the alternative to using the gas.
Competitive Bidding and Green RFPs
Competitive bidding is an accepted and now widely practiced alternative to avoided cost pricing
of power generated from QFs. In recent years, at least 34 states have adopted competitive
bidding systems to manage the development of new capacity from QFs and other non-regulated
power generators. Though systems vary between states, competitive bidding systems generally
select the lowest cost projects. However, non-price criteria such as dispatchability, transmission
requirements, development status, and other policy objectives can be incorporated into the bid
selection process. Non-price criteria notwithstanding, if the costs of the bidded projects exceed
the utility's avoided cost, the utility itself will build the remaining necessary capacity. In many
cases, the capacity bid is more than required, and the price arrived at is typically lower than the
utility's avoided cost.
Coalbed methane recovery projects will need to compete with other power sources in competitive
bidding systems. Although the price offered by the project may be below the utility's avoided
cost, the methane recovery project may not necessarily enter the lowest bid, and thus may not
be selected. Under bidding systems that are not restricted to QFs (allowing, for example,
neighboring utilities to also bid), price competition can be very severe. Bidding systems can be,
and in some instances have been, established to incorporate non-price, criteria, such as
environmental externalities. Such systems should be employed to ensure that environmentally
beneficial generation projects are developed.
incentive Buyback Rates
For some types of renewable energy sources, incentive buyback rates are provided to improve
project economics and encourage development. These rates do not currently extend to the use
of coalbed methane for power generation where this methane would otherwise be vented,
however. Federal and state legislatures and government agencies designing and implementing
such incentive programs should consider including this currently wasted energy source in the
programs. State energy offices and public utility commissions should also consider providing
incentives to encourage electricity projects to reduce the waste of methane by coal mining,'
particularly when other environmentally desirable projects are being encouraged using such
mechanisms.
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Examination of Utility Actions
In cases where power generation projects could be technically feasible and are not being
developed, states may want to examine the approach of local utilities to such projects. Wherever
possible, utilities should be encouraged to promote the development of competitive,
environmentally desirable projects.
7.4 Identify and Promote Direct Use Options
At some sites, it may be possible to use methane recovered by coal mines directly on-site or at
nearby industries. These opportunities will arise on a case-by-case basis and will likely be
identified through a detailed examination of conditions at particular mines. In order to encourage
the development of the full range of opportunities, state and Federal agencies should consider
supporting site-specific feasibility analyses to identify attractive uses for recovered methane. In
addition, in some cases it may be desirable to co-fund demonstration projects with the mines or
other industries to confirm the technical viability of particular options. Finally, state and Federal
agencies should be alert to any potential barriers that might constrain development of utilization
projects and, as necessary, develop programs to address major barriers.
7.5 Identify and Remove Barriers to Pipeline Sale
Several U.S. coal mines are currently recovering pipeline quality methane and selling it to
pipelines. Where methane quality is sufficient, these projects can be extremely profitable. Mines
may confront a number of barriers as they develop such projects, however, that could merit state
or Federal action.
• Pipeline Capacity. Currently, pipeline capacity in the Appalachian region is severely
limited, due to the large amount of gas being transported from major gas producing
regions in the southern U.S. to the northeastern demand centers. These constraints can
make it difficult for coalbed methane producers to gain firm access to pipelines or may
necessitate the construction of long gathering systems to move gas from coalbed
methane production areas to pipelines with capacity. Legislative measures to expedite
pipeline construction could help to address this constraint over several years. It may also
be desirable to provide incentives to support the construction of gathering systems to
move methane from coal mines to market, if the gas would otherwise be vented to the
atmosphere.
• Gas Storage. Like pipeline capacity, gas storage capacity in the Appalachian region is
limited, which can have significant economic implications for coal mine methane recovery
projects. Unlike other types of gas production, methane produced in conjunction with
coal mines cannot be stored in its formation until market conditions are favorable. This
gas is liberated as mining occurs and it can either be sold at that time or released into
the atmosphere. This requirement has economic implications for projects in that a coal
mine must sell its methane as it is available, at the prevailing gas price, rather than store
it and sell it during peak times when prices are higher. Access to gas storage could
enable the mines to market their gas during select times and earn higher prices. General
initiatives to increase storage capacity, in the Appalachian region could be expected to
benefit methane recovery projects at coal mines. In addition, it might be desirable to
investigate the feasibility of unique storage opportunities available to coal mines. In
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particular, some experts have suggested storage of methane from mines in abandoned
mines. Federal or state agencies may want to examine the technical and economic
feasibility of such approaches on a site-specific basis and, if necessary, consider
development of demonstration projects.
7.6 Develop Links to Other Climate Change Actions
As a result of the Rio Framework Convention on Climate Change and the President's Climate
Change Action* Plan, there are currently a number of initiatives underway to encourage the
voluntary reduction of greenhouse gas emissions. Several of these measures are described
below, and they may increase support for the development of methane recovery projects at coal
mines in the Appalachian region. The major climate change initiatives include:
» DOE's Climate Challenge Program. This program is being implemented as part of the
President's Climate Change Action Plan. Under it, electric utilities are making voluntary
commitments to reduce the greenhouse gas emissions associated with their operations
by the year 2000. Already, more than 50 utilities have joined the program. To the extent
that member utilities are purchasing coal from gassy coal mines or selling electricity to
coal mines, they may be interested in participating in the development of methane
recovery projects to reduce methane emissions from mining.
s
* Section 1605(b). Under the 1992 Energy Policy Act, DOE is charged with developing a
database for the voluntary reporting of projects to reduce greenhouse gas emissions.
Entities that implement emission reduction projects can submit documentation to DOE
and have the benefits of their projects recorded. In the future, these entities may receive
recognition, or perhaps some more extensive credit, for taking early actions to reduce the
risk of climate change.' DOE will be publishing the procedures for participating in the
Section 1605(b) program during 1994.
• Other Offsets Initiatives. In some cases, utilities or independent power producers have
made independent commitments to reduce the greenhouse gas emissions associated
with their power generation projects. These groups frequently seek to develop projects
that will reduce greenhouse gas emissions enough to "offset" the emissions from their
existing or new power projects. Low-cost, or profitable, emission reduction projects are
the strongest candidates for offset projects, and coal mine methane recovery projects
could be particularly attractive, because of their technical and economic feasibility.
Utilities participating in the Climate Challenge program and other groups interested in developing
offset projects, should be informed about the potential to cost-effectively reduce methane
emissions from coal mines. These projects can be extremely attractive because of the potency
of methane as-a greenhouse gas;- each kilogram of methane recovered is equivalent to
recovering about 20 kilograms of carbon dioxide. In addition, because recovered methane can
be used as fuel, these projects can frequently have attractive economics. State and Federal
agencies should prepare information on these types of projects and disseminate it widely to
relevant industry and utility groups.
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7.7 Foster Appropriate State and Federal Regulatory Frameworks
A final critical issue is to ensure that state and Federal regulatory frameworks encourage the
development of environmentally desirable methane recovery projects at coal mines. Such issues
as permitting requirements and the Viability of methane recovery projects under relevant state or
Federal regulations should be determined. In addition to environmental regulations, moreover,
other technical regulations (such as those related to gas production or mining operations) should
be evaluated. In examining regulatory frameworks, it is essential to ensure that encouraging the
methane recovery projects does not jeopardize the overarching objective of the existing
regulations. To the extent that coalbed methane recovery projects are consistent with the
objectives of the existing regulations, however, state and Federal agencies should seek to
minimize regulatory burdens on these new projects.
In states without extensive coalbed methane recovery, it may be desirable to investigate the
adequacy and applicability of existing regulations and modify them as appropriate to ensure the
safe, environmentally beneficial, and effective production of coalbed methane at coal mines. The
coalbed methane industry has cooperated with regulators in states such as Alabama and New
.Mexico to facilitate the rapid development of appropriate regulatory frameworks. Such activities
may serve as a model for Appalachian state initiatives to expedite coalbed methane development.
To the extent that regulatory barriers are found to constrain the development of coalbed methane
projects at mines, industry should bring these to the attention of relevant state or Federal
agencies and appropriate mechanisms for addressing the barriers should be developed.
8. Summary and Conclusions
The Appalachian region will benefit significantly from coalbed methane development. Thousands
of jobs will be created and states will receive millions of additional dollars in tax revenue. In
addition, emissions of methane, a potent greenhouse gas, will be reduced, which will help the
United States to meet its goal of stabilizing greenhouse gas emissions.
Projects will not be developed unless states and the Federal government take action to address
the barriers to coalbed methane development in the Appalachian region, however. Coalbed
methane is a new resource, one which was previously considered only a safety hazard in coal
mines. Historically, coalbed methane has been viewed as more of a nuisance than a resource
and has been wasted through venting to the atmosphere in conjunction with coal mining. These
practices will not change unless the legal, regulatory and institutional frameworks that have
encouraged such actions are changed. Although many projects are economically and technically
viable, coal mine methane recovery projects can be constrained by barriers ranging from
uncertain resource ownership to the unwillingness of potential customers (such as pipelines and
electric utilities) to purchase the energy for a fair price.
> *••
This study has quantified the benefits associated with coalbed methane development for the
Appalachian region and has outlined both the major barriers and possible options for addressing
them. The next steps are up to the relevant state and Federal government agencies and the
industries involved. These groups have an opportunity to promote the cost-effective reduction
of methane emissions and to ensure that the economically and environmentally beneficial
development of this large gas resource proceeds rapidly in the Appalachian region.
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